[Federal Register Volume 87, Number 68 (Friday, April 8, 2022)]
[Rules and Regulations]
[Pages 20940-20992]
[FR Doc No: 2022-07133]

Vol. 87

Friday,

No. 68

April 8, 2022

Part II

Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Parts 192 and 195

Pipeline Safety: Requirement of Valve Installation and Minimum Rupture
Detection Standards; Final Rule

Federal Register / Vol. 87 , No. 68 / Friday, April 8, 2022 / Rules
and Regulations

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Parts 192 and 195

[Docket No. PHMSA-2013-0255; Amdt. Nos. 192-130; 195-105]
RIN 2137-AF06

Pipeline Safety: Requirement of Valve Installation and Minimum
Rupture Detection Standards

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA),
DOT.

ACTION: Final rule.

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SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations
applicable to most newly constructed and entirely replaced onshore gas
transmission, Type A gas gathering, and hazardous liquid pipelines with
diameters of 6 inches or greater. In the revised regulations, PHMSA
requires operators of these lines to install rupture-mitigation valves
(i.e., remote-control or automatic shut-off valves) or alternative
equivalent technologies, and establishes minimum performance standards
for those valves' operation to prevent or mitigate the public safety
and environmental consequences of pipeline ruptures. This final rule
establishes requirements for rupture-mitigation valve spacing,
maintenance and inspection, and risk analysis. The final rule also
requires operators of gas and hazardous liquid pipelines to contact 9-
1-1 emergency call centers immediately upon notification of a potential
rupture and conduct post-rupture investigations and reviews. Operators
must also incorporate lessons learned from such investigations and
reviews into operators' personnel training and qualifications programs,
and in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications. PHMSA is promulgating
these regulations in response to congressional directives following
major pipeline incidents where there were significant environmental
consequences or losses of human life. The revisions are intended to
achieve better rupture identification, response, and mitigation of
safety, greenhouse gas, and environmental justice impacts.

DATES: The effective date of this final rule is October 5, 2022.

FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney,
Senior Technical Advisor, by telephone at<PHONE_NUMBER>. General
information: Robert Jagger, Senior Transportation Specialist, by
telephone at<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action
    C. Costs and Benefits
II. Background
    A. Pipeline Ruptures
    B. National Transportation Safety Board Recommendations
    C. Advance Notices of Proposed Rulemaking
    D. 2011 Pipeline Safety Act and Related Studies
    i. Section 4--Automatic and Remote-Controlled Shut-Off Valves
    a. GAO Report GAO-13-168
    b. Studies for the Requirements of Automatic and Remotely
Controlled Shutoff Valves and Hazardous Liquids and Natural Gas
Pipelines With Respect to Public and Environmental Safety
    ii. Section 8--Leak Detection
    E. 2020 Valve Rule NPRM
    F. Subsequent Legislative Deadlines; Recent Executive Orders and
Actions
III. NPRM Comments, Pipeline Advisory Committee Recommendations, and
PHMSA Responses
    A. General Comments, Scope, Applicability, and Cost-Benefit
Issues
    B. Rupture Definition
    C. Rupture Identification Definition and Timeframe
    D. RMV Installation, RMV Closure Timeframe
    E. Valve Spacing & Location
    F. Valve Status Monitoring
    G. Class Location Changes
    H. Valve Maintenance
    I. Failure Investigations
    J. 9-1-1 Notification Requirements
    K. Other
IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for
Gas Pipelines
V. Section-by-Section Analysis of Changes to 49 CFR Part 195 for
Hazardous Liquid Pipelines
VI. Regulatory Analyses and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

    This final rule is the culmination of a decade-long PHMSA
rulemaking effort responding to congressional mandates, National
Transportation Safety Board (NTSB) recommendations, and Government
Accountability Office (GAO) recommendations to revise the Federal
Pipeline Safety Regulations at 49 Code of Federal Regulations (CFR)
parts 192 and 195 to prevent the catastrophic loss of life, property
damage, and environmental harm experienced from ruptures on large-
diameter hazardous liquid and natural gas pipelines, such as those that
occurred near Marshall, MI, and San Bruno, CA, in 2010.
    This final rule codifies a suite of design and performance
standards prescribing the installation, operation, and spacing of
rupture-mitigation valves (RMV) or alternative equivalent technologies
on most new or entirely replaced, onshore, large-diameter (6 inches or
greater), gas transmission, Type A gas gathering, and hazardous liquid
pipelines.\1\ The final rule also requires operators of all gas and
hazardous liquid pipelines to modify their emergency plans to ensure
immediate and direct contact of 9-1-1 emergency call centers, or
coordinating government officials, on notification of a potential
rupture. PHMSA expects this final rule's regulatory amendments will
ensure operators of pertinent gas and hazardous liquid pipelines take
prompt identification, isolation, and mitigation actions with respect
to unintentional or uncontrolled, large-volume releases of gas or
hazardous liquids during a pipeline rupture. The safety enhancements in
this final rule, therefore, are expected to improve public safety,
reduce threats to the environment (including, but not limited to,
reduction of greenhouse gas (GHG) emissions released during ruptures of
natural gas pipelines), and promote environmental justice for minority
populations, low-income populations, or other underserved and
disadvantaged communities.
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    \1\ For the purposes of this final rule, references to diameter
are to the outside diameter of the pipe. Similarly, subsequent
references in this final rule to gas transmission, Type A gas
gathering, and hazardous liquid pipelines will, for brevity,
generally omit the qualifications (onshore, 6-inch diameter)
appearing in the statement of the final rule's scope above. Lastly,
references within this final rule to ``hazardous liquid pipelines''
will, unless otherwise stipulated, include carbon dioxide pipelines
because both hazardous liquid and carbon dioxide pipelines are
subject to 49 CFR part 195 requirements.
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    Recent pipeline ruptures with catastrophic consequences underscore
the importance of prompt identification, isolation, and mitigation
actions in reducing the amount of product released--and by extension,
the loss of life, property damage, and environmental harm--from
ruptures on hazardous liquid and natural gas pipelines. One such
rupture occurred on July 25, 2010, in Marshall, MI, resulting in a
release of approximately 800,000 gallons of crude oil into the
Kalamazoo River and approximately $1 billion in property and
environmental damages.\2\ The operator, Enbridge Energy, LP (Enbridge),
took 18 hours to confirm the

pipeline rupture following the initial alarms received by the control
room operators. Once Enbridge confirmed the rupture, the failed segment
was immediately isolated using installed remote-control shut-off valves
(RCV).
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    \2\ NTSB, Accident Report PAR-12/01, ``Enbridge Incorporated:
Hazardous Liquid Pipeline Rupture and Release; Marshall, MI: July
25, 2010'' (July 10, 2012), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1201.pdf.
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    Another rupture occurred on September 9, 2010, in San Bruno, CA,
when a gas transmission pipeline ruptured, causing an explosion that
killed 8 people, sent 51 other people to the hospital, destroyed 38
homes and damaged 70 others, and caused the evacuation of approximately
300 homes. According to the NTSB report on that incident,\3\ the
initial 9-1-1 notification call by the public was made within one
minute of the rupture, which occurred at 6:11 p.m. The response crew
assembled to operate valves and isolate the rupture did not reach the
first valve site until 7:20 p.m. According to the California Public
Utilities Commission (CPUC) report on the incident, the operator,
Pacific Gas and Electric (PG&E), did not confirm that the incident was
a pipeline rupture until 7:25 p.m., when PG&E employees in the field,
at dispatch, and in the company's supervisory control and data
acquisition (SCADA) \4\ center confirmed that a PG&E gas transmission
line had failed.\5\ After multiple valve closures, PG&E isolated the
ruptured pipeline segment at 7:46 p.m., 95 minutes after the rupture
initiated.\6\ This delay in closing the valves allowed the fire to burn
unabated and hampered emergency response efforts.
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    \3\ NTSB, Accident Report PAR-11/01, ``Pacific Gas and Electric
Company; Natural Gas Transmission Pipeline Rupture and Fire; San
Bruno, CA; September 9, 2010'' (Aug. 30, 2011), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR1101.pdf.
    \4\ Most pipeline operators utilize a SCADA system to run their
operations. These are computer-based systems used by a controller in
a control room that collects and displays information about a
pipeline facility and may have the ability to send commands back to
the pipeline facility. See 49 CFR 192.3 and 195.2.
    \5\ CPUC, ``Sept. 9, 2010 PG&E Pipeline Rupture in San Bruno,
CA'' (Jan. 12, 2012), https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_website/Content/Safety/Natural_Gas_Pipeline/News/AgendaStaffReportreOIIPGESanBruno Explosion.pdf.
    \6\ The CPUC also noted that the backfeed to the line and the
gas feeds to a related distribution system were not closed until
7:52 p.m. and 11:32 p.m., respectively.
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    These rupture events highlight the need for more robust protections
in the Federal Pipeline Safety Regulations for identifying, isolating,
and mitigating catastrophic pipeline failures. First, there is a need
for better and more timely rupture isolation and mitigation equipment
and methods. PG&E's failure to close isolation valves rapidly after the
rupture at San Bruno diminished its ability to mitigate the
consequences of the failure, allowing the fire to burn unabated for 95
minutes following the initial rupture, with firefighting operations
continuing for an additional 2 days after the rupture occurred. Second,
there is need for operators to identify promptly that a rupture has
occurred and respond quickly to mitigate its consequences. Enbridge had
remote-control isolation valves installed on its ruptured oil pipeline
at the time the spill occurred near Marshall, MI, but its failure to
confirm and respond to the rupture promptly rendered that technology
essentially useless.
    After these spill events, the Pipeline Safety, Regulatory
Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act; Pub.
L. 112-90) was enacted. The legislation contained several mandates to
improve pipeline safety. In particular, PHMSA is required to issue
regulations requiring the use of automatic shut-off valves (ASV) or
RCVs, or equivalent technology, on newly constructed or replaced gas
transmission and hazardous liquid pipeline facilities. See 49 U.S.C.
60102(n). That statutory mandate was subsequently revisited,
establishing a new deadline for PHMSA to issue a final rule (see 49
U.S.C. 60102 note).
    In developing this final rule, PHMSA considered NTSB safety
recommendations following the PG&E incident; GAO recommendations on the
ability of operators to respond to commodity releases in high-
consequence areas (HCA); \7\ technical reports commissioned by PHMSA on
valves and leak detection; 8 9 comments received on related
topics through advance notices of proposed rulemaking (ANPRM) and the
notice of proposed rulemaking (NPRM) published in February 2020; \10\
and feedback from members of the public, environmental advocacy
organizations, State pipeline safety regulators, and industry
representatives during Gas Pipeline Advisory Committee and Liquid
Pipeline Advisory Committee meetings.
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    \7\ GAO, ``Pipeline Safety: Better Data and Guidance Needed to
Improve Pipeline Operator Incident Response'' (Jan. 2013), https://www.gao.gov/assets/660/651408.pdf. An HCA, briefly, is an area with
higher population density or contains an area of cultural
significance or where people would congregate at a certain frequency
(e.g., churches, playgrounds, schools, hospitals, etc.). See Sec.
192.903.
    \8\ Oak Ridge National Laboratory (ORNL), ORNL/TM-2012/411,
``Studies for the Requirements of Automatic and Remotely Controlled
Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines with
Respect to Public and Environmental Safety'' (Oct. 31, 2012),
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16701/finalvalvestudy.pdf.
    \9\ Kiefner and Associates, Inc., Report No. 12-173, ``Leak
Detection Study--DTPH56-11-D-000001'' (Dec. 10, 2012), https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
    \10\ 85 FR 7162 (Feb. 6, 2020) (NPRM).
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B. Summary of the Major Provisions of the Regulatory Action

    This final rule prescribes installation and spacing requirements
for ASVs and RCVs (collectively, rupture-mitigation valves, or RMVs) as
well as for alternative equivalent technology. The requirements apply
to most newly constructed, or entirely replaced, onshore pipelines with
diameters of 6 inches or greater, including natural gas transmission
pipelines, Type A gas gathering pipelines, and hazardous liquid
pipelines (including certain regulated hazardous liquid gathering
pipelines). In this final rule, PHMSA has defined an ``entirely
replaced'' pipeline as a pipeline that has 2 or more miles being
replaced with new pipe within any stretch of 5 contiguous miles within
any 24-month period.
    The rule also defines ASVs and RCVs as RMVs. PHMSA did not identify
specific technologies that operators might use as alternative
equivalent technologies for the purposes of this rulemaking, but PHMSA
is requiring that such alternative technologies meet the performance
standard for RMVs, to include the ability to immediately enable
isolation of a rupture--in 30 minutes or less, measured from an
operator's identification of a rupture after notification of a
potential rupture.
    Operators of pipelines subject to the requirements of this final
rule may request to install alternative equivalent technologies if they
can demonstrate within a notification for PHMSA review that site-
specific installation of an alternative equivalent technology would
provide an equivalent level of safety to an RMV. Those notifications
must be submitted in advance of installation of that technology, and
must demonstrate an equivalent level of safety by reference to
technical and safety factors including, but not limited to, the
following: Design, construction, maintenance, and operating procedures;
technology design and operating characteristics such as operation times
(closure times for manual valves); service reliability and life;
accessibility to operator personnel; nearby population density; and
potential consequences to the environment and the public. Further,
should an operator request use of manual valves as an alternative
equivalent technology, the notification submitted to PHMSA must also
demonstrate the economic, technical, or operational infeasibility of
installation of an RMV by reference to

factors such as access to communications and power; terrain;
prohibitive cost; labor and component availability; ability to secure
required land access rights and permits; and accessibility to operator
personnel for installation and maintenance.
    For regulated rural hazardous liquid gathering pipelines,\11\ at
this time, PHMSA is requiring the installation of RMVs or alternative
equivalent technology only where such pipelines cross bodies of water
more than 100 feet in width from high water mark to high water mark.
For hazardous liquid pipelines in general, this final rule establishes
valve spacing thresholds both within and outside of HCAs and provides
valve spacing limits for highly volatile liquid (HVL) pipelines in
populated areas. PHMSA has recently issued a final rule in a separate
rulemaking that will update its regulations that affect all types of
gas gathering pipelines.\12\
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    \11\ A regulated rural hazardous liquid gathering pipeline is
defined in Sec.  195.11 as an onshore gathering line in a rural area
that meets all of the following criteria: (1) A nominal diameter
from 6\5/8\ to 8\5/8\ inches; (2) located in or within \1/4\ mile of
an unusually sensitive area, as that term is defined in Sec.  195.6;
and (3) operating at a maximum pressure established under Sec.
195.406 corresponding to a stress level greater than 20 percent of
the specified minimum yield strength (SMYS) of the line pipe or, if
the stress level is unknown or the pipeline is not constructed with
steel pipe, a pressure of more than 125 psig.
    \12\ ``Pipeline Safety--Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments,'' 86 FR 63266 (Nov.
15, 2021) (``Gas Gathering final rule'').
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    For gas transmission and Type A gas gathering pipelines, the RMV or
alternative equivalent technology installation requirements will not
apply if the pipeline segment is in a Class 1 or Class 2 location and
has a potential impact radius (PIR) less than or equal to 150 feet.
PHMSA understands that the lower operating pressures characteristic of
Type B gas gathering pipelines involve risk profiles comparable to the
Type A gas gathering pipelines exempted from the final rule's
installation and operational requirements. Therefore, the final rule
similarly exempts Type B gas gathering pipelines from the RMV or
alternative equivalent technology installation requirements. The final
rule also exempts Type C gas gathering lines from those requirements,
as that designation was established by the Gas Gathering final rule--
which was published well after the publication of the NPRM for this
rulemaking.
    Additionally, for each gas pipeline whose operator, in response to
a class location change, chooses to replace 2 or more miles of pipe
within a contiguous 5-miles to meet the maximum allowable operating
pressure (MAOP) requirements of the new class location, the operator
would be required to install or otherwise modify existing valves as
necessary to comply with the valve spacing requirements and rupture
mitigation requirements of this final rule.\13\ The final rule provides
operators replacing smaller pipeline segments following a change in
class location more flexibility: Operators replacing between 1,000 feet
and 2 miles may either install RMVs, or they may automate existing
valves with automatic or remote-control actuators and pressure sensors
(with a maximum spacing of 20 miles). And the final rule's RMV
installation and spacing requirements do not apply to those pipe
replacements that amount to less than 1,000 feet within any single mile
during any 24-month period.
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    \13\ Class locations, defined at Sec.  192.5, are determined
depending on the number of dwellings within 220 yards on either side
of a pipeline and reflect the population density around the
pipeline.
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    This final rule also establishes Federal minimum safety performance
standards for the identification of ruptures, pipeline segment
isolation, and other mitigative actions, for pipelines on which RMVs or
alternative equivalent technology are installed pursuant to this
rulemaking. Relevant new requirements include: (1) A definition of the
term ``notification of potential rupture'' to identify signs of an
uncontrolled release of a large volume of commodity observed by, or
reported to, the operator; (2) establishing written procedures for
identifying and responding to a rupture; (3) responding to an
identified rupture by closing RMVs or alternative equivalent
technology, to provide complete valve shut-off and segment isolation as
soon as practicable, but no more than 30 minutes after rupture
identification; (4) performing post-event reviews of any incidents/
accidents or other failure events involving the closure of RMVs or
alternative equivalent technologies to ensure the performance
objectives of this rule are met and to apply any lessons learned
system-wide; (5) performing maintenance on RMVs and alternative
equivalent technology, which includes drills for alternative equivalent
technology that is manually or locally operated; and (6) remediation
measures for repair or replacement of inoperable RMVs and alternative
equivalent technologies, including an RMV or alternative equivalent
technology that cannot maintain shut-off, as soon as practicable.
    This final rule also requires operators of all gas and hazardous
liquid pipelines subject to the emergency planning requirements at
Sec. Sec.  192.615 and 195.402, respectively, to update their emergency
response plans to provide for immediate and direct notification of
appropriate public safety answering points (9-1-1 emergency call
centers) for the communities and jurisdictions in which a rupture is
located following the notification of a potential rupture. Similarly,
the final rule requires all gas and hazardous liquid pipelines subject
to failure investigation requirements at Sec. Sec.  192.617 and
195.402, respectively, to conduct post-rupture investigations and
reviews, and to incorporate lessons learned from such investigations
and reviews into their personnel training and qualifications programs,
and in design, construction, testing, maintenance, operations, and
emergency procedure manuals and specifications.

C. Costs and Benefits

    Consistent with Executive Order 12866 (``Regulatory Planning and
Review''),\14\ PHMSA has prepared an assessment of the benefits and
costs of this final rule, as well as reasonable alternatives. The
Regulatory Impact Analysis (RIA) developed by PHMSA in support of this
final rule, and which is available in the rulemaking docket, estimates
the annual costs of the rule to be approximately $5.9 million,
calculated using a 7 percent discount rate. In the RIA, costs are
aggregated by compliance method to estimate total costs, by year, for
the baseline and the final rule. The incremental effect of this
rulemaking is estimated by taking the difference in total costs
relative to the baseline. Costs are then aggregated across all years in
the analysis period and annualized. The costs reflect the installation
of valves on certain newly constructed and entirely replaced gas and
hazardous liquid pipelines, as well as incremental programmatic changes
that operators will need to make to incorporate the proposed rupture
identification and response procedures.
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    \14\ 58 FR 51735 (Oct. 4, 1993).
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    PHMSA provides a qualitative discussion of the benefits of this
rulemaking in the RIA.\15\ PHMSA expects this final rule's regulatory
amendments will compel operators of

pertinent natural gas and hazardous liquid pipelines to take prompt
identification, isolation, and mitigation actions with respect to
unintentional or uncontrolled, large-volume releases of natural gas or
hazardous liquids during a pipeline rupture. The safety enhancements in
this final rule, therefore, are expected to improve public safety,
reduce threats to the environment (including, but not limited to,
reduction of greenhouse gas emissions released during ruptures of
natural gas pipelines), and promote environmental justice for minority
populations, low-income populations, or other underserved and
disadvantaged communities. PHMSA has, therefore, determined that these
(unquantified) public safety, environmental, and equity benefits of the
final rule described in this final rule and its supporting RIA and
Environmental Assessment justify the costs of the final rule.
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    \15\ PHMSA explains in the RIA that, although the Environmental
Assessment for this rulemaking provides illustrative quantifications
of avoided greenhouse gas emissions from this final rule, PHMSA's
evaluation of the greenhouse gas emissions within its cost-benefit
analysis is on the basis of qualitative assessment of those avoided
emissions.
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II. Background

A. Pipeline Ruptures

    Although pipelines are generally considered to be an efficient and
relatively safe means of transporting natural gas and hazardous
liquids,\16\ they can experience large-volume, uncontrolled releases
that can have severe consequences. Such rupture events can be
aggravated by some combination of: Missed opportunities by the operator
to identify that a rupture has occurred; the failure of operating
personnel to take appropriate actions once a rupture has been
identified; delays in accessing and closing available pipeline segment
isolation valves; and an inability quickly to close isolation valves
that would have the most significant impact in mitigating the
consequences of a rupture. Typically, these types of events where a
significant amount of time passes between initiation and isolation of a
rupture have been the most serious in terms of monetary and
environmental damages and safety consequences. The Marshall, MI, and
San Bruno, CA, incidents are examples of rapid failure events with
large-volume releases on high-pressure, large-diameter pipelines with
serious consequences exacerbated by delays in identification and
isolation of the ruptures.
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    \16\ See PHMSA, Letter to Congress, Report on Shipping Crude Oil
by Truck, Rail, and Pipeline at 2 (Oct. 2018), https://www7.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/70826/report-congress-shipping-crude-oil-truck-rail-and-pipeline-32019.pdf.
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    The intent of this final rule is to require design and equipment
elements and improved operational practices for quick and efficient
identification of ruptures, that in turn will improve rupture
mitigation and shorten rupture isolation times for certain gas
transmission, gathering, and hazardous liquid pipelines. Rupture
isolation time, as it is discussed in this final rule, is the time it
takes an operator to identify a rupture after a notification of
potential rupture, implement response procedures, and fully close the
appropriate valves to terminate the uncontrolled flow of commodity from
the ruptured pipeline segment.
    PHMSA and NTSB investigations of recent natural gas transmission
and hazardous liquid pipeline ruptures have identified issues relating
to the timeliness of rupture identification and the appropriateness and
timeliness of operators' responses to identified ruptures. Typically,
no single event contributes to the deficiencies in rupture
identification and response. Instead, there are multiple contributing
factors associated with the technology, design, equipment, procedures,
or human elements that result in inadequate rupture identification and
response efforts. In some rupture scenarios, certain aspects of an
operator's rupture identification or response efforts appeared
adequate, but other issues, such as delayed access to isolation valves,
resulted in an inadequate response overall.
    For example, in the Enbridge accident near Marshall, MI, the
pipeline operator had installed a leak detection system (LDS) and SCADA
system that notified the operator of a potential rupture within minutes
of the actual event, but issues related to the operator's procedures,
training, and personnel response resulted in an 18-hour lapse before
the operator confirmed the rupture and initiated mitigating actions. In
the PG&E incident in San Bruno, CA, the operator effectively identified
through its LDS or SCADA systems that there was in fact a rupture, but
then took another 95 minutes to isolate it. This delay proved
catastrophic due to the time required for confirming the existence of
the rupture, assembling response personnel, traveling to the valve
site, and closing the valve to isolate the pipeline segment--during
which time a fire resulting from the rupture burned unabated. The
NTSB's report on that incident noted that PG&E lacked a detailed and
comprehensive procedure for responding to large-scale emergencies such
as a transmission pipeline break, and that the use of ASVs or RCVs
would have reduced the amount of time taken to stop the flow of gas.
    Prior to those rupture events, the NTSB noted similar issues
related to rupture response in its report on an incident occurring on
March 23, 1994, in Edison Township, NJ.\17\ In the Edison incident, the
operator took nearly 2\1/2\ hours to stop the flow of natural gas from
a ruptured pipeline in a highly-populated area. The fire that followed
the rupture destroyed 8 buildings, caused the evacuation of
approximately 1,500 apartment residents, and resulted in more than $25
million (approximately $40 million in 2020 dollars) worth of property
damage. The NTSB report quotes the operator of that pipeline in saying
that it could typically notify employees to close valves within 5 to 10
minutes after identifying a rupture, and that the time it took to close
a manual valve depended on the employee's travel time to the valve
site: Its employees could usually arrive at a valve site within 15 to
20 minutes, but in some instances it could take more than an hour for
employees to arrive at certain valve locations after being dispatched.
With this in mind, the NTSB concluded that the lack of automatic or
remote-operated valves on the ruptured line prevented the operator from
promptly stopping the flow of gas to the failed pipeline segment, which
exacerbated damage to nearby property. Subsequently, the NTSB
recommended to PHMSA's predecessor, the Research and Special Programs
Administration, that it expedite establishing requirements for
installing automatic or remote-operated valves on high-pressure
pipelines in urban and environmentally sensitive areas to provide for
rapid shutdown of failed pipeline systems.
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    \17\ NTSB, PAR-95-01, ``Pipeline Accident Report; Texas Eastern
Transmission Corporation Natural Gas Pipeline Explosion and Fire;
Edison, New Jersey'' (Jan. 18, 1995), https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR9501.pdf.
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B. National Transportation Safety Board Recommendations

    In its report on the PG&E gas transmission pipeline incident that
occurred in San Bruno, CA, the NTSB issued safety recommendations P-11-
8 through P-11-20 to PHMSA.\18\ Pertaining to this rulemaking, NTSB
safety recommendation P-11-10 recommended that PHMSA require operators
to equip their SCADA systems with tools, including leak detection
systems and appropriately spaced flow and pressure transmitters along
covered transmission lines, to identify leaks (and ruptures); and NTSB
safety recommendation P-11-11 recommended PHMSA require operators

install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the
valve spacing based on risk analysis.
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    \18\ See supra note 3.
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    PHMSA determined that, although the NTSB directed these
recommendations to a rupture on a gas transmission pipeline, certain
aspects of these recommendations are also applicable to ruptures on gas
gathering and hazardous liquid pipelines, including the regulated
hazardous liquid gathering pipelines regulated under part 195. PHMSA
took these recommendations into account when developing this final rule
by requiring that RMVs and alternative equivalent technologies be
capable of having their status controlled or monitored (directly, or
indirectly via the upstream pressure, and the downstream pressure)
remotely,\19\ and by requiring the installation of RMVs, or equivalent
alternative technologies, at intervals of no more than 8 miles in Class
4 locations and 15 miles in Class 3 locations.
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    \19\ As discussed later in this document, for ASVs, an operator
does not need to monitor remotely a valve's status if the operator
has the capability to monitor pressures or gas flow rate on the
pipeline to identify and locate a rupture. Pipeline segments that
use an alternative equivalent technology must have the capability to
monitor pressures or gas flow rates on the pipeline to identify and
locate a rupture.
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C. Advance Notices of Proposed Rulemaking

    PHMSA published two ANPRMs seeking comments regarding the revision
of provisions in the Federal Pipeline Safety Regulations governing
safety of hazardous liquid pipelines and natural gas pipelines.\20\
PHMSA responded to pertinent comments received on the ANPRMs in Section
III of the NPRM preceding this final rule. PHMSA addressed other topics
raised in the hazardous liquid and gas transmission ANPRMs within other
rulemakings, as appropriate.
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    \20\ 75 FR 63774 (Oct. 18, 2010) (pertaining to hazardous liquid
pipelines within docket PHMSA-2010-0229), and 76 FR 53086 (Aug. 25,
2011 (pertaining to natural gas pipelines within docket PHMSA-2011-
0023).
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D. 2011 Pipeline Safety Act and Related Studies

    Sections 4 and 8 of the 2011 Pipeline Safety Act established
statutory requirements relating directly to topics addressed in the
ANPRMs discussed previously. This final rule responds to those
statutory mandates. PHMSA also considered the GAO Report No. GAO-13-
168, ``Better Data and Guidance Needed to Improve Pipeline Operator
Incident Response'' and ORNL Report/TM-2012/411, ``Studies for the
Requirements of Automatic and Remotely Controlled Shutoff Valves on
Hazardous Liquids and Natural Gas Pipelines With Respect to Public and
Environmental Safety'' which were performed in response to the 2011
Pipeline Safety Act and are discussed further below.
i. Section 4--Automatic and Remote-Controlled Shut-Off Valves
    Section 4 of the 2011 Pipeline Safety Act directs the Secretary of
Transportation (Secretary), if appropriate, to require by regulation
the use of ASVs or RCVs, or equivalent technology, where it is
economically, technically, and operationally feasible, on hazardous
liquid and gas transmission pipeline facilities that are constructed or
entirely replaced after the date on which the Secretary issues the
final rule containing such requirements. This final rule addresses this
mandate by establishing minimum standards for the installation of RMVs
or alternative equivalent technology on specified newly constructed or
entirely replaced, onshore pipelines that have diameters of 6 inches or
greater, including gas transmission pipelines, Type A gas gathering
pipelines, hazardous liquid pipelines, and certain regulated hazardous
liquid gathering lines.
a. GAO Report GAO-13-168
    Section 4 of the 2011 Pipeline Safety Act required the development
of a study by the Comptroller General on the ability of pipeline
operators to respond to a hazardous liquid or gas release from a
pipeline segment located in an HCA. In this study, published in January
2013, the GAO recommended PHMSA take the following two actions:
    1. Improve the reliability of incident response data to improve
operators' incident response times, and use this data to evaluate
whether to implement a performance-based framework for incident
response times; and
    2. Assist operators in determining whether to install automated
valves by using PHMSA's existing information sharing mechanisms to
alert all pipeline operators of inspection and enforcement guidance
that provides additional information on how to interpret regulations on
automated valves, and share approaches used by operators for making
decisions on whether to install automated valves.
    The GAO report noted that defined performance-based goals,
established with reliable data and sound agency assessments, could
result in improved operator response to incidents, with ASV and RCV
installation and use being one of the determining factors. The GAO
further noted that PHMSA's then-current regulations for incident
response and installation and use of ASVs and RCVs employed broadly-
stated performance standards, requiring operators to respond to
incidents in a ``prompt and effective manner,'' \21\ and requiring
operators to install ASVs, RCVs, or emergency flow restricting devices
(EFRD) if an operator determines, through risk analysis, such valves
are necessary to protect HCAs.\22\
---------------------------------------------------------------------------

    \21\ For natural gas and hazardous liquid pipelines, Sec. Sec.
192.615(a)(3) and 195.402(e)(2), respectively.
    \22\ Requirements for ASV and RCV installation on gas
transmission pipelines are at Sec.  192.935(c), and requirements for
EFRD installation for hazardous liquid pipelines are at Sec.
195.452(i)(4).
---------------------------------------------------------------------------

    More clearly defined goals can help operators identify actions that
could improve their ability to respond to certain types of incidents
consistently and promptly, though identical incident response actions
are not appropriate for all circumstances due to variable locations,
equipment needs, configurations, and operating conditions of pipeline
facilities. PHMSA agrees with the GAO's conclusions that more precise
performance-based standards, in conjunction with carefully selected
requirements, could be more effective in improving incident response
times, particularly when ruptures are involved.
    The GAO report also concluded that the primary advantage of
installing and using automated valves is that operators can respond
more quickly to isolate the affected pipeline segment and reduce the
amount of commodity released. Although the report suggested that using
automated valves can have certain disadvantages, including the
potential for accidental closures, which makes it appropriate for
operators to decide whether to install automated valves on a case-by-
case basis, the report recognized that a faster incident response time
could reduce the amount of property damage from secondary fires (after
an initial pipeline rupture) by allowing fire departments to extinguish
the fires sooner. For hazardous liquid pipelines, a faster incident
response time could also result in lower costs for environmental
remediation efforts and less commodity loss.
    PHMSA applied these principles and the GAO's findings and
recommendations in developing the standards in this final rule. The
amendments in this final rule also include specific post-event review
requirements in Sec. Sec.  192.617 and 195.402. Operators must make
those post-event reviews available for PHMSA to inspect, and PHMSA
would be able to use those reviews to inform future rulemakings and
guidance documents.

b. Studies for the Requirements of Automatic and Remotely Controlled
Shutoff Valves and Hazardous Liquids and Natural Gas Pipelines With
Respect to Public and Environmental Safety
    In March 2012, PHMSA commissioned a study to assess the
effectiveness of timely operation of automatic and remote-controlled
shut-off valves recommended by the NTSB in its report on the PG&E
incident and mandated by section 4 of the 2011 Pipeline Safety Act for
mitigating the public safety and environmental consequences of natural
gas and hazardous liquid pipeline releases. That study, whose
conclusions were memorialized in the above-captioned report, also
evaluated the economic, technical and operational feasibility and
potential benefits of installing ASVs and RCVs in newly constructed and
entirely replaced pipelines. The study concluded that:
    1. In general, installing ASVs and RCVs on newly constructed and
entirely replaced natural gas transmission and hazardous liquid
pipelines is technically feasible, provided sufficient space is
available for the valve body, actuators, power source, sensors and
related electronic equipment, and personnel required to install and
maintain the valve; and is operationally feasible, provided the
communication links between the RCV site and the control room are
continuous and reliable.
    2. There is evidence that it is economically feasible to install
ASVs and RCVs on newly constructed and entirely replaced natural gas
transmission and hazardous liquid pipelines, and the benefits would
exceed the costs for the release scenarios (guillotine-type breaks on
gas transmission pipelines with diameters of 12 and 42 inches in HCAs
of all class locations, as well as on hazardous liquid pipelines with
diameters of 8 and 30 inches in HCAs) considered in the study. However,
the study noted that it is necessary to consider site-specific
variables in determining whether installing ASVs or RCVs on newly
constructed or entirely replaced pipelines is economically feasible for
a particular situation and pipeline.
    3. Installing ASVs and RCVs on newly constructed and entirely
replaced natural gas and hazardous liquid pipelines can be an effective
strategy for mitigating potential fire consequences resulting from a
release and subsequent ignition. Adding automatic closure capability to
valves on newly constructed or entirely replaced hazardous liquid
pipelines can also be an effective strategy for mitigating potential
socioeconomic and environmental damage resulting from a release that
does not ignite.
    4. For hazardous liquid pipelines, installing ASVs and RCVs can be
an effective strategy for mitigating potential fire damage resulting
from a pipe opening-type breaks \23\ and subsequent ignition, provided
the leak is detected and the appropriate ASVs and RCVs close completely
so that the damaged pipeline segment is isolated within 15 minutes
after the break.
---------------------------------------------------------------------------

    \23\ A break in the pipeline that involves the opening of the
pipe in either the circumferential or longitudinal direction.
---------------------------------------------------------------------------

    PHMSA used the conclusions of that report in developing this
rulemaking and as a basis for implementing standards for valve
installation per section 4 of the 2011 Pipeline Safety Act.
ii. Section 8--Leak Detection
    Section 8 of the 2011 Pipeline Safety Act required the Secretary to
submit to Congress a report on LDSs used by operators of hazardous
liquid pipeline facilities, including transportation-related flow
lines, and to establish technically, operationally, and economically
feasible standards for the capability of LDSs to detect leaks.
    PHMSA responded to the 2011 Pipeline Safety Act's section 8 mandate
by commissioning a leak detection study.\24\ The study examined LDSs
used by operators of hazardous liquid and natural gas transmission
pipelines and included an analysis of the technical limitations of
current LDSs, the ability of the systems to detect ruptures and small
leaks that are ongoing or intermittent, and what can be done to foster
development of better technologies. It also reviewed the practicality
of establishing technically, operationally, and economically feasible
standards for LDS capabilities. The study addressed five tasks defined
by PHMSA:
---------------------------------------------------------------------------

    \24\ See supra note 9.
---------------------------------------------------------------------------

    1. Assess past incidents to determine if additional LDSs would have
helped to reduce the consequences of the incident;
    2. Review installed and currently available LDS technologies, along
with their benefits, drawbacks, and ability to be retrofitted on
existing pipelines;
    3. Study current LDS operational practices used by the pipeline
industry;
    4. Perform a cost-benefit analysis of deploying LDSs on existing
and new pipelines; and
    5. Study existing LDS industry standards and international
regulations to determine what gaps exist and if additional standards
are needed to cover LDSs over a larger range of pipeline categories.
    The authors of the study were tasked only to report data and
technical and cost aspects of LDSs. Although the study did not provide
any specific conclusions or recommendations related to leak detection
system standards, the study acknowledged that pressure/flow monitoring
(leak detection techniques) will consistently and reliably catch large
volume, uncontrolled release events such as ruptures. Consistent with
the study findings, PHMSA has established regulations requiring RMVs
and alternative equivalent technologies to be outfitted with equipment
or other means to monitor valve status, commodity pressures, and flow
rates.
    The study also noted that operator procedures may have allowed
ignoring alarms, restarting pumps, or opening valves during large
releases. PHMSA addresses this concern in this rulemaking by requiring
operators to confirm that a rupture is occurring following any one of
the criteria specified in a new regulatory definition for the
``notification of [a] potential rupture.'' The final rule also provides
for post-incident reviews that can help operators determine how best to
implement lessons learned system-wide and assist PHMSA in providing
industry-wide guidance regarding overarching performance issues.

E. 2020 Valve Rule NPRM

    On February 6, 2020, PHMSA published the NPRM seeking public
comments on the revision of the Federal Pipeline Safety Regulations
applicable to the safety of certain gas transmission, gas gathering,
and hazardous liquid pipelines. Specifically, the proposed language
created a RMV installation requirement for onshore, newly constructed
and entirely replaced gas and hazardous liquid pipelines, including
gathering pipelines, with diameters of 6 inches or greater.
Additionally, PHMSA proposed to shorten pipeline segment isolation
times in response to rupture events. PHMSA proposed a definition for
``rupture'' and outlined standards related to rupture identification
and pipeline segment isolation, including establishing a 40-minute
maximum RMV closure time and a 10-minute rupture identification
threshold.
    In the NPRM, PHMSA also proposed requirements for RMV maintenance
and inspection, spacing, risk analysis, post-incident investigation and
review, and local 9-1-1 notification to help operators achieve better
rupture

response and mitigation. When developing the proposals in the NPRM,
PHMSA considered the relevant comments it received on the ANPRMs, as
well as the related NTSB recommendations, congressional mandates, and
related studies. A summary of the NPRM proposals and topics, the
comments received on those specific proposals, and PHMSA's response to
the comments received is set forth in Section III.

F. Subsequent Legislative Deadlines; Recent Executive Orders and
Actions

    Congress has revisited the rulemaking mandate in the 2011 Pipeline
Safety Act in subsequent legislation. Specifically, Congress directed
PHMSA to issue a final rule no later than December 20, 2020 (see 49
U.S.C. 60102 note). In addition, in the joint explanatory statement
accompanying the Consolidated Appropriations Act for FY 2021 (Pub. L.
116-120; December 27, 2020), the conferees expressed ``disappointment''
that PHMSA had not met the December 20 deadline, and specified that
PHMSA should issue a final rule within 180 days of enactment (i.e., by
June 25, 2021).\25\
---------------------------------------------------------------------------

    \25\ 166 Cong. Rec. H8823 (daily ed. Dec. 21, 2020) (joint
explanatory statement on Consolidated Appropriations Act of FY
2021).
---------------------------------------------------------------------------

    The President has also issued a series of Executive Orders
emphasizing the importance of public safety, environmental protection,
and GHG reduction in Federal policymaking. Executive Order 13990
(``Protecting Public Health and the Environment and Restoring Science
To Tackle the Climate Crisis'') \26\ announced the Administration's
policy to, among other things, improve public health and protect the
environment, reduce greenhouse gas emissions, and prioritize
environmental justice. Executive Order 14008 (``Tackling the Climate
Crisis at Home and Abroad'') \27\ stated the Administration's policy
that climate considerations will be an essential element of United
States foreign policy and national security. The order also stated the
Administration's policy to organize and deploy the full capacity of
Federal agencies to combat the climate crisis, using a Government-wide
approach. The President also announced a new target for reductions in
national GHG emissions (a 50-52 percent reduction from 2005 levels in
economy-wide net greenhouse gas pollution in 2030) to combat climate
change, highlighting the importance of reducing emissions of greenhouse
gases other than carbon dioxide, including methane, to deliver fast
climate benefits.\28\ Lastly, the Administration touted the GHG
emissions reduction benefits of this rulemaking within the U.S. Methane
Emissions Reduction Action Plan.\29\
---------------------------------------------------------------------------

    \26\ 86 FR 7037 (Jan. 20, 2021).
    \27\ 86 FR 7619 (Feb. 1, 2021).
    \28\ See, e.g., White House, ``Fact Sheet: President Biden Sets
2030 Greenhouse Gas Pollution Reduction Target Aimed at Creating
Good-Paying Union Jobs and Securing U.S. Leadership on Clean Energy
Technologies'' (Apr. 21, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/04/22/fact-sheet-president-biden-sets-2030-greenhouse-gas-pollution-reduction-target-aimed-at-creating-good-paying-union-jobs-and-securing-u-s-leadership-on-clean-energy-technologies/.
    \29\ White House, ``U.S. Methane Emissions Reduction Action
Plan'' at 7 (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf.
---------------------------------------------------------------------------

III. NPRM Comments, Pipeline Advisory Committee Recommendations, and
PHMSA Responses

    The comment period for the NPRM ended on April 6, 2020. PHMSA
received approximately 30 submissions to the docket commenting on the
NPRM, including comments from major industry trade associations and
others following advisory committee meetings as discussed below. PHMSA
also accepted stakeholders' requests to discuss this rulemaking in
meetings memorialized in the rulemaking docket. Consistent with Sec.
190.323, PHMSA considered all of these comments given their relevance
to the rulemaking and the absence of additional expense or delay
resulting from considering any late-filed comments.
    Some of the comments PHMSA received in response to the NPRM were
beyond the scope of the proposed regulations. In this final rule, PHMSA
does not address the comments on pipeline safety issues that were
beyond the scope of the NPRM; however, that does not mean that PHMSA
determined the comments lack merit or do not support additional rules
or amendments. Such issues may be the subject of other existing
rulemaking proceedings or may be addressed in future rulemaking
proceedings.
    The Technical Pipeline Safety Standards Committee (commonly known
as the Gas Pipeline Advisory Committee, or the GPAC) and the Liquid
Pipeline Advisory Committee (LPAC) are statutorily mandated (5 U.S.C.
App. 1-16; 49 U.S.C. 60115) advisory committees tasked with advising
and commenting on PHMSA's proposed safety standards, risk assessments,
and safety policies for natural gas and hazardous liquid pipelines,
respectively, prior to their final adoption. Each Committee consists of
15 members, with membership equally divided among Federal and State
agencies, regulated industry, and the public. The committees consider
the ``technical feasibility, reasonableness, cost-effectiveness, and
practicability'' of each proposed pipeline safety standard and provide
PHMSA with recommended actions pertaining to those proposals.
    On July 22 and 23, 2020, the GPAC and the LPAC (collectively, the
``Committees'') met virtually to discuss this rulemaking. During the
meetings, the Committees considered the specific regulatory proposals
in the NPRM and discussed various comments submitted in the rulemaking
docket on those proposals, including alternative regulatory language,
from the pipeline industry, public interest groups, and government
entities. Interested members of the public and other stakeholders were
permitted to comment on the NPRM's proposals during the open portion of
each meeting prior to the closed Committee discussions and voting. At
the end of their closed discussions of each of the principal elements
of the rulemaking, the Committees voted on whether to recommend PHMSA's
adoption of the language proposed in the NPRM, or a variation thereon,
as technically feasible, reasonable, cost-effective, and practicable.
    This section discusses the substantive comments on the NPRM that
were submitted to the docket, the GPAC and LPAC recommendations, as
well as any comments received from stakeholders in writing or during
meetings with PHMSA personnel before issuance of this final rule.\30\
They are organized by topic and include PHMSA's response to, and
resolution of, those comments.
---------------------------------------------------------------------------

    \30\ Those written comments, and summaries for the meetings, may
be found in the rulemaking docket. PHMSA notes those comments and
meeting summaries largely recapitulate positions submitted in
written comments on the NPRM or during the GPAC/LPAC meetings.
---------------------------------------------------------------------------

A. General Comments, Scope, Applicability, and Cost-Benefit Issues

1. Summary of Proposal
    In the NPRM, PHMSA proposed to make changes to parts 192 and 195
that applied to many regulated gas transmission, gas gathering, and
hazardous liquid pipelines (including regulated rural hazardous liquid
gathering pipelines).

2. Comments Received
(i) General Support and Criticism
    Commenters largely supported the content and intent of the NPRM
while also submitting more specific comments on individual topics and
specific requests for revision, which are summarized in subsequent
sections. Industry organizations were supportive of PHMSA's intent to
enhance pipeline safety by improving rupture mitigation and shorten
rupture isolation times for certain natural gas and hazardous liquid
pipelines. The American Fuel and Petrochemical Manufacturers (AFPM)
indicated that their members rely on an uninterrupted, affordable
supply of crude oil and natural gas as feedstocks to maintain their
competitiveness and economic activity, and that therefore, it is
important to prevent pipeline safety incidents that can disrupt supply.
    The Kentucky Oil and Gas Association (KOGA) supported, in
particular, the regulatory certainty provided by the rule, citing the
importance of a clear framework to inform future business decisions.
Additionally, the Clean Air Council and the National Association of
Pipeline Safety Representatives (NAPSR) indicated support for the NPRM,
the clarity it provides, and PHMSA's attention to human health and
safety as well as the environment in regulating the transportation of
gas and hazardous materials via pipeline across the United States.
    A broad, general criticism was that the same language, criteria,
and requirements are unnecessarily restated in numerous sections of the
NPRM, and that the NPRM could be improved by consolidating or removing
duplicative language. Other criticisms included the scope of the rule
and its applicability to gathering lines, as discussed in more detail
in this section.
(ii) Scope: General
    The NTSB stated that, although Safety Recommendation P-11-10
specifically called for PHMSA to require leak detection equipment on
gas transmission and gas distribution pipelines, that recommendation is
not included in the proposed rule. The NTSB noted that the criteria
proposed for ruptures in the proposed rule do not specifically provide
for leak detection, and the proposed requirements for installing RMVs
exclude gas distribution systems, which are a particular concern of
Safety Recommendation P-11-10.
    Other commenters echoed these concerns and stated that the rule
should include leak- and rupture-detection requirements. The Clean Air
Council stated that, because significant time is often lost during a
pipeline incident in determining whether a rupture has occurred, the
final rule should require operators install devices to detect ruptures.
The Clean Air Council also noted that installing extra RMVs might be
fruitless if an operator cannot detect the initial rupture, and went on
to say that, in many rupture events, residents in the vicinity of the
incident are those who discover a pipeline has ruptured, not the
pipeline operators. Additionally, they noted that, in remote locations,
the time between the rupture event occurring and when it is discovered
is often so long that large amounts of product are lost, and the damage
to the surrounding area is extreme.
    The Pipeline Safety Trust (PST) stated that it has been nearly 10
years since the NTSB recommended leak detection systems, via
recommendation P-11-10, that meet regulatory performance standards on
all transmission and distribution pipelines, and that PHMSA must do
more to further the development and use of leak detection systems
beyond participating in industry standards development. The PST and the
Clean Air Council also asked that PHMSA consider extending the NPRM's
proposed RMV requirements to existing pipelines consistent with the
NTSB's recommendations.
(iii) Scope: Distribution and Gathering Pipelines
    Regarding the scope related to gas distribution pipelines, INGAA et
al.\31\ recommended that PHMSA limit any new gas distribution system
requirements, if they were intended in the proposal, to the 9-1-1
notification requirements and the incorporation of post-incident
lessons learned.
---------------------------------------------------------------------------

    \31\ The American Gas Association, American Petroleum Institute,
American Public Gas Association, and Interstate Natural Gas
Association of America (INGAA) jointly submitted comments to this
rulemaking. Throughout this final rule, their joint comment is
referred to as ``INGAA et al.''
---------------------------------------------------------------------------

    Several commenters requested clarification regarding the provisions
and their applicability to gathering pipelines, with the American
Petroleum Institute and Association of Oil Pipe Lines (API/AOPL) and
GPA Midstream Association (GPA Midstream), for example, recommending
that PHMSA provide an exception for gathering pipelines from the RMV
installation requirements. These entities stated that section 4 of the
2011 Pipeline Safety Act is limited to transmission pipelines, and also
that requiring gathering pipeline operators to install RMVs is not
economically, technically, or operationally feasible.
    KOGA and NAPSR noted that PHMSA initially stated that the NPRM
would be applicable to transmission pipelines, however, both commenters
noted that many of the provisions appeared to apply to gathering
pipelines. NAPSR stated that, per Sec.  192.9, Type A and B gathering
pipelines must follow transmission regulations, and they requested that
PHMSA clarify whether operators of gathering pipelines would have to
install new valves as required by the NPRM for class location changes.
    Sander Resources stated that it was unclear whether PHMSA wanted to
make the proposed regulations applicable to gathering pipelines or
whether gathering pipelines were inadvertently included. Therefore,
they noted that PHMSA must consider whether it would be appropriate to
include provisions applicable to gathering pipelines in the final rule.
Similarly, the Texas Pipeline Association (TPA) stated that the
regulations should not be expanded beyond the scope of the
congressional mandate, which applied to transmission pipeline
facilities.
(iv) Cost-Benefit
    Industry organizations stated that the NPRM dramatically
understated the potential costs of the proposed valve installation and
rupture detection standards, noting that PHMSA's Preliminary Regulatory
Impact Assessment (PRIA) estimated the annual cost of implementing the
proposed rule would be approximately $3.1 million. These organizations,
however, said that an estimate prepared several decades ago showed that
the cost of complying with similar valve installation standards would
exceed $600 million. They stated the PRIA offered no explanation for
the significant discrepancy between these two cost estimates and failed
to account for the true costs for the changes required, noting that
PHMSA may not propose a standard for adoption without making a
``reasoned determination that the benefits of the intended standard
justify its costs.''
    These commenters further stated that the alleged underreporting of
incremental annual regulatory burdens in the PRIA is particularly
impactful given the extraordinary economic conditions currently
confronting the oil and gas industry due to the Covid-19 global
pandemic. Furthermore, GPA Midstream and Sander Resources stated that
the industry expects to add more than 35,000 miles of pipeline during
2020; therefore, they suggested that it may be unrealistic for PHMSA to

estimate the total annualized cost amounts at $3.1 million. This would
amount to just $88 per mile on an annualized basis. Further, these
commenters noted that PHMSA's estimate did not cover repair or
replacement projects that are ongoing.
    TC Energy Corporation commented that the cost estimates for adding
actuators, controls, and telemetry to gas transmission pipelines would
have added $250,000 to $375,000 per valve for a total of $4 to 6
million in additional annual costs. Based on their review of their
class location projects completed in previous years, TC Energy
estimated that the proposed language regarding class location
replacements would add another $5 million in costs annually.
    An individual suggested that the cost-benefit analysis should
consider the loss of power when gas transmission or gas distribution
service is interrupted. They stated reductions in serious injuries and
loss of life are the most significant economic consideration, but there
are additional economic factors that PHMSA should consider. Among those
economic costs mentioned were cost to end users associated with
interruption of natural gas supply, as well as the additional delay and
costs associated with recovery efforts (e.g., re-lighting pilot lights)
following a service interruption.
    The Clean Air Council commented that the economic feasibility of
the proposed rule should not be a factor in implementing the
regulations. They stated that the installation of the proposed rupture-
detection and automatic-valve technology should be included in pipeline
construction and repair costs and should not be considered ``extra''
infrastructure that would carry an incremental cost. They stated that,
while in some cases, the necessary electricity and connectivity
requirements may make RCVs and ASVs infeasible in very remote
locations, in all other cases, this equipment should be considered
mandatory as part of the cost of constructing or repairing a pipeline.
They argued that the potential loss of life and economic costs from
ruptures is enough to justify this change, and that the implementation
cost is not even 1 percent of the amount of the damages the public and
industry pays annually for pipeline incidents.
3. PHMSA Response
    PHMSA considered all the comments regarding the NPRM's readability
and redundant language while drafting this final rule and believes that
this final rule more clearly states the regulations and their intended
effect.
(i) Scope
    General. In response to the comments from the PST and the Clean Air
Council that suggested PHMSA consider extending the NPRM's proposed RMV
requirements to existing pipelines consistent with the NTSB's
recommendations, PHMSA first notes that such a change is beyond the
scope of the NPRM. As a result, such an expansion may merit additional
process (e.g., a supplemental notice and solicitation of additional
comments), imposing a substantial delay to a rule that is already ten
years in the making. Further, application of the rule's RMV and
alternative equivalent technology installation requirements to existing
pipeline infrastructure would entail installation activity (e.g.,
blowdowns of existing pipelines prior to replacement, and work in
pipeline rights-of-way) that could involve significant GHG emissions
and other potential environmental harms.\32\
---------------------------------------------------------------------------

    \32\ PHMSA notes that the concerns discussed in this paragraph
militate against, at the final rule stage, extending the
rulemaking's scope to offshore gas and hazardous liquid pipelines.
PHMSA is, however, evaluating extension in the future of the
regulatory amendments in this final rule to pipeline facilities
(e.g., offshore pipelines, existing pipelines, additional gathering
lines, and smaller-diameter pipelines) that were not within the
scope of this rulemaking described in the NPRM.
---------------------------------------------------------------------------

    PHMSA notes that this does not mean that operators of existing
pipelines do not have to address the risks of leaks or rupture events.
All operators are required under the integrity management (IM)
regulations at Sec. Sec.  192.935 and 195.452 to conduct risk analyses
to identify measures (including installing ASVs, RCVs, or EFRDs) as
appropriate to enhance safety on pipeline segments that are in or which
could affect HCAs. Further, this final rule requires operators of all
gas and hazardous liquid pipelines subject to the emergency planning
requirements at Sec. Sec.  192.615 and 195.402, respectively, to update
their emergency response plans to provide for immediate and direct
notification of appropriate public safety answering points (9-1-1
emergency call centers) following the notification of a potential
rupture. Similarly, the final rule requires all gas and hazardous
liquid pipelines subject to failure investigation requirements at
Sec. Sec.  192.617 and 195.402, respectively, to conduct post-rupture
investigations and reviews, and to incorporate lessons learned from
such investigations and reviews into their training regimes and
procedures.
    Regarding the provisions in this rulemaking related to leak
detection, PHMSA is requiring pressure monitoring upstream and
downstream of RMVs and alternative equivalent technology installed
pursuant to this final rule. In doing so, PHMSA believes operators will
be able to better detect and isolate ruptures, and operators can
integrate the pressure monitoring equipment required by this rule into
future, or current, leak detection systems and analyses.
    PHMSA also notes that the Federal Pipeline Safety Regulations
reflect PHMSA's commitment to ensuring robust leak detection on PHMSA-
jurisdictional pipelines. Since 2002, operators of hazardous liquid
pipelines have been required to evaluate and install leak detection
systems in HCAs, including on pipeline segments that could affect an
HCA.\33\ PHMSA also issued new regulations in October 2019 \34\
requiring that all hazardous liquid pipelines, even those outside of
HCAs, have an effective system for detecting leaks. Further, hazardous
liquid pipeline operators are required to inspect the surface
conditions of their rights-of-way every 3 weeks.\35\ Similarly, gas
distribution pipeline operators are required by Sec. Sec.  192.722 and
192.723 to conduct periodic patrols and leak surveys of their
distribution systems at intervals. Gas transmission pipeline operators
are obliged by Sec.  192.705 to conduct periodic patrols of their
pipelines, and by Sec.  192.706 to conduct leak surveys twice per year
in Class 3 locations and quarterly for Class 4 locations.
---------------------------------------------------------------------------

    \33\ Design regulations for computational pipeline monitoring
(CPM) leak detection systems are at Sec.  195.134, and the
operational requirements for CPM leak detection are at Sec.
195.444. The requirement for operators of pipelines in HCAs and
those that could affect HCAs to have an LDS are at Sec.
195.452(i)(3).
    \34\ 84 FR 52260 (Oct. 1, 2019).
    \35\ See Sec.  195.412.
---------------------------------------------------------------------------

    PHMSA has also, in response to a mandate in section 120 of the
Protecting our Infrastructure of Pipelines and Enhancing Safety Act of
2020 (Pub. L. 116-260; 2020 PIPES Act), initiated a rulemaking (under
RIN 2137-AF51) to require operators of new and existing gas
transmission, gas distribution, and (certain) regulated gas gathering
lines implement leak detection and repair programs to achieve minimum
performance standards reflecting the capabilities of commercially
available advanced technologies. PHMSA will also continue to promote
leak detection technology for pipelines through its research and
development programs.
    Application to distribution and gas gathering lines. In the NPRM,
PHMSA intended for the RMV and alternative equivalent technology
installation requirements to apply to new and

entirely replaced regulated gathering pipelines, both for gas and
hazardous liquid operators. Section 192.9 states that operators of Type
A gas gathering pipelines must comply with the requirements of part 192
applicable to gas transmission pipelines, and new and replaced Type B
gas gathering pipelines must follow part 192 design, construction,
installation, initial inspection, and initial testing requirements
applicable to gas transmission pipelines. Nothing in the NPRM stated or
suggested that the regulatory amendments proposed therein would not
apply to new and entirely replaced gas gathering lines as provided by
the plain meaning of Sec.  192.9. However, in this final rule, PHMSA
has decided to narrow the application of the valve installation
requirements proposed in the NPRM to Type A gas gathering pipelines
only; Type B gas gathering pipelines are explicitly exempted from those
requirements.
    PHMSA adopts this limitation on the scope of the RMV and
alternative equivalent technology installation requirements because of
the distinguishable risk profiles associated with ruptures on Type A
and Type B gas gathering pipelines. Type A gas gathering pipelines, per
Sec.  192.8, operate at higher pressures (correlating to hoop stress of
20 percent or more of specified minimum yield strength (SMYS), or
pressures greater than 125 psig) and in areas of higher population
density (specifically Class 2, Class 3, or Class 4 locations). As a
result, ruptures on these pipelines will generally present a higher
risk of public safety consequences, similar to gas transmission
pipelines, warranting the additional protection that RMVs or
alternative equivalent technology would provide. However, as explained
in Section II. E of this final rule, PHMSA provides an exception from
the valve installation requirements if an operator can demonstrate that
a rupture on a new or entirely replaced Type A gas gathering pipelines
in Class 2 locations would yield a PIR of 150 feet or less.
    Type B gas gathering pipelines, on the other hand, as defined at
Sec.  192.8, operate at lower pressures (involving hoop stress of less
than 20 percent of SMYS). Ruptures on gas gathering pipelines operating
within that same pressure range are likely to have a PIR comparable to
the Type A gas gathering pipelines that PHMSA exempts from its RMV and
alternative equivalent technology installation requirements. The final
rule therefore exempts Type B gas gathering pipelines from those same
requirements. Going forward, however, PHMSA will gather and consider
additional data to inform application of these requirements to
additional types of gas gathering pipelines.
    PHMSA has, in this final rule, further clarified that the Type C
gas gathering lines established in the Gas Gathering final rule are,
like Type B gas gathering lines, not subject to the RMV and alternative
equivalent technology installation requirements. As explained above,
the Type C gas gathering designation is new, created after publication
of the NPRM and the LPAC and GPAC meetings on this rulemaking. PHMSA,
therefore, declines to extend the valve installation requirements to
that newly defined type of gas gathering lines in this final rule;
PHMSA may, however, consider doing so in a subsequent rulemaking.
    Section Sec.  195.1 similarly provides that part 195 applies to
onshore hazardous liquid gathering pipelines that are: (1) Located in a
non-rural area, (2) a regulated rural gathering line as that term is
defined in Sec.  195.11, or (3) located within an inlet of the Gulf of
Mexico as provided in Sec.  195.413. Further, operators of regulated
rural gathering lines have to follow specific safety provisions set out
in Sec.  195.11, one of which is that steel regulated rural gathering
lines must be designed, installed, constructed, initially inspected,
and initially tested in compliance with part 195. Therefore, and
similarly to Type A gas gathering pipelines, regulations proposed for
design and construction standards for hazardous liquid pipelines will
apply to regulated rural hazardous liquid gathering pipelines absent a
specific statement that the regulations do not apply to regulated rural
hazardous liquid gathering pipelines.
    Accordingly, in this final rule, operators of regulated hazardous
liquid gathering lines must comply with the provisions of this
rulemaking pertaining to hazardous liquid pipelines. Based on comments
received on the NPRM and discussions at the LPAC meeting, however,
PHMSA is requiring that operators of only certain regulated rural
gathering lines--namely, lines that cross bodies of water greater than
100 feet wide, from high water mark to high water mark--install RMVs or
alternative equivalent technologies in accordance with Sec.
195.260(e). PHMSA has required extra valves near such water crossings
for several decades under Sec.  195.260, and similarly applies the
requirements of this final rule to those lines.
    As for low-stress, rural hazardous liquid pipelines, as those are
defined at Sec.  195.12, PHMSA acknowledges that a hazardous liquid
pipeline operating below 20 percent of SMYS is less likely to rupture
than the same pipeline operating at higher pressures. However, a
hazardous liquid pipeline can leak, without rupturing, and cause
significant environmental damage; further, PHMSA accident report data
yields that even low-stress hazardous liquid pipelines have failed.
Accordingly, although the LPAC recommended that PHMSA consider an
exception for low-stress, rural hazardous liquid pipelines in the final
rule, PHMSA is instead requiring that all newly constructed and
entirely replaced low-stress, rural hazardous liquid pipelines with
diameter of six inches or greater, including low-stress hazardous
liquid pipelines in rural areas, install RMVs pursuant to this
rulemaking.
    PHMSA is also clarifying in this final rule that the requirements
pertaining to RMVs or alternative equivalent technologies as outlined
in the NPRM do not apply to gas distribution pipelines. The only
requirements in this rule intended to apply to gas distribution
pipelines are the requirements at Sec.  192.615 for contacting 9-1-1
call centers and at Sec.  192.617 pertaining to post-incident analysis
and implementation of lessons learned. Although PHMSA acknowledges that
there could be safety and environmental benefits from extending
elements of this final rule to gas distribution pipelines, PHMSA
declines to do so in this final rule as such an extension is beyond the
scope of the NPRM and would require additional notice and public
comment, and thus further delay issuance of this final rule. PHMSA will
conduct further study and analysis evaluating which rupture response
and mitigation measures (including, but not limited, those adopted in
this final rule) are most appropriate for gas distribution pipelines.
(iii) Cost-Benefit
    PHMSA analyzed the comments it received on the PRIA and cost-
benefit issues and took them into account when drafting this final
rule. PHMSA addresses those comments within the RIA in the rulemaking
docket.

B. Rupture Definition

1. Summary of Proposal
    In the NPRM, PHMSA proposed to introduce a new definition of
``rupture'' for gas pipelines at Sec.  192.3 meaning any of the
following events that involve an uncontrolled release of a large volume
of gas: (1) A release of gas observed or reported to the operator by
its field personnel, nearby pipeline or utility personnel, the public,
local responders,

or public authorities, and that may be representative of an
unintentional and uncontrolled release event defined in paragraphs (2)
or (3) of this definition; (2) An unanticipated or unplanned pressure
loss of 10 percent or greater, occurring within a time interval of 15
minutes or less, unless the operator has documented in advance of the
pressure loss the need for a higher pressure-change threshold due to
pipeline flow dynamics that cause fluctuations in gas demand that are
typically higher than a pressure loss of 10 percent in a time interval
of 15 minutes or less; or (3) An unexplained flow rate change, pressure
change, instrumentation indication, or equipment function that may be
representative of an event defined in paragraph (2) of this definition.
    Similarly, for hazardous liquid pipelines, PHMSA proposed to
introduce at Sec.  195.2 a definition of ``rupture'' for hazardous
liquid pipelines as any of the following events that involve an
uncontrolled release of a large volume of hazardous liquid or carbon
dioxide: (1) A release of hazardous liquid or carbon dioxide observed
and reported to the operator by its field personnel, nearby pipeline or
utility personnel, the public, local responders, or public authorities,
and that may be representative of an unintentional and uncontrolled
release event defined in paragraphs (2) or (3) of this definition; (2)
An unanticipated or unplanned flow rate change of 10 percent or greater
or a pressure loss of 10 percent or greater, occurring within a time
interval of 15 minutes or less, unless the operator has documented in
advance of the flow rate change or pressure loss the need for a higher
flow rate change or higher pressure-change threshold due to pipeline
flow dynamics and terrain elevation changes that cause fluctuations in
hazardous liquid or carbon dioxide flow that are typically higher than
a flow rate change or pressure loss of 10 percent in a time interval of
15 minutes or less; or (3) An unexplained flow rate change, pressure
change, instrumentation indication or equipment function that may be
representative of an event defined in paragraph (2) of this definition.
    For both definitions, PHMSA added a note stating that ``rupture
identification'' was to occur when a rupture, as defined above, was
first observed by, or reported to, pipeline operating personnel or a
controller.
2. Comments Received
    For both gas and hazardous liquid pipelines, commenters stated that
the proposed definitions are unclear in many respects and that the
proposed definition of rupture emphasized the sources of information an
operator might use to identify a rupture, like notifications to an
operator, as opposed to establishing workable criteria for determining
what qualifies as a rupture.
    Some commenters suggested that the release criteria PHMSA used to
define a rupture were impractical and do not account for differences in
pipeline system operation and monitoring capabilities. Some commenters
further suggested that PHMSA proposed technically infeasible detection
sensitivities.
    Individual operators and trade associations provided alternative
definitions for ``rupture'' and ``rupture identification'' or provided
editorial changes to the definitions. Other commenters, such as the
NTSB, noted that elements of the definition, including the terms
``large-volume'' and ``uncontrolled release,'' could be interpreted in
several ways and could benefit from clarification.
    Northern Natural Gas Company stated that the proposed definition of
a rupture is too restrictive, noting that their pipeline system
consists of pipelines with a series of branch or lateral lines which
serve power plant or industrial customers that may change operating
status several times per day with subsequent start-ups and shutdowns.
They added that many of these start-ups and shutdowns would meet the
proposed threshold defining a rupture, and for them to develop and
maintain documentation in advance for all of these scenarios would be
burdensome, extensive, time consuming, expensive, and would not result
in improved pipeline safety. Therefore, they recommended that the
language defining a rupture be changed to an unanticipated or unplanned
flow rate change or pressure loss of 25 percent occurring within 30
minutes, or that the operator should be allowed to establish specific
rupture criteria for each pipeline and maintain technical
justification.
    TPA stated that there should be some recognition of the difficulty
of determining a 30 percent pressure drop on certain transmission
pipelines, such as where a natural gas-fueled electric generation plant
is located on a segment. On pipeline segments such as these, they
stated, significant swings in pressure are not uncommon as the
generation plant starts up, and these swings in pressure can occur with
little notice.
    Emerson Process Management Actuation Technologies, a manufacturer
of pipeline valve operating systems and controls (including ASVs),
noted that their clients typically use an actuation set point of a 20
to 30 psi pressure drop per minute with the goal of sensing a rupture
but not being too sensitive to ``risk a false valve closure.'' This
commenter proceeded to assert that the proposed definition could
require ASV set points that are more sensitive to pressure changes than
currently used within industry.
    Pertaining to hazardous liquid pipelines, AFPM stated that defining
a rupture as a 10 percent pressure loss is not feasible for all
locations, stating that the proposed language would force operators to
consider pressure drops as ruptures when such pressure drops would
likely not constitute an actual rupture event. They stated further that
such a measure could lead to unnecessary incident reports, even in
instances when no product is released, and suggested that a rupture is
better defined as a percentage of flow leaving the pipeline, typically
defined as 50 percent of receipt flows or higher.
    Magellan Midstream Partner, L.P. stated that the proposed rule is
not clear regarding the impact of alarm persistence on determining
whether a rupture is occurring and whether any momentary pressure
change of 10 percent constitutes a rupture, or if the 10 percent drop
would be sustained continuously over 15 minutes. Magellan also
suggested that, since there are several scenarios in any given pipeline
operation that could contribute to pressure drops and flow rates, a
rupture should not be defined by a single variable, such as pressure or
flow, but be inclusive of multiple indications that, evaluated
collectively, would provide for a rupture signature.\36\
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    \36\ Including pressure, temperature, meter flow, product
characteristics, and geometry of the pipeline.
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    OptaSense stated that operators should rely on monitoring systems
that alert them of significant events with immediacy and actionable
detail to mitigate the harmful consequences of a rupture rather than
relying on third-party notification. On the other hand, TPA stated that
the differences in the sophistication of various operators' pressure
monitoring capabilities and differing granularity of monitored pressure
points, combined with the short response times in the proposed rule,
support some broadening of the definition of rupture to include
notifications from first responders and the public. TPA added that
these notifications would need some provision for operator
confirmation. Magellan Midstream Partner, L.P. suggested that the
proposed rule, as

written, creates the potential for numerous false rupture alarms that
could impact an operator's safety culture and desensitize an
organization to the heightened awareness and urgent response that a
rupture alarm should create.
    Commenters also suggested PHMSA consider allowing operators to
establish specific rupture notification criteria for individual
pipelines based on a pipeline's unique operating environment and
parameters rather than establishing one-size-fits-all criteria.
    INGAA et al. stated that the proposed definition of rupture does
not take into account that operators' natural gas systems and their
customers' needs are unique and dynamic. INGAA et al. stated that the
proposed definition arbitrarily establishes set points which require
response and that PHMSA did not provide a technical basis for the 10-
percent-over-15-minutes threshold in the proposed rule. INGAA et al.
added that by unnecessarily triggering rupture response, PHMSA's
proposed 10 percent over 15 minutes criteria may potentially compromise
the reliability of service to customers. INGAA et al. stated that
rather than prescribe a one-size-fits-all rupture criteria, they
recommended that PHMSA direct operators to establish rupture-
notification criteria for individual operating systems and to outline
these criteria clearly within each operator's procedures.
    TC Energy recommended that if PHMSA includes a rate of pressure
drop (ROPD) in the definition of a rupture, that operators should be
allowed to establish their own ROPD that would indicate a rupture. They
stated that the proposed definition of a rupture does not consider that
operators' natural gas systems are unique and dynamic.
    Similarly, API/AOPL and GPA Midstream stated that the proposed
definition of rupture relies on one-size-fits-all numerical thresholds
for pressure loss and flow rates that would encompass many scenarios
that are not in fact ruptures (e.g., a power loss at a pump station).
These entities added that PHMSA does not provide any technical
justification for the proposed numeric thresholds and rigid application
of the criteria that could lead to numerous false alarms and
unnecessary valve closures.
    Commenters requested PHMSA clarify and distinguish between the
meanings of the terms ``rupture identification'' and ``notification of
potential rupture'' for both gas and hazardous liquid pipelines. INGAA
et al. stated that the proposed definition of rupture does not address
actual ruptures but rather the notification of potential ruptures, and
PHMSA should therefore re-label this definition as the ``notification
of potential rupture,'' which will also provide clarity in other
sections of the rule. INGAA et al. and NAPSR also stated that PHMSA
should limit the definition of ``rupture'' or ``notification of
potential rupture'' to gas transmission pipelines, enabling PHMSA to
use the terms ``rupture'' and ``notification'' as intended throughout
the rulemaking without continuously qualifying whether the requirements
are applicable to only potential ruptures on gas transmission lines or
to both transmission line ruptures and rupture-like events on gas
distribution lines, such as excavation damages.
    As noted previously, commenters, including API/AOPL and GPA
Midstream, also suggested that PHMSA align the definition of rupture in
this rulemaking with the definition of rupture used in PHMSA's incident
report, noting the existing guidance currently used in the instructions
for the part 195 accident reports state that a rupture occurs when a
pipeline has ``burst, split, or broken and the operation of the
pipeline facility is immediately impaired,'' resulting in an
uncontrolled, large volume release of hazardous liquid or carbon
dioxide. These industry commenters suggested that matching the
definition in the reporting instructions would promote consistency,
make the regulations easier to understand, and avoid unnecessary
compliance burdens. The PST added that if the definition of rupture in
the proposed rule is not the same as the definition of a rupture for
incident and accident reporting purposes, it will make it impossible to
track the effectiveness of this rule over time and to know whether this
rule is driving safety.
    In response to these comments, PHMSA provided the Committees in
advance of their July 22-23, 2020 meetings alternative language for
consideration that would substitute the term ``notification of
potential rupture'' for the definition of ``rupture'' proposed in the
NPRM.
    The Committees unanimously recommended that PHMSA adopt this
substitute language as presented and recommended by PHMSA staff at the
meeting. However, the LPAC also recommended PHMSA remove from the
second criterion under the part 195 definition of ``notification of
potential rupture'' any reference to a specific pressure loss-rate
threshold, instead recommending that this criterion refer only to
operator observation of an unanticipated or unplanned pressure loss
outside of a pipeline's normal operating parameters as defined in the
operator's procedures.
3. PHMSA Response
    PHMSA acknowledges that having a clear definition is essential for
successful implementation of the rule and considered the varying
suggestions provided by commenters to clarify terms and improve
understanding of, and compliance with, the final rule. Therefore, PHMSA
has changed the proposed definition of ``rupture'' to a definition of
``notification of potential rupture'' as proposed to and recommended by
the Committees. PHMSA intended for the definition of a ``rupture'' to
provide operators with a standard to initiate rupture-mitigation
measures consistently and promptly and notify emergency responders of a
rupture event. PHMSA acknowledges, however, that operator response
actions are more appropriately initiated on ``notification of potential
rupture'' than on ``rupture'' as suggested by the NPRM. Indeed, the
experience of the rupture events in San Bruno, CA, and Marshall, MI,
underscore there can be a significant time lag between notification of
indicia of a potential rupture and verification of a rupture. PHMSA has
consequently, in this final rule, recharacterized the NPRM definition
of ``rupture'' as a ``notification of potential rupture.''
    PHMSA declines, however, to further modify the second criterion of
the definition of ``notification of potential rupture'' to remove the
NPRM's reference to a 10-percent-pressure-loss-within-15-minutes
threshold as recommended by the LPAC. PHMSA's Accident Investigation
Division has reviewed ruptures that have occurred the past several
years that PHMSA has investigated and finds this to be an appropriate
requirement. In certain cases, for example, operator pressure charts
provided to PHMSA following pipeline ruptures showed pipelines
operating at approximately 850 psig rapidly fall to approximately 100
psig. Another pipeline went from operating at 1,160 psig to 0 psig. In
PHMSA's experience, unexpected pressure-loss events that are greater
than 10 percent within 15 minutes are not routine events and are often
indications a rupture has occurred. However, because PHMSA acknowledges
that operators may have conditions or considerations that would cause
pressure swings in excess of 10 percent within 15 minutes, PHMSA has
introduced language permitting operators to document in their written
procedures the need for alternative pressure-loss-rate thresholds due
to the unique pipeline flow

dynamics resulting from changes in demand. This final rule does not
contemplate that operators must submit those written operating
procedures to PHMSA in advance for notification or approval. PHMSA
furthermore submits that operator concerns regarding the ``one-size-
fits-all'' approach of this numerical threshold or the difficulty in
predicting pressure drops given the diverse and variable demands on
their systems may also be addressed by the qualifying language that any
such pressure loss must be ``unanticipated or unexplained.''
    PHMSA initially considered including the criteria for a
``notification of potential rupture'' within the definition sections of
parts 192 and 195 (Sec. Sec.  192.3 and 195.2, respectively) but found
such an approach challenging. First, PHMSA found it unwieldy to include
such detailed criteria in a definition section that has no enumerated
paragraphs. Second, because the criteria also include requirements,
PHMSA determined that the definition, including the criteria, would be
more appropriately located in an operative section of the regulations.
PHMSA understands the approach taken in this final rule provides
improved clarity and enforceability. PHMSA used a similar approach when
developing the definition of an ``unusually sensitive area'' in part
195. Therefore, in this final rule, PHMSA has established a definition
for the term ``notification of potential rupture'' and has promulgated
the criteria for that definition in Sec. Sec.  192.635 and 195.417 for
gas pipelines and hazardous liquid pipelines, respectively. PHMSA has
also made editorial corrections clarifying the definitional criteria
and identifying indicia--including explosions and fires in the
immediate vicinity of a pipeline--discussed in the NPRM and during the
Committee meetings as potential consequences (and therefore indicia) of
a rupture.
    PHMSA acknowledges the value in aligning any regulatory definition
of the term ``rupture'' with the definitions in its parts 192 and 195
incident/accident reporting forms. However, PHMSA has decided against
codifying any regulatory definition of ``rupture'' in this final rule.
Should PHMSA consider introducing a regulatory definition of
``rupture'' in a future rulemaking, it will endeavor to ensure
consistency between any definition in the Federal Pipeline Safety
Regulations and the incident and accident reporting forms.

C. Rupture Identification Definition and Timeframe

1. Summary of Proposal
    In the NPRM, PHMSA proposed new provisions (Sec. Sec.
192.634(c)(1) and 195.418(c)(1)) requiring operators installing RMVs or
alternative equivalent technology to isolate a ruptured pipeline
segment as soon as practicable, but within 40 minutes of rupture
identification--defined in the NPRM (Sec. Sec.  192.3 and 195.2) as the
initial report to pipeline operators, or their initial observation, of
a rupture. PHMSA also solicited comments on whether to oblige operators
to have procedures to identify a rupture event within 10 minutes of the
initial notification to the operator. These requirements would apply to
both gas and hazardous liquid pipelines.
2. Summary of Comments Received
    API/AOPL, GPA Midstream, KOGA, Magellan Midstream Partner, L.P.,
and TC Energy Corporation stated that PHMSA should add a separate
definition for the term ``rupture identification'' to specify that
rupture identification occurs when a pipeline operator has sufficient
information reasonably to determine that a rupture occurred. Some of
these industry commenters provided alternative definitions or editorial
suggestions to that end.
    API/AOPL stated that the rupture identification concept is highly
important in establishing the extent of an operator's obligations under
the new regulations. They suggested, along with GPA Midstream, that
adding a separate definition for ``rupture identification'' that is
based on a reasonableness standard is preferable to the NPRM's approach
of defining a ``rupture'' by reference to a list of information that
may be indicative, but not conclusive, of whether there is indeed a
rupture.
    Northern Natural Gas Company stated that a 10-minute time limit for
determining whether there is a rupture can create uncertainty in the
initial actions that must be undertaken by natural gas transmission
pipeline operators upon initial notification, and should be eliminated;
Northern Natural Gas Company suggested that the final rule would be
better focused on the time to commence shut-off of RMVs or alternative
equivalent technology. Similarly, TC Energy Corporation called on PHMSA
to remove the 10-minute rupture identification requirement entirely,
and instead revise the regulatory text to mirror language in the NPRM
preamble requiring operators to respond to a rupture as soon as
practicable by closing rupture-mitigation valves, with complete valve
shut-off and segment isolation within 40 minutes after rupture
identification.
    INGAA et al. and TC Energy Corporation stated that PHMSA should
eliminate the 10-minute identification requirement because the 40-
minute response standard is sufficient to ensure safety in HCAs and
Class 3 and Class 4 locations. INGAA et al. further stated that the
decision to shut down a pipeline should not be rushed to meet an
arbitrary 10-minute threshold because it risks significant service
disruptions for natural gas customers. They added that operators should
be provided the necessary time to determine whether a pipeline needs to
be shut down.
    For hazardous liquid pipelines, API/AOPL stated that the
feasibility of a 10-minute rupture identification requirement is highly
dependent on the location of the pipeline. They further stated that
imposing a 10-minute rupture identification requirement for pipelines
in remote or difficult-to-access areas will effectively force operators
of such pipelines to err on the side of being overly-conservative in
responding to events as ruptures. Both API/AOPL and GPA Midstream
stated that this requirement would disrupt operations, is too
restrictive, and could lead to adverse consequences. API/AOPL requested
that PHMSA eliminate the rupture identification timeframe or provide a
longer period for rupture identification. Similar to comments made for
gas transmission pipelines, GPA Midstream stated that, rather than
providing a 10-minute deadline for rupture identification, PHMSA should
provide operators with a 40-minute total response time for closing
RMVs, manual valves, or equivalent technology following a rupture.
    TPA stated that the 10-minute requirement for identifying a rupture
and contacting first responders is not feasible because of the need to
determine the existence of a rupture as the trigger for the
determination of the start of the response time. TPA stated that
existing emergency procedures and damage prevention procedures at
Sec. Sec.  192.615 and 195.402 already contain requirements for the
timely contact of emergency responders and calls to 9-1-1 numbers, so
the 10-minute notification requirement in these provisions is
duplicative and unnecessary, and recommended that this requirement be
deleted from the proposed rule. An individual, on the other hand,
agreed that the time to identify a rupture should be no more

than 10 minutes, and that emergency services must be notified right
away.
    At the Committee meetings on July 22 and 23, 2020, both the GPAC
and the LPAC unanimously recommended that PHMSA eliminate the 10-minute
rupture identification requirement because of the practical
difficulties of prescribing a universal 10-minute rupture
identification timeline notwithstanding the variety of pipeline
locations and operational environments. In conjunction with this
recommendation, the Committees also recommended that PHMSA require RMVs
to be closed ``as soon as practicable'' within 30 minutes of ``operator
identification of a rupture'' and that PHMSA require operators to
document a method for rupture identification in their written
procedures.
3. PHMSA Response
    PHMSA is adopting in this final rule at Sec. Sec.  192.3 and 195.2
effectively identical regulatory definitions for ``notification of
potential rupture'' that reflect editorial revisions to the definitions
endorsed by the GPAC and LPAC. PHMSA notes that its decision to re-cast
the NPRM definition of ``rupture'' as the term ``notification of
potential rupture'' reflects that timely and effective rupture
mitigation demands operators undertake certain actions on notification
of common indicia of a rupture. Effective and timely rupture mitigation
also demands operators take action on confirming, or identifying, that
a rupture is in progress.
    The definition for ``notification of potential rupture'' allows an
operator to consider the different pipeline operating characteristics,
diverse potential rupture mechanisms, and information of varying
quantity and quality in evaluating whether a rupture is, in fact, in
progress, and whether additional mitigation measures are necessary.
PHMSA believes this definition is flexible enough to help ensure
operators reach an informed determination on whether a rupture is in
progress. However, PHMSA has backstopped this flexibility by requiring
within revisions to each of Sec. Sec.  192.615 and 195.402 that each
operator have written procedures specifying its methodology for
identifying a rupture on receipt of a notification of a potential
rupture. The communication of ruptures to 9-1-1 or other public safety
officials was always meant to be broadly applicable to all pipeline
operators--the provisions were placed in the emergency response section
of the regulations applicable to all operators, and the GPAC and LPAC
each recognized this intent when recommending that the proposed
provisions for communicating with 9-1-1 applied to all ruptures,
without exception. An operator cannot properly and promptly coordinate
and share information with the appropriate public safety authorities
regarding event location and planned and actual responses to an
emergency if they do not have a procedure for identifying a rupture
upon the notification of a potential rupture.
    Consistent with the Committees' recommendations, PHMSA has decided
against including within this final rule the 10-minute global rupture
identification time interval proposed in the NPRM. Although PHMSA
understands that a 10-minute rupture identification timeline is
achievable based on currently available technology, after reviewing the
written comments submitted in this proceeding, and the discussions
during the Committee meetings, PHMSA has concluded that the NPRM's one-
size-fits-all approach to rupture identification could be challenging
in light of the diversity of pipeline operational conditions and
customer requirements.
    However, PHMSA remains concerned that, in the absence of a minimum
rupture identification time interval, a scenario similar to those that
played out during the Marshall, MI, and San Bruno, CA rupture events--
in which there were extended delays in rupture identification and
response despite multiple indicia of a potential rupture--could happen
again. With that in mind, PHMSA had considered triggering this final
rule's RMV operation response actions set forth in Sec. Sec.  192.636
and 195.419 on notification of potential rupture rather than rupture
identification. PHMSA has, however, declined to adopt such an approach
in this final rule to avoid further procedural delays in realizing the
safety benefits of a rulemaking that has been over a decade in the
making here at PHMSA--which effort commenced over 40 years after the
NTSB highlighted the public safety benefits from operators'
installation of readily-available technologies such as RMVs on
pipelines.\37\
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    \37\ See Homendy, ``San Bruno Victims and Their Families Deserve
Long-Overdue Action'' (Sept. 9, 2020), https://safetycompass.wordpress.com/category/infrastructure/ (last visited
Nov. 8, 2021) (referencing NTSB, PSS-71-1, Special Study of Effects
of Delay in Shutting Down Failed Pipeline Systems and Methods of
Providing Rapid Shutdown (Dec. 31, 1970), https://www.ntsb.gov/safety/safety-studies/Documents/PSS7101.pdf).
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    As a result, PHMSA may, in future rulemakings, consider whether it
is appropriate to key operator RMV operation response actions to
notification of potential rupture. In the interim, PHMSA has in this
final rule codified at Sec. Sec.  192.615(a)(12) and 195.402(e)(4)
language within the NPRM expressing its expectation that operators
will, upon notification of a potential rupture, identify whether there
is indeed a rupture by reference to written procedures. Operators
implementing this final rule should ensure those written procedures
incorporate common-sense elements including, but not limited to, waiver
of any requirements for specific pipeline personnel to conduct on-scene
investigation of a potential rupture if an operator receives one or
more of the following: Multiple or recurring instrument indications
(pressure readings, alarms, etc.) of potential ruptures; pressure drops
significantly in excess of the minimum thresholds in Sec. Sec.
192.635(a)(1) and 195.417(a)(1); \38\ and reports of rupture indicia
from on-scene, credible sources (e.g., on or off-duty pipeline operator
personnel, sheriff or police officers, fire department personnel, or
other emergency response personnel). PHMSA understands this reading of
its revisions at Sec. Sec.  192.615(a)(12) and 195.402(e)(4) to be
consistent with operators' obligations elsewhere in Sec. Sec.
192.615(a) and 195.402(e) (as revised) to take ``necessary actions to
minimize hazards of released [commodity] to life, property, or the
environment.'' PHMSA further notes that any risks to the public and the
environment arising from delays in rupture identification for operators
installing RMVs under this final rule would be further reduced by each
of (1) language in Sec. Sec.  192.615 and 195.402 requiring operators
to ensure that their protocols identify ruptures ``as soon as
practicable'' and (2) language at Sec. Sec.  192.636 and 195.419
imposing demanding timelines--``as soon as practicable,'' but not to
exceed 30 minutes from rupture identification--for operation of RMVs
following rupture identification.
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    \38\ PHMSA submits that operators may be able to leverage other
provisions in this final rule (Sec. Sec.  192.636(d)-(e) and
195.419(d)-(e)) pertaining to upstream/downstream pressure
monitoring to support timely rupture identification without the need
for on-scene investigation of a potential rupture.
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D. RMV Installation; RMV Closure Timeframe

1. Summary of Proposal
    In the NPRM, PHMSA proposed to require that all valves on newly
constructed or entirely replaced onshore gas transmission and gathering

pipelines that have diameters greater than or equal to 6 inches be RMVs
or an alternative equivalent technology. Operators seeking to use an
alternative equivalent technology in lieu of an RMV would have needed
to submit a notification to PHMSA demonstrating that their preferred
technology would provide an equivalent level of safety to an RMV. And
should an operator seek to use a manual valve as an alternative
equivalent technology, the operator would also have had to demonstrate
that installation of an RMV would not be economically, technically, or
operationally feasible. All valves installed per this proposal would
meet the new rupture-mitigation standards proposed in Sec.  192.634 and
isolate a ruptured pipeline segment within 40 minutes of rupture
identification.
    Similarly, for hazardous liquid pipelines, PHMSA similarly proposed
to require that all valves on newly constructed and entirely replaced
onshore hazardous liquid pipelines that have diameters greater than or
equal to 6 inches be RMVs or alternative equivalent technology.
Operators seeking to use an alternative equivalent technology in lieu
of an RMV would have needed to submit a notification to PHMSA
demonstrating that their preferred technology would provide an
equivalent level of safety to an RMV. And should an operator seek to
use a manual valve as an alternative equivalent technology, the
operator would also have had to demonstrate that installation of an RMV
would not be economically, technically, or operationally feasible. All
valves installed under this proposal would meet the new rupture-
mitigation standards proposed in Sec.  195.418 and isolate a ruptured
pipeline segment as soon as practicable, but within 40 minutes of
rupture identification.
2. Comments Received
    The PST stated that the proposed rule did not provide sufficient
rationale regarding how PHMSA arrived at a 40-minute shutdown
requirement, other than a suggestion that it is ``reasonable.'' They
stated that they have seen spill response plans for hazardous liquid
pipelines claiming that failures isolated within 15 minutes constitute
an operator's worst-case discharge. If those are accurately identified
as the worst-case discharges, the PST noted, then valves must be able
to close that fast or even more quickly. They stated that PHMSA's
determination of the maximum allowable shut-off period should be
justified by data relating to the speed with which automatic valves can
shut, and if they can shut more quickly, then the maximum allowable
valve closure period should be shortened to that length of time.
Similarly, the NTSB suggested that the 40-minute valve closure time
period is longer than expected for remote or automatic valves. The NTSB
suggested that, if PHMSA determined that shut-off valves are not
capable of isolating pipeline segments in less than 40 minutes, every
facility response plan calculating the worst-case discharge based on a
valve closure of less than 40 minutes after rupture identification
should be re-evaluated.
    Conversely, Northern Natural Gas Company asserted that the
requirement for closing a valve to isolate a rupture within 40 minutes
does not allow adequate time for the pipeline controller to evaluate
the nature of the pressure change, determine if there is an emergency,
or identify the actions needed to mitigate the emergency. Therefore,
Northern Natural Gas Company recommended PHMSA change the rupture
identification and valve shut-off period to 60 minutes total. It stated
that a 40-minute valve closure requirement could result in too-rapid
decisions to shut-in pipeline segments, causing unnecessary outages,
unanticipated pressure changes, and potential damage to the pipeline
system. It also stated that, within the States where it operates,
unplanned, sudden outages could cause major problems with prolonged
loss of heat to residences, businesses, and government facilities as
well as an interruption of electric power generation and industrial
processes.
    INGAA et al. recommended that PHMSA apply the 40-minute valve
closure time only to pipelines in HCAs and Class 3 and Class 4
locations to allow more flexibility in remote areas, noting
specifically that achieving valve closure within 40 minutes is
typically more challenging in remote areas. They noted that operators
are likely to consider the use of manual valves in remote areas because
an ASV, RCV, or equivalent technology would be economically,
technically, or operationally infeasible, as it can be difficult to
provide power or communications to automated valves in remote areas.
INGAA et al., further noted that pipelines traverse a multitude of
geographies, including locations that cannot safely be reached within
40 minutes, particularly during winter months.
    Similarly, AFPM and other commenters representing hazardous liquid
pipeline operators also requested that PHMSA consider flexibility for
response time in remote areas where manual valves are located, stating
that, according to information submitted by AFPM members after a review
of their respective systems, manual valve response times in certain
scenarios would potentially exceed 40 or 60 minutes. AFPM stated that
the increased response time is due to the location of field employees
and their ability to reach remote locations, and that some valves may
take up to 10 to 20 minutes to close once personnel are at the valve
site. Therefore, these commenters stated that manual valves installed
in accordance with the RMV installation requirements should not need to
meet the proposed 40-minute valve closure standard.
    GPA Midstream, like other commenters, provided specific regulatory
text for streamlining the requirements related to the valve closure
period. GPA Midstream also recommended that operators be allowed to
seek authorization from the Associate Administrator for Pipeline Safety
to use an alternative shut-off time in appropriate cases, stating that
there may be circumstances where an operator cannot meet the 40-minute
shut-off time.
    INGAA et al. asserted that the 40-minute response time would not be
practicable or appropriate to apply to existing pipelines, should PHMSA
consider such a proposal in a future rulemaking. INGAA et al. claimed a
40-minute closure time is on the leading edge of what is practicable
under currently-available technologies that could be applied to new and
replaced pipelines. They noted that multiple PHMSA special permits
contain a 60-minute valve closure time requirement, and operators have
proactively taken steps to attain the 60-minute response target while
the current rulemaking has been pending for almost a decade.
    Further, INGAA et al. stated that, even for new and replaced
pipelines, attaining the 40-minute valve closure time will push the
limit of what is currently technologically and operationally possible.
They noted that for almost 60 percent of PHMSA-reportable ruptures from
2010 to 2019, the response time was greater than 40 minutes, which,
they claimed, would indicate any response time shorter than 40 minutes
for new and replaced pipelines would be infeasible. Similarly, Magellan
Midstream Partners L.P. stated that 40 minutes is not a practical
travel time to manual valves that have been installed in accordance
with the RMV installation requirements.
    Commenters also suggested PHMSA should provide an allowance for
scenarios where the operator and

emergency responders agree not to shut an RMV following a rupture.
    At the Committee meetings on July 22 and 23, 2020, the Committees
unanimously endorsed the NPRM's RMV closure requirements as
``technically feasible, reasonable, cost effective and practicable''
provided that PHMSA reduce the RMV closure time to 30 minutes in
combination with eliminating the proposed 10-minute rupture
identification standard. PHMSA understands that endorsement to reflect
Committee discussions in which industry representatives focused their
objections to the NPRM on the difficulty of meeting the 10-minute
rupture identification timeline given differences in environmental
conditions and operational requirements within their systems.
    Further, the GPAC recommended PHMSA review the issue of allowing
certain valves to remain open during emergency situations based on the
Committee discussion and public comments and ensure that the integrity
of the rule was not compromised and would minimize environmental
damage.
    The GPAC also recommended PHMSA allow, for natural gas pipelines,
manual valves installed as alternative equivalent technology in non-HCA
Class 1 locations to exceed the 30-minute closure time requirement only
if the operator submits within its notification to install such valves
as alternative equivalent technology a specific closure time for those
manual valves. For hazardous liquid pipelines, the LPAC recommended a
similar limitation apply to manual valves used as alternative
equivalent technology in remote, non-HCA locations.
3. PHMSA Response
    As a part of developing the NPRM, PHMSA considered what would make
it economically, technically, or operationally infeasible to install or
use an ASV, RCV, or equivalent technology. For instance, PHMSA proposed
to limit the installation of ASVs, RCVs, equivalent technologies
(including, potentially manual valves) to pipelines of 6 inches and
greater because, while rupture-mitigating technologies are commercially
available for pipelines as small as 2 inches in diameter, PHMSA
determined at the time that it is unlikely the safety and environmental
benefits on those pipelines would justify the costs of installing the
technology. While PHMSA applies these requirements to pipelines of 6
inches in this final rule, PHMSA may consider expansion of this
application for smaller pipeline diameters in a future rulemaking.
PHMSA would analyze the costs and potential safety and environmental
benefits of an expansion in any such rulemaking.
    PHMSA also noted in the NPRM that examples of where it might be
infeasible to install ASVs or RCVs included locations that may have
issues with communication signals, power sources, space for actuators,
or physical security. These locations can vary and are not limited to
certain types of terrain. Certain urban areas, for example, might have
access to power sources but might not have adequate physical space for
the necessary valve actuators. Certain rural areas, on the other hand,
might have issues with maintaining continuous communication signals or
might have difficult-to-access valves. Other reasons that installation
of RMV may be infeasible identified in written comments and during
GPAC/LPAC meetings include difficulties in obtaining required access
rights or permits. The COVID-19 global health emergency has also
exacerbated labor and component constraints, drawing out procurement
timelines and increasing costs.
    However, given that these valve installation requirements apply to
new construction and replacement projects whose routes and components
are planned out years in advance, PHMSA does not believe that there
should be major economic, technical, or operational constraints
impacting valve installation. Final Environmental Impact Statements for
pipeline projects proposed after the passage of the Pipeline Safety Act
of 2011 have shown that operators are committing to installing a
substantial number of remotely operated and monitored valves. However,
PHMSA does not want to preclude unforeseen challenges or conditions
operators may face in installing valves pursuant to this rulemaking,
and so developed an advance notification process at Sec. Sec.  192.18
and 195.18, by which operators can (subject to PHMSA's review) make a
site-specific case before installation of an alternative equivalent
technology that (1) the technology would provide an equivalent level of
safety to an RMV, and (2) if that proposed alternative equivalent
technology is a manual valve, installation of an RMV would be
economically, technically, or operationally infeasible. Similarly,
PHMSA has in this final rule established procedural machinery allowing
operators to request extensions of compliance timelines for
installation of RMVs and alternative equivalent technology is such
timelines are economically, technically, or operationally infeasible
for near-term construction and replacement projects.
    PHMSA also considered what would make a technology ``alternatively
equivalent'' to the ASVs and RCVs that the statute specifically listed.
In developing the NPRM, and given the circumstances noted above, PHMSA
wanted to provide operators with flexibility to install the appropriate
valve or technology based on the unique circumstances at each site
while still ensuring that such valves or technologies would close as
soon as practicable.\39\ In the NPRM, PHMSA also noted that, in the
Marshall, MI incident, the rupture-mitigating valves the operator had
equipped on the line were functionally useless until the operator was
able to identify the rupture. Therefore, PHMSA believed that any
proposed regulation would need to pair a valve installation requirement
with a standard delineating when an operator must identify a rupture
and actuate those valves. PHMSA did not consider it appropriate to
assign different valve closure times to different rupture-mitigating
valves or technologies, because doing so would have made compliance and
enforcement difficult.
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    \39\ PHMSA notes that, as contemplated by the NPRM, such
alternative technologies can include manual valves if an operator
makes the requisite showings of safety equivalence and technical,
operational, or economic infeasibility of RMV installation. See,
e.g., 85 FR at 7178.
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    PHMSA believed that, by setting a valve and technology closure
standard for operators to meet, it would contribute to PHMSA's review
of notifications contending that an alternative technology would
provide an equivalent level of safety to an RMV. This approach allows
operators to install the most appropriate valve or technology given
site specifics, and it also prevents PHMSA from inadvertently
restricting the development or use of promising rupture-mitigating
technologies by imposing prescriptive requirements on the use of
``equivalent technology,'' which was not defined by the statute. As
discussed throughout the NPRM and this final rule, PHMSA does expect
operators to be able to close certain valves or technologies faster
than others, and has included requirements for operators to close RMVs
or alternative equivalent technologies ``as soon as practicable'' but
within the required timeframe.
    PHMSA maintains that the proposed 40-minute RMV closure standard is
achievable with current technology, and it would be a significant
improvement over the 95 minutes it took PG&E to

close the necessary valves during the incident at San Bruno, CA. As
discussed in the NPRM, recent PHMSA-issued special permits for non-
looped pipelines contemplate those lines will be equipped with
isolation valves that can be closed in 30 minutes or less. PHMSA
proposed a higher ceiling (40 minutes) in the NPRM because many gas and
hazardous liquid systems have several incoming and outgoing product
receipts and deliveries or tie-ins and, in some situations, multiple
loop lines; establishing a one-size-fits-all requirement for valve
closure times on all gas and hazardous liquid pipeline systems can be
challenging based on the configuration of those systems. In the NPRM,
PHMSA also noted that it considered valve closure times between 30 and
60 minutes based on comments on the ANPRMs and work on the
``Alternative MAOP'' rulemaking.\40\
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    \40\ 73 FR 62147 (Oct. 17, 2008).
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    PHMSA notes that it developed the 40-minute RMV closure standard in
the NPRM accounting for the potential need to include manual valves as
alternative equivalent technology due to site-specific concerns; PHMSA
assumed and expects ASVs and RCVs will be closed much faster. In the
NPRM, PHMSA proposed to allow operators to use manual valves as an
alternative equivalent technology, with a notification to PHMSA
demonstrating that installing an ASV or RCV would be economically,
technically, or operationally infeasible, and that a manual valve would