[Federal Register Volume 87, Number 68 (Friday, April 8, 2022)]
[Rules and Regulations]
[Pages 20940-20992]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-07133]



[[Page 20939]]

Vol. 87

Friday,

No. 68

April 8, 2022

Part II





Department of Transportation





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





Pipeline and Hazardous Materials Safety Administration





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





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

[[Page 20940]]


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

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.

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

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 713-272-2855. General 
information: Robert Jagger, Senior Transportation Specialist, by 
telephone at 202-366-4361.

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 20941]]

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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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; <SUP>8 9</SUP> 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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

[[Page 20942]]

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\
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \14\ 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------

    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

[[Page 20943]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 20944]]

install ASVs or RCVs in HCAs and Class 3 and 4 locations, with the 
valve spacing based on risk analysis.
---------------------------------------------------------------------------

    \18\ See supra note 3.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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.

[[Page 20945]]

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

[[Page 20946]]

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).

[[Page 20947]]

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

[[Page 20948]]

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

[[Page 20949]]

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,

[[Page 20950]]

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\
---------------------------------------------------------------------------

    \36\ Including pressure, temperature, meter flow, product 
characteristics, and geometry of the pipeline.
---------------------------------------------------------------------------

    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

[[Page 20951]]

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

[[Page 20952]]

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

[[Page 20953]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 20954]]

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

[[Page 20955]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 20956]]

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\
---------------------------------------------------------------------------

    \40\ 73 FR 62147 (Oct. 17, 2008).
---------------------------------------------------------------------------

    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 
provide an equivalent level of safety to an RMV. The NPRM's proposal 
reflected PHMSA's belief it would be reasonable to apply a 40-minute 
valve closure standard to provide time (if needed) for operators to get 
personnel on-site to close any necessary manual valves.
    As discussed elsewhere in this document, both the GPAC and the LPAC 
each unanimously voted to characterize a shortened valve closure time 
as ``technically feasible, reasonable, cost-effective, and 
practicable'' provided that the NPRM's prescriptive timeframe for 
rupture identification was eliminated. PHMSA acknowledges that a faster 
valve-closure standard would provide additional environmental and 
public safety benefits and has revised this final rule to require a 30-
minute maximum valve-closure time, measured from rupture 
identification--with an emphasis that this is a ceiling whereas the 
actual requirement is ``as soon as is practicable.'' As noted by some 
of the commenters, many operators indicate ``worst case scenarios'' of 
15 minutes.
    Accordingly, PHMSA is requiring any RMVs and alternative equivalent 
technology installed pursuant to this final rule be closed ``as soon as 
practicable'' but no later than 30 minutes following the identification 
of a rupture. In addition, as suggested in comments from PST, those 
operators that have indicated in their spill response plans a valve 
closure time of less than 30 minutes during a worst-case discharge 
would still have to operate such valves in the time indicated in their 
spill response plan (see Sec.  194.105(b)(1)). If an operator chooses 
to install ASVs as RMVs, they must conduct flow modeling for the 
applicable pipeline segments and any laterals that feed the pipeline 
segment to ensure that the ASV will close within 30 minutes or less 
following rupture identification. The flow modeling must include the 
anticipated maximum, normal, or any other flow volumes, pressures, or 
other operating conditions (including extreme fluctuations in weather 
that might affect operating pressures) that may be, or are anticipated 
to be, encountered during the year, not to exceed a period of 15 
months, and it must be modeled for the flow between the RMVs or 
alternative equivalent technologies, and any looped pipelines or gas 
receipt tie-ins. If operating conditions change in a way that could 
affect the ASV set pressures and the valve closure time after rupture 
identification, an operator must conduct a new flow model and reset the 
ASV set pressures prior to the next review for ASV set pressures in 
accordance with Sec.  192.745. The flow model must include a pressure 
drop/time chart or graph for the segment containing the ASV if a 
rupture event occurs and must show rupture segment isolation as soon as 
is practicable and within 30 minutes of rupture identification. An 
operator must conduct this flow modeling prior to making flow condition 
changes in a manner that could assure that the 30-minute valve closure 
time is achievable. If an operator does not perform this flow modeling 
correctly, the set pressure could be too low, thus rendering a 30-
minute closure time unachievable.
    When conducting flow modeling for ASVs, operators should also 
consider what type of rupture may occur on their system, especially 
whether the rupture may be a pipe-body type or a seam-type failure. The 
flow model detection for a rupture should be based on 0.5 times the 
pipe diameter (or less) pipe area when sizing the pressure drop for a 
rupture.
    Operators also have the option, in lieu of installing RMVs, to 
install alternative equivalent technology with an advance notification 
to PHMSA in accordance with Sec. Sec.  192.18 and 195.18. An operator 
must include, for PHMSA's review, a site-specific technical and safety 
evaluation in its notice consisting of the following information, as 
well as any other information requested by PHMSA in its review of the 
notification: 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. 
Where the operator proposes to use manual valves as alternative 
equivalent technology, its notification to PHMSA must also demonstrate 
that installation of an RMV would be economically, technically, or 
operationally infeasible by reference to factors such as access to 
communications and power; terrain; prohibitive cost; component and 
labor availability; ability to secure required access rights and 
permits; and accessibility to operator personnel for installation and 
maintenance.
    As discussed above, PHMSA is requiring an ``as soon as is 
practicable'' valve closure time (with an absolute ceiling of 30 
minutes), measured from rupture identification pursuant to an 
operator's written procedures, in conjunction with eliminating the 10-
minute rupture identification timeframe. Shortening the time it takes 
for an operator to close a RMV or alternative equivalent technology 
provides a better mitigation standard to protect the public and the 
environment from the consequences of a rupture. PHMSA notes that it has 
seen evidence of operators being able to isolate looped pipeline 
systems in less than 10 minutes--this rule should help ensure this 
timeframe is widely achievable. Operators of hazardous liquid pipelines 
must also consider the shut-down times they use when calculating worst-
case discharges in accordance with Sec.  194.105 and be able to close 
RMVs within that timeframe if it is less than 30 minutes.
    For gas pipelines, some commenters suggested allowing operators to 
exceed the 30-minute closure standard if using manual valves as 
alternative equivalent technology in non-HCA, Class 1 locations, if the 
operator submits a notification demonstrating that installing an RMV 
would be economically, technically, or operationally infeasible. Given 
that non-HCA Class 1 locations are largely rural areas, PHMSA believes 
such a provision would be warranted if the operator could demonstrate 
they could not install

[[Page 20957]]

a compliant valve or technology in those locations. In this final rule 
at Sec.  192.636(g), PHMSA specifies that an operator seeking an 
exemption from the rule's RMV and alternative equivalent technology 30-
minute operation requirement would, within its request submitted under 
Sec.  192.18, have to provide PHMSA for its review, inter alia, with an 
estimated closure time of any manual valve employed as an alternative 
equivalent technology. PHMSA has not included procedural machinery for 
such an exemption from that operation requirement for manual valves 
used as alternative equivalent technology in non-HCA Class 2 locations 
in this final rule, however, because those locations would pose a 
greater risk to public safety: By definition, Class 2 locations have a 
minimum of 10 houses and up to 45 houses in the class location unit 
near the pipeline. The final rule incorporates at Sec.  195.419(g) an 
analogous procedure for certain hazardous liquid pipelines 
(specifically, those that are neither in, nor could affect, an HCA) 
whereby an operator can request an exemption from the 30-minute 
operation requirement at Sec.  195.419(b) when employing a manual valve 
as an alternative equivalent technology; those pipelines, too, pose a 
lower risk to public safety and environment from hazardous liquid 
pipeline segments which are located in, or could affect, an HCA.
    In this final rule, PHMSA does not authorize operators, in 
conjunction with emergency responders, to leave RMVs or alternative 
equivalent technologies open for rupture mitigation or safety during 
emergency response, without first forwarding to PHMSA pursuant to 
Sec. Sec.  192.18 or 195.18 such a request and developing appropriate 
written procedures. PHMSA believes that the need to isolate ruptures is 
paramount--precisely to be able to afford maximum safety for an 
emergency response as well as for mitigation purposes--and that RMVs 
and alternative equivalent technologies should be closed as soon as 
practicable. Any discussions occurring with emergency responders while 
an incident is occurring could lead to unjustified delays in isolating 
ruptures. If an operator has not established the need in their 
operating procedures for not closing valves prior to a rupture, the 
emergency responder(s) would probably not have the appropriate 
information to make such a decision promptly. Commenters at the GPAC 
meeting noted that there might be instances where leaving RMVs or 
alternative equivalent technologies open during emergencies was 
warranted, such as when the pipeline was the sole product source for a 
power plant or a hospital, or where closing a RMV or alternative 
equivalent technology would then have an adverse economic impact on 
other customers downstream. PHMSA has determined that, in situations 
such as these, the potential risks associated with interruption of gas 
supply to particular end users will generally outweigh the value of 
more quickly mitigating the nearly certain catastrophic consequences of 
a pipeline rupture. PHMSA notes that a rupture may itself result in 
interruption of service to critical facilities and electric generators, 
regardless of response actions taken by operators. Further, PHMSA notes 
that bi-directional product flow or the residual volume of product 
downstream of a ruptured pipeline segment can provide operators with 
time to isolate the ruptured pipeline segment while also redirecting 
product flow as necessary to ensure that any disruption to downstream 
facilities would be minimized. PHMSA also contemplates operators will 
appropriately plan for the aforementioned contingencies.
    Based on the GPAC discussion, however, PHMSA has provided in this 
final rule a mechanism for an operator to forward to PHMSA such a 
request. Accordingly, an operator of a gas pipeline may request 
pursuant to Sec.  192.18 to plan to leave an RMV or alternative 
equivalent technology open for more than 30 minutes following rupture 
identification if the operator can demonstrate to PHMSA that closing 
that RMV or alternative equivalent technology would be detrimental to 
public safety. Such a request must be coordinated in advance with 
appropriate local emergency responders, and the operator and applicable 
emergency responders must agree that it would be safe to leave the 
valve open. If PHMSA grants such a request to an operator, that 
operator would be required to have written procedures for determining 
when to leave a RMV or alternative equivalent technology open, 
including all plans for communicating with local emergency responders 
during a rupture event during which the RMV or alternative equivalent 
technology would be left open, and including measures by which the 
operator would minimize environmental impacts.
    Regarding the comments requesting clarification on the meaning of 
``other mitigative actions,'' PHMSA intended this phrase to require 
that operators take whatever action is appropriate to mitigate the 
event, in addition to closing the appropriate RMVs or alternative 
mitigative technologies. The specific actions PHMSA would expect an 
operator to take would be dependent on each unique rupture scenario and 
may include, but are not limited to, the closure of valves on laterals 
used for receipt or delivery and communication with product receipt and 
delivery customers.

E. RMVs

1. Summary of Proposal
    In the NPRM, for gas pipelines, 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 ASVs, RCVs or an alternative equivalent 
technology. Operators seeking to use manual valves as an alternative 
equivalent technology would also need to demonstrate to PHMSA's 
satisfaction that installing an ASV or RCV was economically, 
technically, or operationally infeasible. PHMSA proposed to define the 
statutory phrase ``entirely replaced'' as being where an operator 
replaces 2 or more contiguous miles of pipeline with new pipe. All 
valves installed per this proposal would meet the new rupture-
mitigation standards proposed and isolate a ruptured pipeline segment 
within 40 minutes of rupture identification. PHMSA also proposed that 
new or entirely replaced laterals contributing 5 percent of the total 
volume of the applicable gas line shut-off segment would also require 
RMVs.
    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 RCVs, ASVs, or an alternative equivalent technology. PHMSA 
proposed to permit operators to install manually or locally operated 
valves as alternative equivalent technology only when there were 
economic, technical, or operational feasibility issues precluding the 
installation of ASVs or RCVs and proposed to require operators to 
notify PHMSA as well. 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. Similar to gas transmission 
lines, new or entirely replaced laterals contributing 5 percent of 
hazardous liquid volume would also be required to install RMVs.
    PHMSA also defined the term ``shut-off segment'' in the NPRM as the 
segment of applicable pipe between the RMVs closest to the upstream and

[[Page 20958]]

downstream endpoints of an HCA, a Class 3 location, or a Class 4 
location so that the entirety of these areas is between RMVs. Multiple 
HCAs, Class 3 locations, or Class 4 locations can be contained in a 
single shut-off segment, and all valves installed on a shut-off segment 
are RMVs. While PHMSA did not specifically define the term ``rupture-
mitigation valve'' in the NPRM, it used that term in the NPRM to 
describe the ASVs, RCVs, or alternative equivalent technology installed 
to mitigate ruptures.
    For the proposed construction and replacement requirements, PHMSA 
proposed an implementation timeframe of 12 months following the 
effective date of the rule.
2. Comments Received
(i) ``Rupture-Mitigation Valve'' and Related Definitions
    API/AOPL, GPA Midstream, Magellan Midstream Partner, L.P., and TC 
Energy Corporation recommended that PHMSA add a definition of an RMV 
for clarity. These industry commenters stated that the definition of an 
RMV should explicitly include check valves within its scope and also 
specify the purpose served by these valves, which is to minimize the 
volume of product released following a rupture and mitigate the safety 
and environmental consequences of a rupture. API/AOPL and GPA Midstream 
added that the definition of an RMV should include automated valves, 
alongside ASVs and RCVs, per the GAO report. Other commenters, 
representing hazardous liquid pipelines operators, noted that the 
definition should also contain EFRDs for hazardous liquid pipelines.
    PHMSA also received several comments regarding the use of 
additional technologies and practices. Regarding valve types, industry 
commenters suggested PHMSA should allow operators to use a ``locked-
out'' or ``tagged-out'' manual valve as an alternative equivalent 
technology at crossovers, and allow operators to use a check valve as 
an RMV for laterals used for receipt or delivery, provided that the 
check valve is positioned to stop product flow into the shut-off 
segment. Further, industry commenters suggested that PHMSA should add 
language to the final rule to confirm that locally actuated ASVs would 
be an acceptable alternative for RMVs and that operators could select 
any pipeline (mainline or lateral) or station valve as an RMV as long 
as it complied with the RMV spacing requirements.
    Commenters also had suggestions for definitions related to RMVs, 
including ``shut-off segment'' and ``entirely replaced.'' For ``shut-
off segment,'' commenters recommended defining that term and provided 
assorted editorial suggestions for the definition. Similar comments 
were made for the term ``entirely replaced.''
    Additionally, for the term ``entirely replaced,'' industry 
commenters noted that PHMSA discussed the definition for the term in 
the preamble text but did not include it in the regulatory text. They 
asserted that the definition that PHMSA uses for ``entirely replaced'' 
in the NPRM is not consistent with the plain meaning of that term, as 
meaning ``in every way possible; completely.'' Based on that 
interpretation of the definition of ``entirely replaced,'' these 
commenters stated that replacing a portion of a pipeline would not 
constitute an ``entirely replaced'' pipeline and suggested that, based 
on PHMSA's definition, ``entirely replaced'' could create an incentive 
to make poor engineering decisions based on the potential consequences 
of a segment being ``completely'' replaced.
    The PST stated that PHMSA provided no explanation for how it 
arrived at the 2-mile threshold or whether recent replacement projects 
were tallied to see how many recent projects that distance would 
include or exclude. The PST asserted that choosing a shorter distance 
would include more replacement projects and would therefore result in 
more of the Nation's pipeline systems having the additional protection 
of ASVs or RCVs. The PST also stated that because 2 miles is a long 
distance, it seems an easier distance to design around to avoid 
application of this rule. Therefore, the PST suggested PHMSA establish 
the definition of ``entirely replaced'' based on a replacement length 
of 600 contiguous feet or a length of more than 600 feet of any 
contiguous 1,000 feet, which would be a distance longer than a single 
integrity repair might require but short enough to capture smaller 
replacement projects. The PST stressed the importance of this 
definition due to limitations on changing design and construction 
requirements on existing pipeline systems. Similarly, other commenters 
from the general public suggested that PHMSA should reduce the distance 
for replacement that triggers valve installation to 1 mile of 
contiguous pipeline.
    At the Committee meetings on July 22 and 23, 2020, discussions 
focused on the practicability of NPRM's proposed definition of 
``entirely replaced.'' Pipeline operators generally supported the 2-
mile element of the definition as striking an appropriate balance 
between safety benefits and practical difficulties (e.g., obtaining 
land access rights and permits) associated with installing new RMVs on 
replacement pipelines--provided PHMSA clarify (1) the length of the 
pipeline from which the 2 miles of replaced pipe would be calculated 
was less than each operator's entire system, and (2) the timeframe over 
which those pipeline replacements would be conducted so as to 
accommodate pipeline maintenance planning cycles. The Committees 
unanimously recommended that PHMSA revise the final rule so that the 
``entirely replaced'' standard applies to multiple replacements that, 
in the aggregate, exceed 2 miles of pipeline within a 5-contiguous-mile 
length within a 24-month period. The Committees also unanimously 
recommended PHMSA allow check valves and valves on crossover piping 
that are locked and tagged closed in accordance with operating 
procedures to be used as RMVs. Committee members noted that check 
valves could already be considered an ASV based on their design, and 
that check valves have been used effectively in hazardous liquid 
pipeline systems.
(ii) RMV Applicability
    NAPSR and other commenters requested PHMSA clarify whether the 
proposed requirements would be applicable to low-stress systems, noting 
that rupture risk is greatly reduced for systems that operate at less 
than 20 or 30 percent of SMYS.
    Similarly, the industry associations requested that PHMSA except 
pipelines from the RMV installation requirements where the PIR of those 
pipelines is less than 150 feet. They stated that pipeline diameter 
alone is not an accurate indicator of the potential consequences of a 
rupture, as many pipelines with diameters ranging from 6 inches to 12 
inches operate at pressures low enough that the impact of a rupture 
would be minimal. The industry associations noted that a pipeline's PIR 
reflects both the pipeline size and the operating pressure, and it is 
therefore a better measure of potential consequence than diameter 
alone. Further, the industry associations noted that the 2019 Gas 
Transmission Final Rule \41\ used a PIR of less than or equal to 150 
feet to establish less-stringent requirements for aspects of MAOP 
reconfirmation and pressure reductions.
---------------------------------------------------------------------------

    \41\ 84 FR 52180 (Oct. 1, 2019).
---------------------------------------------------------------------------

    Commenters representing hazardous liquid pipeline operators 
similarly requested that PHMSA exempt pipeline segments that could not 
affect HCAs

[[Page 20959]]

from the requirement for installing RMVs to create the greatest benefit 
for the rule using an HCA-focused approach consistent with the risk-
based philosophy of the Federal Pipeline Safety Regulations.
    For both gas and hazardous liquid pipelines, industry commenters 
requested that PHMSA clarify whether the 5 percent volume contribution 
for determining the need for RMVs on laterals is based on flow rate or 
total volume.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
recommended that PHMSA consider exceptions from the RMV installation 
requirement for pipelines with SMYS of 30 percent or less and for all 
gas transmission and gas gathering pipelines with a PIR equal to or 
less than 150 feet (not for pipeline segments in Class 4 locations) 
considering cost-benefit issues and while maintaining the integrity of 
the rule. For hazardous liquid pipelines, the Committees recommended 
that PHMSA consider exceptions for pipelines 30 percent of SMYS or 
less.
    Further, the GPAC recommended PHMSA consider an exception for Type 
A gas gathering pipelines of 12 inches or less and Type B gas gathering 
pipelines. Both the GPAC and the LPAC recommended that PHMSA consider 
the appropriateness of applying this rulemaking, or a separate 
rulemaking, to gathering lines.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
    With regard to the timeframe for making RMVs operational following 
operators placing pipelines into service, INGAA et al. requested that 
PHMSA provide operators with 14 days rather than the 7-day period 
proposed. They stated that several safety and operational activities 
must take place following the introduction of gas into a new pipeline 
segment, including the testing of control and communication systems, 
evaluating system constraints, and conducting management of change 
processes, which could require more than 7 days to conduct. Some 
commenters from industry also suggested that PHMSA change the 
implementation period for new construction from 12 months after the 
effective date to 24 months.
    At the GPAC and LPAC meetings on July 22 and 23, 2020, the 
Committees unanimously recommended that PHMSA change the implementation 
period of the rule to 24 months after publication date for gas 
transmission and gas gathering pipelines, and consider reducing the 
implementation of the rule to be between 12 and 18 months for hazardous 
liquid pipelines. On both Committees, members representing the public 
(including PST) were initially reluctant to provide longer periods of 
time for the implementation of the rule. However, PHMSA noted during 
the meeting that the NPRM already provided a compliance period of 12 
months after the 6-month effective date of the rule, which would have 
provided a compliance date of 18 months after the rule's publication. 
Members of the Committees representing industry (including Enbridge, 
National Grid, Marathon Pipeline, Colonial Pipeline, DCP Midstream, and 
PECO) noted that there could be significant lead time required for 
obtaining actuators for valves for larger-diameter pipelines, and 
recommended longer implementation times for the rule. As a result of 
this discussion, the committee ultimately recommended the 24-month 
implementation period. Additionally, for hazardous liquid pipelines, 
the LPAC also unanimously recommended PHMSA change the timeframe to 
activate RMVs after construction from 7 days to 14 days because of 
practicability concerns.
(iv) Notifications
    Commenters representing hazardous liquid pipeline operators stated 
that PHMSA should align the various notification requirements 
throughout the rulemaking, including those for ``other [alternative 
equivalent] technology'' requests, with other part 195 notification 
requirements. Regarding such notifications, the PST requested that 
PHMSA clarify what criteria or standards are needed to justify the 
determination and provide for an equivalent level of safety. Commenters 
also requested that this notification period operate similarly to how 
PHMSA has created notifications for gas pipeline operators; namely, 
that unless an operator receives a specific objection from PHMSA or a 
request for more review time before the 90-day period has passed, the 
operator can install the technology under the assumption that PHMSA has 
no objection.
    INGAA et al. also recommended PHMSA revise the rule so that the 
notification process for alternative technology such as manual valves 
applies to all locations, asserting that operators installing new or 
replaced pipelines in remote areas are likely to use this process.
    At the Committee meetings on July 22 and 23, 2020, the LPAC and 
GPAC each unanimously recommended that PHMSA add specificity on 
standards for PHMSA review of ``other technology'' and manual valve 
notifications. The LPAC also unanimously recommended PHMSA incorporate 
the notification requirements of Sec.  192.18 into the final rule and 
make a similar provision for hazardous liquid pipelines.
3. PHMSA Response
(i) ``Rupture-Mitigation Valve'' and Related Definitions
    PHMSA notes that there was concern regarding the clarity of the 
terms RMV, ``shut-off segment,'' and ``entirely replaced,'' and PHMSA 
has revised those terms in this final rule.
    For the definition of an RMV, PHMSA has made it explicit that such 
a valve is an ASV or an RCV. Commenters from industry requested PHMSA 
allow the use of certain valve technologies to satisfy the proposed RMV 
or alternative equivalent technology installation requirement. In this 
final rule, PHMSA is clarifying that a valve on crossover piping that 
is locked and tagged closed in accordance with operating procedures 
would qualify as an alternative equivalent technology. PHMSA notes 
that, for other technologies (such as check valves) that commenters 
from industry had suggested should be generally considered alternative 
equivalent technologies, PHMSA included a pre-installation notification 
procedure for alternative equivalent technologies and will consider 
requests to use such technologies on a case-by-case, site-specific 
basis. When determining the appropriateness of alternative equivalent 
technologies for a particular site, PHMSA will consider technical and 
safety information submitted by an operator including, but not limited 
to, 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.
    The definition of a ``shut-off segment,'' as it pertains to RMVs 
and alternative equivalent technologies, has been clarified in this 
final rule as well. These segments are only relevant when RMVs or 
alternative equivalent technologies are installed pursuant to this 
final rule for Class 3 and Class 4 locations for gas pipelines, as well 
as HCAs (or on pipeline segments that could affect HCAs, in the case of 
hazardous liquid pipelines) for gas and hazardous liquid pipelines. 
Shut-off

[[Page 20960]]

segments are defined as segments of pipe located between the upstream 
mainline valve closest to the upstream endpoint of the new or entirely 
replaced Class 3, Class 4, or HCA segment, and the downstream mainline 
valve closest to the downstream endpoint of the new or entirely 
replaced Class 3, Class 4, or HCA segment. Shut-off segments can 
include crossover or lateral pipe depending on where that pipe connects 
to the specific shut-off segment. Single shut-off segments can include 
multiple Class 3, Class 4, or HCA pipeline segments.
    Pertaining to the definition of ``entirely replaced,'' it was not 
PHMSA's intent to require the addition of RMVs or alternative 
equivalent technologies for small maintenance replacements, such as at 
road crossings or anomaly repairs where the pipe is replaced. PHMSA did 
note throughout the NPRM that it was considering ``entirely replaced'' 
to mean the replacement of 2 contiguous miles of pipe. Some commenters 
representing the public noted that pipeline operators may try to 
schedule replacement activities and pipeline segment lengths to 
circumvent the replacement mileage threshold. PHMSA determined that 
this concern is mitigated by the recommendations of the Committees to 
clarify that the RMV and alternative equivalent technology installation 
requirements would apply to those replacement projects where 2 or more 
miles of pipeline, in the aggregate, are replaced within any 5 
contiguous miles within any 24-month period. PHMSA is aware that 
sourcing valves might take a long lead time, and that waiting to 
install a valve, at any location, could be deleterious to safety. 
Requiring the installation, or automation, where applicable, of valves 
where relatively larger construction projects are taking place will 
facilitate operators obtaining and installing the RMVs or alternative 
equivalent technologies required by this final rule. Accordingly, in 
this final rule, PHMSA has introduced specific definitions for 
``entirely replaced onshore transmission pipeline segments'' and 
``entirely replaced onshore hazardous liquid or carbon dioxide pipeline 
segments'' meaning those gas and hazardous liquid pipeline replacement 
projects where 2 or more miles of pipe have been replaced within any 5 
contiguous miles of pipe within any 24-month period.
(ii) RMV Applicability
    Certain commenters from the industry and the industry associations 
requested various exemptions for the RMV and alternative equivalent 
technology installation requirements, including pipelines that operated 
at pressures below 30 percent of SMYS. Pipelines operating at pressures 
below 30 percent of SMYS have ruptured in the past, and low operating 
pressure is not a guarantee that the pipe will not rupture. However, 
PHMSA is aware of data that would indicate that pipelines operating at 
pressures lower than 20 percent of SMYS are at less risk of rupturing. 
A study on pipelines that ruptured while operating at low hoop stresses 
that was published in 2013 noted that, within the 5-year window of the 
study, there were seven pipeline ruptures occurring on pipelines 
operating at a pressure below 20 percent SMYS.\42\ The authors of the 
study noted that, while these are not highly likely events, the 
likelihood is not so low where certain conditions could be present that 
they do not need to be considered in an operator's IM plans.
---------------------------------------------------------------------------

    \42\ Rosenfeld & Fassett ``Study of Pipelines that Ruptured 
While Operating at a Hoop Stress Below 30% SMYS;'' Pipeline Pigging 
and Integrity Management Conference (Feb. 13-14, 2013).
---------------------------------------------------------------------------

    Additionally, according to PHMSA's 2019 annual report data, the 
population of natural gas and hazardous liquid pipelines that operate 
at these pressures are a small portion of the aggregate mileage of 
those types of pipelines across the United States.\43\ Consistent with 
other, current regulatory requirements, PHMSA believes it is reasonable 
to add certain exemptions for pipeline segments operating at lower 
stress levels. For natural gas pipelines, PHMSA presented data during 
the GPAC meeting showing a correlation between pipelines operating at 
lower stresses and pipelines with smaller PIRs. Given that natural gas 
pipelines that would have a PIR of less than 150 feet would typically 
be either pipelines of smaller diameter that would not be subject to 
the requirements of this rulemaking, or larger pipelines operating at 
lower stresses, PHMSA believes it would be feasible to exempt such 
pipelines from the RMV and alternative equivalent technology 
installation requirements if those pipelines are in Class 1 or Class 2 
locations. PHMSA did not accept the GPAC's recommendation to provide an 
exception, based on the pipeline's PIR, for gas transmission and 
gathering pipelines in Class 3 locations. Pipelines in Class 3 
locations are by definition adjacent to population centers: A Class 3 
location is where there are 46 or more buildings for human occupancy 
within the class location unit, or where there is a building or area 
that is occupied by 20 or more persons on at least 5 days a week for 10 
weeks in any 12-month period. PHMSA has determined that, while it might 
be less likely that a gas pipeline operating at lower stresses in a 
Class 3 location would rupture, the potential consequences to public 
safety and the environment are still unacceptable.
---------------------------------------------------------------------------

    \43\ Seven percent of the gas transmission mileage operates at 
pressures below 20 percent of SMYS, which equates to approximately 
21,000 miles out of 302,000 miles. For hazardous liquid pipelines, 3 
percent of the total mileage operates as pressures less than 20 
percent of SMYS, which equals 6,750 miles out of a total of 225,000 
miles.
---------------------------------------------------------------------------

    For hazardous liquid pipelines, PHMSA notes that there are 
currently regulatory requirements for low-stress pipelines in rural 
areas. By definition (at Sec.  195.12), these pipelines operate at 
stress levels equal to or less than 20 percent of SMYS. The 
environmental consequences of a hazardous liquid spill can linger for 
many years, and hazardous liquids can travel far from the initial 
accident site to affect other areas as well. Therefore, counter to the 
LPAC recommendation, PHMSA is not providing hazardous liquid pipelines 
that operate at lower stresses an exemption from the RMV installation 
and usage requirements of this rulemaking.
    Some commenters (including TC Energy and the industry associations) 
requested PHMSA provide exemptions from RMV installation requirements 
for, or otherwise exclude, gas pipelines in Class 1 and Class 2 
locations, and for hazardous liquid pipelines that are outside of HCAs. 
PHMSA notes that, for hazardous liquid pipelines, there are many 
locations, such as non-navigable waterway crossings, that could 
experience significant consequences from an accident even though they 
are not defined as HCAs. For gas pipelines, there have been many 
instances where a Class 1 location in which a pipeline has been 
installed has later experienced so much population growth that it has 
grown into a Class 3 location. Requiring operators to install RMVs and 
alternative equivalent technology on Class 1, Class 2, and non-HCA 
infrastructure is prudent and provides future generations with a 
baseline level of public and environmental safety that can accommodate 
changes in population density.
    As discussed earlier in this rulemaking, PHMSA considered the 
recommendations the Committees made regarding the applicability of this 
rulemaking to gathering pipelines. For gas pipelines, PHMSA determined 
that the risk profile of Type A gas gathering pipelines was 
considerable enough not to impose a broad exception to the rule's 
requirements, as these pipelines tend to operate at higher pressures 
and are in Class 2, Class 3, or Class 4 locations,

[[Page 20961]]

where there are more concentrated populations. However, based on risk 
profile, PHMSA did create a general exemption from the RMV and 
alternative equivalent technology installation requirements in this 
rulemaking for Type A gas gathering pipelines in Class 2 locations with 
a PIR of 150 feet or less. Operators of Type A gas gathering pipelines 
that have a PIR of 150 feet or less in a Class 2 location are not 
required to install RMVs or alternative equivalent technology in 
accordance with this rulemaking. PHMSA considered the GPAC's 
recommendation applicable to Type B gathering lines and determined that 
a broad exemption from the RMV and alternative equivalent technology 
requirements would be warranted, given the fact that Type B gas 
gathering pipelines, by definition, operate at hoop stresses less than 
20 percent of SMYS. Pipelines operating at pressures that low are less 
likely to rupture. As noted above, PHMSA will carefully monitor data 
from these lines to inform future rulemaking.
    For hazardous liquid pipelines, PHMSA noted earlier that regulated 
hazardous liquid gathering pipelines would be required to install and 
use RMVs and alternative equivalent technologies in accordance with 
this rulemaking, as hazardous liquid gathering pipelines that are in 
non-rural areas are required to comply with the entirety of part 195. 
However, PHMSA is exempting regulated rural gathering pipelines from 
the RMV and alternative equivalent technology requirements of this 
rulemaking unless they cross bodies of water greater than 100 feet 
wide, as ruptures on regulated rural gathering pipelines would 
generally involve less risk to public safety and property than non-
rural gathering lines, and ruptures on regulated rural gathering lines 
that cross large bodies of water have the potential to cause more 
significant environmental damage. Regarding the comment that PHMSA 
should clarify whether the 5 percent volume contribution for 
determining the need for RMVs on laterals is based on flow rate or 
total volume, Sec.  192.634(b)(3) states that the 5 percent volume 
contribution is based on total volume.
(iii) Timeframe for RMVs To Be Operational and Implementation Period
    Regarding the timeframe for making RMVs and alternative equivalent 
technologies operational, PHMSA has determined that 14 days is more 
appropriate than the proposed 7 days given that (as noted in the 
comment submitted by INGAA et al.) a number of activities must take 
place after a pipeline has been placed into service but before an RMV 
is fully operational--PHMSA understands the scale and number of those 
activities make completion within the proposed 7-day timeline 
impracticable. Accordingly, PHMSA has adjusted that timeframe in this 
final rule. PHMSA has also provided a procedural machinery for 
operators to request an extension beyond 14 days if completion of 
necessary activities for a valve to become operational is not 
economically, technically, or operationally feasible (e.g., due to 
prohibitive costs, labor or component shortages, or required permitting 
or access rights).
    Regarding the implementation date for RMV and alternative 
equivalent technology installation, PHMSA notes the confusion several 
commenters had regarding the implementation date and the effective date 
of the rule. In this final rule, PHMSA is clarifying the implementation 
date for RMV and alternative equivalent technology installation by 
stating that pipelines and pipeline segments installed or entirely 
replaced beginning 12 months after the publication date of the final 
rule will be required to have RMVs or alternative equivalent 
technologies. PHMSA believes 12 months is a reasonable implementation 
period for RMV and alternative equivalent technology installation 
rather than the 24 months recommended by the Committees as it should 
provide operators with sufficient lead time to source RMV or 
alternative equivalent technology for planning construction and 
replacement projects without causing substantial implementation delay. 
Further, as shown in the RIA, PHMSA has found that much new pipeline 
construction is already obtaining and installing RMVs. If a gas or 
hazardous liquid pipeline operator anticipates it will not be able to 
meet this compliance timeframe, it may request from PHMSA, in 
accordance with Sec. Sec.  192.18 and 195.18, respectively, additional 
time to comply because of economic, technical, or operational 
feasibility constraints (e.g., labor or component availability 
constraints and lead times, prohibitive cost, permitting requirements, 
or obtaining requisite access rights) with respect to its near-term 
construction and replacement projects. Per the procedures at Sec. Sec.  
192.18 and 195.18, PHMSA has discretion to grant or deny an operator's 
request based on the information that the operator provides.
(iv) Notifications
    Regarding the notification requirements for RMV and alternative 
equivalent technology installation, PHMSA acknowledges that aligning 
the notification process with the recently finalized Sec.  192.18 would 
be beneficial. Accordingly, PHMSA has done so in this final rule for 
both hazardous liquid and gas pipelines. For gas pipelines, this means 
that PHMSA has cross-referenced the notification requirements in this 
final rule to Sec.  192.18 to provide for, and build upon, the 
notification process that is in that section. For hazardous liquid 
pipelines, because there was no corresponding notification section, 
PHMSA has created a new Sec.  195.18 in this final rule that functions 
similarly to Sec.  192.18. For any notifications related to the RMV and 
alternative equivalent technology requirements of this rulemaking, 
Sec.  195.18 provides a consistent process where operators submit in 
advance of installation the pertinent, requested information to PHMSA, 
and PHMSA has 90 days in which to review and respond to the request. If 
an operator does not receive a letter of objection or a request from 
PHMSA for more time or information for PHMSA to complete its review of 
the request within 90 days of the notification, then the operator may 
use the alternative technology, method, compliance timeline, or valve 
spacing that is being requested. Similar to the notification response 
process for part 192, PHMSA's objection will specify the reasons PHMSA 
does not approve of the proposed alternative technology, method, 
compliance timeline, or valve spacing, while a request from PHMSA for 
more time to review the request will extend the notification review 
period beyond 90 days. Further, to establish a verifiable record, it is 
PHMSA's policy to send a formal ``no objection'' letter or email, 
either before or after the 90-day review period, when PHMSA does not 
object to an operator's request in the notification.

F. Valve Spacing & Location

1. Summary of Proposal
    In the NPRM, PHMSA proposed to require RMVs or alternative 
equivalent technologies installed on newly constructed or entirely 
replaced gas and hazardous liquid pipelines to be spaced at certain 
intervals. For gas pipelines, PHMSA proposed that the distance between 
RMVs or alternative equivalent technologies must not exceed 8 miles for 
Class 4 locations, 15 miles for Class 3 locations, and 20 miles for 
Class 1 and Class 2 locations in HCAs. For hazardous liquid pipelines, 
PHMSA proposed RMV and alternative equivalent technology spacing of 15 
miles for HCAs and 7\1/2\ miles for HVL lines in populated HCAs. PHMSA 
also

[[Page 20962]]

proposed valve spacing of 20 miles for hazardous liquid pipelines not 
in HCAs and spacing of a maximum of 1 mile for pipelines at water 
crossings of greater than 100 feet in width so that the valve is 
located outside of the flood plain, or the actuators and controls were 
otherwise unaffected by floodwaters.
    In Sec. Sec.  192.634 and 195.418, PHMSA also proposed that 
operators would, in HCAs and Class 3 and Class 4 locations for gas 
pipelines, install RMVs or alternative equivalent technologies upstream 
and downstream of new construction and replacements longer than 2 
contiguous miles regardless of whether the project involved a valve 
installation.
    PHMSA also proposed to modify the IM requirements for both gas and 
hazardous liquid pipelines to specify that RMVs or alternative 
equivalent technologies installed to protect HCAs must meet the design, 
operation, testing, maintenance, and rupture mitigation requirements 
proposed elsewhere in the NPRM.
2. Comments Received
(i) Spacing
    The PST and the NTSB stated the maximum RMV and alternative 
equivalent technology spacing intervals proposed in the NPRM might not 
be sufficient to mitigate the consequences of a ruptured pipeline, with 
the PST expressing concern that 15- and 20-mile spacing is too far, 
especially for large-diameter pipelines.
    For hazardous liquid pipelines, commenters representing the 
pipeline industry generally did not support a universal mileage 
threshold for maximum valve spacing without considering the 
feasibility, practicability, and public safety benefits associated with 
installing a valve at a particular location. Magellan Midstream 
Partners L.P. specifically requested PHMSA consider valve spacing that 
relies on operator programs providing for pipeline-specific evaluations 
on optimization of valve spacing to reduce the magnitude of potential 
releases within HCAs. Similarly, commenters representing the hazardous 
liquid pipeline industry requested PHMSA provide a process for 
operators to request alternative valve spacing distances for situations 
where an operator determines the installation of additional valves 
would not provide additional public safety or where installation is 
otherwise infeasible.
    API, AOPL, and GPA Midstream also suggested that PHMSA's proposal 
for the maximum valve spacing for HVL pipelines was too stringent at 7 
\1/2\ miles and that a 10-mile distance for valves on HVL pipelines 
would better align PHMSA requirements with standards established in 
Canada that would be more appropriate for pipelines in the United 
States. API, AOPL, and GPA Midstream suggested that a 7 \1/2\-mile 
spacing for HVL pipelines was appropriate only for those pipelines in 
HCAs. Commenters also noted that the Canadian standard provides 
operators with a 25 percent spacing flexibility when determining valve 
locations, and the commenters recommended PHMSA provide a similar 
allowance.
    The PST expressed confusion regarding the NPRM language related to 
RMV and alternative equivalent technology spacing, suggesting that 
their interpretation of the proposed regulatory text would allow RMVs 
and alternative equivalent technology to be spaced at distances greater 
than the current valve spacing requirements at Sec.  192.179. By 
contrast, their expectation is that PHMSA's intent is to require more 
valves at closer spacing intervals than the current rules, or at most, 
at the same spacing. The PST requested PHMSA clarify whether new valve 
spacing requirements would be equal to or more stringent than currently 
required.
    At the GPAC meeting on July 22, 2020, the Committee unanimously 
recommended that PHMSA specify that the spacing requirements in Sec.  
192.634 apply to replacement projects covered by Sec.  192.179. At the 
LPAC meeting on July 23, 2020, the Committee unanimously recommended 
that PHMSA add a 25 percent tolerance to the spacing of HVL pipelines 
and add a notification procedure to allow operators of hazardous liquid 
pipelines to obtain relief from the valve spacing requirements on a 
case-by-case basis.
(ii) Location
    INGAA et al. noted that using an automated valve in a remote area 
may create a comparatively higher reliability risk than using an 
automated valve in a more populated area, noting that if a 
communications failure, power loss, or other malfunction causes an 
automated valve in a remote area to close unnecessarily, it may take 
the operator hours to arrive at the valve and restore service, leading 
to an extended loss of gas supply. They also stated that, in locations 
where an operator employs an RCV to meet the proposed installation 
requirement in a Class 1 or Class 2 location, it will take more time 
for the operator to acquire information about a potential rupture event 
in remote areas. Further, INGAA et al. stated that operators require 
significant information about a potential rupture event before making 
the critical decision to close an RCV, as closing a valve prematurely 
can have the same disruptive impacts to customers as a rupture.
    INGAA et al. also noted that limiting the RMV and alternative 
equivalent technology installation requirements to pipelines in HCAs 
and Class 3 and Class 4 locations would also improve the clarity of the 
rulemaking, stating that the rule, as written, is confusing. INGAA et 
al. suggested PHMSA revise Sec.  192.179 to clarify that Class 1 and 
Class 2 locations outside of HCAs do not require RMVs or alternative 
equivalent technologies to be installed unless the replacement project 
involves a valve. INGAA et al. noted that this ``opportunistic 
approach'' appears to have been PHMSA's intent in the proposal, and it 
differed from their understanding of the rule's application to 
replacement projects in HCAs and Class 3 and Class 4 locations. Other 
commenters had similar suggestions and requested PHMSA revise cross-
references throughout the rule for clarity. Commenters representing 
hazardous liquid pipeline operators made a similar comment pertaining 
to the proposals for hazardous liquid pipelines.
    API and AOPL also requested that PHMSA clarify the requirements for 
the placement of valves near water crossings, recommending that PHMSA 
base the valve spacing requirements on the size of a 100-year flood 
plain.
    Operators of both gas and hazardous liquid pipelines recommended 
that PHMSA explicitly state that a shut-off segment must contain the 
new or replaced HCA segment or Class 3 or Class 4 segment where RMVs or 
alternative equivalent technologies are installed. Related to shut-off 
segments, these operators also asked PHMSA to clarify whether 
operational block valves would be permitted within a shut-off segment, 
and if an RMV or alternative equivalent technology would need to be the 
nearest valve to the shut-off segment. Some commenters noted that 
requiring valves within the endpoints of certain segments might create 
valve spacing more stringent than the current valve spacing 
requirement. Further, INGAA et al. questioned if an RMV or alternative 
equivalent technology is needed at the termination of a pipeline.
    For hazardous liquid pipelines, several commenters requested PHMSA 
clarify what a ``flood plain'' is for the purposes of valve spacing at 
water crossings, with some commenters suggesting PHMSA specify 
operators must use the 100-year flood plain. The PST requested PHMSA 
clarify what

[[Page 20963]]

``flood conditions'' meant. Similarly, certain commenters, including 
Magellan, requested that PHMSA remove the 1-mile limitation on water 
crossings or provide for alternative spacing if that mile is within the 
flood plain.
    PHMSA also received comments requesting that it remove the proposed 
requirement to locate valves within 7\1/2\ miles of the endpoint of an 
HCA segment.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
unanimously recommended that PHMSA:

    (1) Clarify that replacement projects in non-HCA Class 1 and 
Class 2 locations do not require RMVs or alternative equivalent 
technology unless the replacement project involves a valve. 
Throughout industry public comments, this was what was referred to 
as the ``opportunistic approach.'' For hazardous liquid pipelines, 
the LPAC recommended PHMSA revise the rule to clarify the same 
concept for pipelines in non-HCA locations.
    (2) Specify that proposed valve spacing requirements related to 
pipeline replacements and RMV and alternative equivalent technology 
installation requirements do not apply to pipelines in non-HCA Class 
1 and Class 2 locations.
    (3) Specify that a ``shut-off segment'' must contain the newly 
constructed or replaced HCA or Class 3 or Class 4 pipeline segment.
    (4) Specify that RMVs or alternative equivalent technology would 
not be required at the downstream termination of a pipeline. 
Further, specify that operational block valves are allowed within a 
shut-off segment and RMVs and alternative equivalent technology need 
not be the nearest valve to a shut-off segment.
    (5) For hazardous liquid pipelines, specify the 100-year flood 
plain at hazardous liquid pipeline water crossings.
3. PHMSA Response
(i) Spacing
    PHMSA believes the valve spacing it proposed in the NPRM for both 
gas and hazardous liquid pipelines is appropriate. For new gas pipeline 
construction, spacing of RMVs and alternative equivalent technology 
will follow existing requirements at Sec.  192.179(a) determining 
distance by reference to class location: 2.5-mile intervals in Class 4 
locations, 4-mile intervals in Class 3 locations, 7.5-mile intervals in 
Class 2 locations, and 10-mile intervals in Class 1 locations. For 
replacement projects on gas pipelines, PHMSA's experience with how 
operators implement a ``one-class bump'' when a pipeline's class 
location changes support the final rule's spacing approach. Per the 
current requirements following a class location change, an operator can 
base a pipeline's MAOP on a specified design factor multiplied by the 
test pressure for the new class location as long as the corresponding 
hoop stress does not exceed certain percentages of the SMYS of the pipe 
and as long as the pipeline has been tested for a period of 8 hours or 
longer in accordance with Sec.  192.611(a)(1). This approach has been 
practical for operators where single-step class location changes occur. 
Operators performing one-class bumps leave the existing infrastructure 
in place, which means that, even though the class location has changed, 
the design standards of the original pipeline are still being used. In 
addition to wall thickness and steel strength, this applies to the 
spacing of the valves along the segment as well. For example, operators 
have been able to use Class 1 spacing standards for valves on a 
pipeline segment that has changed from a Class 1 to a Class 2 if the 
operator has followed the appropriate procedures in Sec.  192.611. 
PHMSA is extending this same methodology to replacement RMV and 
alternative equivalent technology spacing for gas pipelines by allowing 
operators to use the maximum valve spacing of a class below the class 
location of the replacement project. In practice, this means that 
replacement projects requiring RMVs or alternative equivalent 
technology in Class 4 locations can have RMVs or alternative equivalent 
technology spaced at a maximum of 8 miles, replacement projects 
requiring RMVs or alternative equivalent technology in Class 3 
locations can have RMVs or alternative equivalent technology spaced at 
a maximum of 15 miles, and replacement projects in Class 1 and Class 2 
locations can have RMVs or alternative equivalent technology spaced at 
a maximum of 20 miles. If the RMV or alternative equivalent technology 
spacing is greater than the spacing for the next class location, a new 
RMV or alternative equivalent technology is required. Going forward, 
PHMSA will monitor data in these locations to ensure such spacing does 
not create an undue risk to people or the environment.
    According to PHMSA's data from 2015 to 2019, hazardous liquid 
pipeline operators have constructed or replaced 4,708 miles of pipeline 
that is 6 inches or greater in diameter, and they have installed a 
total of 673 valves on that pipeline mileage for an average of 1 valve 
for every 7 miles. Therefore, PHMSA does not believe it is onerous to 
finalize minimum valve spacing standards at every 15 miles for pipeline 
segments in, or which could affect, HCAs and at every 20 miles for 
pipeline segments that could not affect HCAs. However, a hazardous 
liquid pipeline operator may request an exemption from these 
requirements if it can demonstrate to PHMSA in accordance with the 
notification procedures in Sec.  195.18, that installing an RMV or 
alternative equivalent technology as otherwise required by Sec.  
195.260 would be economically, technically, or operationally infeasible 
by reference to factors such as access to communications and power; 
terrain; prohibitive cost; component and labor availability; ability to 
secure access rights and necessary permits; and lack of accessibility 
to operator personnel for installation and maintenance. That notice 
must also include a safety evaluation of deviation from this final 
rule's spacing requirements that references technical and safety 
factors including, but not limited to, the following: Design, 
construction, maintenance, and operating procedures for pertinent 
pipeline segments; potential consequences to the environment and the 
public from a rupture on the pertinent pipeline segments; and 
mitigation measures (e.g., operating times for isolation valves) in the 
event of a rupture.
    Concerning the proposed spacing for HVL pipeline segments, PHMSA 
based the valve spacing requirements on the recommended spacing in 
American Society of Mechanical Engineers (ASME) B31.4, ``Pipeline 
Transportation Systems for Liquids and Slurries,'' an industry standard 
that has existed for many decades. PHMSA does not believe that 
permitting broad tolerance from the HVL valve spacing requirements in a 
manner similar to the Canadian standard commenters referenced is 
appropriate, as PHMSA prescribed this valve spacing standard only in 
high-population areas or other populated areas as defined by Sec.  
195.450 where there would be significant populations in need of 
additional protection. However, in accordance with the LPAC 
recommendation, PHMSA has provided in this final rule a method for 
operators to request (in accordance with Sec.  195.18 and subject to 
PHMSA review) an increase, by 25 percent, of the maximum valve spacing 
intervals for HVL pipeline segments in high-population areas or other 
populated areas should the installation of a valve at a particular 
location not be economically, technically or operationally feasible. 
Operators would, in connection with that notice, submit a safety 
evaluation referencing technical and safety factors including, but not 
limited to, the following: Design, construction, maintenance, and 
operating procedures

[[Page 20964]]

for pertinent pipeline segments; potential consequences to the 
environment and the public from a rupture on the pertinent pipeline 
segments; and mitigation measures in the event of a rupture. If PHMSA 
grants the request, the operator is required to keep the records 
necessary to support such a determination for the useful life of the 
pipeline.
    PHMSA considered the comments regarding the clarity of the proposed 
valve spacing regulations and the interplay of the various sections of 
the NPRM when drafting this final rule. PHMSA attempted to simplify the 
regulatory text by dividing the RMV sections into installation 
requirements and performance requirements. PHMSA also attempted to 
consolidate notification requirements broadly by establishing a 
notification section in part 195, similar to that established in part 
192 in the 2019 Gas Transmission Final Rule, and cross-referencing to 
these sections whenever a notification might be required in the 
regulations. In addition to reducing the amount of regulatory text, 
these sections also provide for a more consistent notification process 
across the regulated community.
(ii) Location
    PHMSA notes that the proposed RMV and alternative equivalent 
technology requirements for gas pipelines in Class 1 and Class 2 
locations were intended to apply only to new construction and those 
replacement projects where 2 or more miles were being replaced and 
which involved a valve. This was unlike the proposed requirements for 
gas pipe replacements in excess of 2 miles in HCAs and Class 3 and 
Class 4 locations, which, as proposed, would have needed upstream and 
downstream RMVs or alternative equivalent technology regardless of 
whether the project impacted an existing valve. Therefore, PHMSA is 
clarifying in this final rule that operators are to take the 
``opportunistic'' approach suggested in the comments and are required 
to install RMVs or alternative equivalent technology during pipe 
replacement projects in non-HCA Class 1 or Class 2 areas only if the 
replacement project involves the addition, replacement, or removal of a 
valve. As previously discussed, this requirement does not apply to 
those Class 1 or Class 2 locations that have a PIR of 150 feet or less. 
For hazardous liquid pipelines, the same approach applies to those 
replacements in non-HCA locations.
    Commenters questioned whether a newly constructed or entirely 
replaced pipeline segment in an HCA was supposed to be included within 
a shut-off segment for the purposes of the NPRM. PHMSA intended the 
shut-off segment to include the entire new or replaced pipeline segment 
in (or, for hazardous liquid lines, which could affect) an HCA and has 
clarified that intent in the regulatory text of this final rule by 
stating so explicitly in Sec. Sec.  192.634 and 195.418. Similarly, 
some commenters from the hazardous liquid pipeline industry also 
questioned whether requiring an RMV or alternative equivalent 
technology within 7\1/2\ miles of the endpoint of a hazardous liquid 
pipeline segment in or which could affect an HCA would ultimately 
reduce the existing valve spacing. PHMSA did not intend for such a 
measure to reduce valve spacing and determined that the requirement is 
duplicative of similar preventative and mitigative requirements set 
forth in Sec.  195.452. As such, PHMSA has determined that the proposed 
requirement may have been unnecessary and has deleted it from this 
final rule.
    INGAA et al. also requested PHMSA clarify whether an RMV or 
alternative equivalent technology is needed at the termination of a 
pipeline. Per this final rule, an RMV or alternative equivalent 
technology is needed at the termination of a pipeline, and PHMSA is 
clarifying that an operator may use a manual compressor station valve 
at a continuously manned station as an alternative equivalent 
technology; PHMSA understands that the logical termination of a 
pipeline might be within a station, and a valve there could also be 
used as an RMV or alternative equivalent technology to help isolate a 
rupture on the pipeline system. Such a valve used as an alternative 
equivalent technology would not require an advance notification to 
PHMSA pursuant to Sec. Sec.  192.18 or 195.18, but, as with any 
alternative equivalent technology, it must be able to be closed as soon 
as is practicable and absolutely within 30 minutes after the rupture 
identification and comply with the applicable provisions of this final 
rule.
    Further, PHMSA also received questions regarding whether 
operational block valves are permitted within a shut-off segment and 
whether an RMV or alternative equivalent technology needs to be the 
nearest valve to the shut-off segment. In the NPRM, PHMSA stated that 
``all valves in a shut-off segment'' needed to be RMVs or alternative 
equivalent technology. However, it was PHMSA's intent that operational 
block valves be allowed within a shut-off segment as long as the RMV or 
alternative equivalent technology is within the valve spacing 
requirements. As such, PHMSA has removed that phrase from this final 
rule; the section now states the requirements for installing RMVs or 
alternative equivalent technologies, and it leaves open the possibility 
that an operator can install additional block valves on a shut-off 
segment between compliant and appropriately spaced RMVs or alternative 
equivalent technologies. PHMSA is also clarifying in this final rule 
that RMVs or alternative equivalent technologies do not need to be the 
nearest valve to the shut-off segment, and has specifically stated this 
in the RMV and alternative equivalent technology installation sections 
at Sec. Sec.  192.634 and 195.418.
    Regarding comments about the installation of RMVs or alternative 
equivalent technologies near river crossings and flood plains, PHMSA 
notes that, based on the comments it received, it has made explicit in 
this final rule that such valves must be installed outside of the 100-
year flood plain of the body or bodies of water, or the valves must 
have actuators and other control equipment installed so as to not be 
impacted by flood conditions, or the equipment might be elevated to a 
level where they will not be impacted by flood conditions. PHMSA 
considers ``flood conditions'' to be where water is at a high enough 
level near the valve so that it, or the related electronics, would not 
operate. Flood conditions also can include debris carried by 
floodwaters that could affect the equipment. For multiple water 
crossings, PHMSA structured the proposed requirements to provide 
operators the flexibility to install valves near sites where there are 
multiple water crossings and where there might be potential access 
issues between water crossings. This mechanism is consistent with 
approvals PHMSA has granted operators under the existing authority and 
process at Sec.  195.260. In this final rule, PHMSA is requiring 
operators to locate valves upstream and downstream of the first and 
last of multiple water crossings so that the total distance between the 
upstream-most valve and the downstream-most valve does not exceed 1 
mile, rather than requiring an operator to install RMVs or alternative 
equivalent technologies on either side of each water crossing where 
there are multiple water crossings.

G. Valve Status Monitoring

1. Summary of Proposal
    In the NPRM, PHMSA proposed to require operators to monitor or 
otherwise control RMVs or alternative equivalent technologies using 
remote or

[[Page 20965]]

on-site personnel. This monitoring or control would include the valve 
status, the upstream and downstream product pressures, and product flow 
rates during normal, abnormal, and emergency operations. PHMSA also 
proposed to require operators be able to monitor the status of valves 
during rupture events.
2. Comments Received
    Several commenters, including INGAA et al., questioned whether 
remote monitoring of ASVs was required, as those valves would be set to 
respond automatically to rupture events and not require additional 
input.
    INGAA et al. also requested that PHMSA allow operators to monitor 
pressure or flow rates in lieu of valve status if they were unable to 
monitor valve status. PHMSA was also asked to clarify whether operators 
would need to monitor remotely the flows and pressures through manually 
operated RMVs after they close. Further, PHMSA was also asked to 
remove, on efficiency grounds, the proposed requirement for operators 
to station personnel at a manually operated RMV site for continuous 
monitoring.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
unanimously recommended that PHMSA specify that an operator does not 
need to monitor ASV status if the operator can monitor pressures or 
flows in the pipeline segment to be able to identify and locate a 
rupture. This differed from the proposed language in that, as worded, 
an operator would have been required to monitor ASV status in addition 
to pressures and flows. The Committees also unanimously recommended 
PHMSA provide a similar allowance for manual valves.
3. PHMSA Response
    PHMSA maintains that an operator's ability to monitor the upstream 
and downstream pressures around RMVs and alternative equivalent 
technologies is important to identify ruptures effectively and mitigate 
incidents. As such, PHMSA expects all valves installed as RMVs and as 
alternative equivalent technologies to monitor pressures upstream and 
downstream of those valves at all times. However, if operators can 
monitor upstream and downstream pressures around manual valves that are 
being used as alternative equivalent technologies or ASVs in real-time 
so that they can identify and locate a rupture, operators do not need 
to station personnel at a site where a manually operated alternative 
equivalent technology has been installed or continually monitor ASV 
status. In accordance with the Committee recommendations on this issue, 
PHMSA has specified in this final rule that, if an operator can 
remotely monitor either pressures or flows in real-time at an ASV or a 
manual shut-off valve such that they can identify and locate a rupture, 
the operator does not need to monitor valve status continually, nor are 
operators required to monitor the pressures on manual valves being used 
as alternative equivalent technology once those valves are closed in 
response to a rupture.

H. Class Location Changes

1. Summary of Proposal
    In the NPRM, PHMSA proposed to clarify the valve spacing 
requirements of Sec.  192.179 and to apply the RMV and alternative 
equivalent technology installation requirement and rupture-mitigation 
requirements to pipelines where segments of pipe (of any length) were 
replaced to meet MAOP requirements following a class location change. 
As proposed, operators would need to install necessary RMVs or 
alternative equivalent technology within 24 months of the class 
location change.
2. Comments Received
    INGAA et al., GPA Midstream, and the KOGA, expressed concern over 
the proposed Sec.  192.610 requirements and recommended revisions to 
the rule language. INGAA et al. indicated that class location change 
pipe replacements produce minimal pipeline safety benefits because they 
involve less than 75 miles of transmission pipe per year, and the 
replaced pipe is often in safe, operable condition.
    GPA Midstream called for PHMSA to establish specific valve 
installation requirements for class-location-related pipeline 
replacements. They claimed that under PHMSA's interpretation of the 
current regulations at Sec. Sec.  192.13(b) and 192.179, operators must 
comply with valve installation requirements for new pipelines if a 
segment is replaced in response to a class location change; but that 
this is contrary to the original intent of the regulations, imposes 
unreasonable compliance burdens, and discourages pipeline replacements.
    INGAA et al. noted that, because the vast majority of class change 
pipe replacements are less than 2 miles in length, the proposed Sec.  
192.610 would require the installation of at least one manual valve for 
many pipe replacements where the class location changes from a Class 1 
to a Class 3. INGAA et al. estimated that it costs $600,000 to $800,000 
for an operator to install a new manual valve on an existing pipeline 
ranging from 24 to 36 inches in diameter, and therefore, the annual 
cost for installing manual valves under this proposed provision could 
exceed $100 million per year. Therefore, INGAA et al. suggested that, 
for class location change pipe replacements that involve less than 2 
contiguous miles of pipe but more than 2,000 feet of pipe, PHMSA should 
provide operators the option to automate an existing upstream and 
downstream valve so that the distance between such automated valves 
would not exceed 20 miles, which is the current spacing requirements 
for valves on pipelines in Class 1 locations. INGAA et al. stated that 
this would be consistent with the approach that PHMSA has proposed for 
replacements greater than or equal to 2 contiguous miles in Class 1 and 
Class 2 locations that are also HCAs. They further stated that 
retaining the valve spacing requirements for Class 1 locations is 
appropriate for class location change pipe replacements that do not 
meet the 2-mile ``entirely replaced'' definition and will mitigate the 
need to install a new valve for most class location change pipe 
replacements.
    Similarly, other industry commenters, including GPA Midstream and 
TC Energy Corporation, stated that PHMSA should exclude short pipe 
replacements from proposed Sec.  192.610, noting that when an operator 
is removing a short section of pipe, there may not be an appropriate 
location in that short area to install a new valve, which can make 
complying with the valve spacing provisions impractical. Further, these 
commenters suggested that operators frequently replace short sections 
of existing pipe to repair potentially injurious conditions found to be 
affecting that pipe. They stated that many of these maintenance 
replacements are not ``pipe replacement projects,'' generally only 
affect small sections of the pipeline, and in some cases, must be 
conducted immediately to ensure public safety. They argue that 
operators must be reasonably able to repair such pipeline defects 
without installing additional valves, stating that requiring all pipe 
replacements, no matter how small, to comply with valve spacing 
requirements applicable to new pipe construction would increase cost 
and regulatory complexity and may reduce an operator's incentive or 
ability to complete voluntary assessments and remediation. As such, 
PHMSA was asked to exclude pipe replacements that were less than 2,000 
feet from the RMV and alternative equivalent technology installation 
requirements.
    AFPM stated that the requirement to update and install the required 
valves to match the class location requirements

[[Page 20966]]

within 24 months of the class location change may not be feasible in 
all circumstances due to factors outside the control of the operator, 
such as local permitting. AFPM also suggested that PHMSA should 
incorporate a process to account for such uncontrollable delays.
    At the GPAC meeting on July 22, 2020, the GPAC unanimously 
recommended that PHMSA specify that the valve spacing in Sec.  192.634 
would, pursuant to Sec.  192.610, be applicable to class location 
changes resulting in the replacement of an aggregate of 2 or more miles 
of pipe within any 5 contiguous miles, and consider implementing a 
timeframe of 24 months for compliance from the change in class 
location. Following discussion of the potential that high installation 
costs from application of valve spacing requirements to replacement of 
smaller pipeline segments may discourage pipeline replacement projects, 
the GPAC also unanimously recommended PHMSA exclude pipeline 
replacements less than 1,000 feet within 1 contiguous mile from the 
valve installation requirements. Finally, the Committee unanimously 
recommended (after discussion of the costs and practical difficulties 
associated with obtaining land rights necessary to install RMVs on 
pipelines on segments less than 2 miles in length) that, for pipeline 
replacements due to class location changes that are between 1,000 feet 
and 2 miles, PHMSA should allow operators to automate the existing 
valves with automatic or remote-control actuators and pressure sensors, 
with a maximum spacing of 20 miles, which they asserted would be 
consistent with the operational capability proposed in Sec.  192.634.
3. PHMSA Response
    PHMSA intended for the RMV and alternative equivalent technology 
requirements, including those for valve spacing proposed in Sec.  
192.634, to be applicable to class location changes for cases where the 
operator chose to replace pipe to meet the MAOP requirements of the new 
class location. The proposal was attempting to clarify that, in the 
event of pipe replacement due to a class location change, operators 
must install valves that comply with the existing valve spacing 
requirements at Sec.  192.179(a) for the new class location.\44\
---------------------------------------------------------------------------

    \44\ In the Matter of Viking Gas Transmission, Final Order, 
C.P.F. No. 32102 (May 1, 1998).
---------------------------------------------------------------------------

    In addition to finalizing that proposal in this final rule for 
class location-based pipeline replacements of 2 or more miles within 
any 5 contiguous miles over a 24-month period, PHMSA is also allowing 
operators to comply with this section by installing or using existing 
RMVs when a class location changes (i.e., from Class 1 to a Class 2 or 
a Class 2 to a Class 3) so that the distance between RMVs does not 
exceed 20 miles. This allowance considers several public comments in 
addition to a corresponding discussion and recommendation from the 
GPAC. INGAA et al. noted that the NPRM seemed to require the 
installation of manual valves on pipelines where the class location had 
changed. However, this was not PHMSA's intent. The automation of 
existing valves to protect a pipeline segment where the class location 
has changed is to provide a higher measure of public and environmental 
safety than the installation of additional manual valves, given that 
automated valves will be able to be closed more quickly than manual 
valves in the event of an emergency.
    PHMSA acknowledges that there may be instances where the RMV and 
alternative equivalent technology installation requirements might not 
be appropriate for very short sections of pipe that are being replaced 
under Sec.  192.610. As such, PHMSA is providing in this final rule an 
exception from the RMV and alternative equivalent technology 
installation requirements for short pipeline replacements that are less 
than 1,000 feet in length within 1 contiguous mile. For pipe 
replacements that occur when class locations change and that range from 
1,000 feet to 2 miles in length, PHMSA believes that operators could 
automate existing valves with RCV or ASV technologies and corresponding 
pressure sensors that would be consistent with the operational 
requirements and valve spacing requirements of proposed Sec.  192.634. 
As discussed in the paragraph above, PHMSA has modified this final rule 
accordingly.

I. Valve Maintenance

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise Sec. Sec.  192.745 and 
195.420 to require operators perform inspections, maintenance, and 
drills on RMVs to ensure that they can be closed as soon as practicable 
but within 40 minutes of identifying a rupture. Among other 
requirements, PHMSA proposed operators perform point-to-point 
verification tests for RMVs that are ASVs or RCVs and perform initial 
validation drills and periodic confirmation drills for manual or 
locally operated valves an operator identified as RMVs. PHMSA also 
proposed that operators would be required to identify corrective 
actions and lessons learned from the validation and confirmation drills 
and share and implement those lessons learned throughout their pipeline 
systems. As proposed, operators would be required to repair or 
remediate inoperable valves within 6 months following a failed drill, 
with the operator designating a temporary alternate compliant valve 
within 7 days of a failed drill.
2. Comments Received
    Some commenters, including INGAA et al., stated PHMSA should remove 
the proposed requirement for point-to-point testing because it is 
already required under the control room management requirements in 
Sec. Sec.  192.631 and 195.446. This comment applied to the proposed 
regulations for both gas and hazardous liquid pipelines.
    Operators requested that PHMSA clarify that annual drills are not 
required for every manual valve and that the drills for ``locally-
actuated'' valves would exclude ASVs and RCVs. Further, commenters 
indicated that PHMSA should provide more specificity regarding the 
random drill selection process.
    INGAA et al. commented that PHMSA should clarify that operators are 
not required to fully close manual or locally actuated valves during 
drills. TPA and AFPM expressed this same concern, with AFPM stating 
that such a requirement might cause significant disruptions when the 
applicable pipeline is the primary source of feedstock for a major 
manufacturing facility. INGAA et al. suggested PHMSA allow operators to 
perform tabletop drills to meet the drill response time requirement.
    The Clean Air Council stated that the final rule should include 
provisions for pipeline operators to perform regular drills to ensure 
they can comply with the rupture response regulations, test the 
performance of their equipment, and ensure that pipeline personnel will 
be trained and skilled in responding to an emergency properly. They 
noted that while ASVs and RCVs will cut the response time down in a 
rupture event, having trained operating personnel is also important, 
stating that PHMSA should include provisions wherein a key responsible 
individual within the company is identified whose responsibility it is 
to train new personnel on the rupture response procedures within a 
certain period of new personnel being hired. They stated that PHMSA 
should require operators to report on how such training would be 
conducted and in what period the new individuals are trained, noting 
that this

[[Page 20967]]

would create accountability for an otherwise unknown factor in pipeline 
management that would decrease the likelihood that operators may fail 
in carrying out rupture response procedures in a timely manner. They 
also noted that with adding in electrical connections and cellular 
communications with new valves, additional maintenance schedules and 
procedures will need to be developed for this added complexity. 
Similarly, the PST supported the proposed requirements for testing, 
maintenance, drills, and the incorporation of lessons learned into 
operator procedures.
    INGAA et al. stated that PHMSA should reconsider the proposed 
maintenance requirements for when an RMV or alternative equivalent 
technology installed under the final rule is unable to achieve the 
proposed performance standard. Specifically, they suggested PHMSA 
should revise the NPRM by providing operators 12 months to repair, 
replace, or install new RMVs when an RMV or alternative equivalent 
technology is not operating correctly or otherwise cannot achieve the 
40-minute response time requirements. This concern was echoed by other 
industry commenters, who suggested various compliance timeframes. INGAA 
et al. also stated that PHMSA should allow a notification process when 
it would not be practicable for an operator to repair or replace an RMV 
or alternative equivalent technology within 12 months.
    GPA Midstream noted that operators should be required to make 
repairs or replacements as soon as practicable but no later than the 
time provided in their procedures for conducting operations, 
maintenance, and emergency activities. GPA Midstream also stated that a 
7-day timeframe may not be sufficient to locate and designate an 
alternative valve to serve as a substitute for a damaged or otherwise 
inoperable RMV or alternative equivalent technology. They requested 
that PHMSA revise the provision to allow 14 days for designating an 
alternative compliant valve. This concern was echoed by individual 
operators, who suggested different compliance periods for implementing 
alternative valve measures.
    Other commenters also noted that the proposed 6 months for 
implementing alternate shut-off valve measures is inadequate because it 
fails to account for right-of-way acquisition, the time needed to 
obtain necessary environmental clearance and permits, and extended lead 
times for the procurement of transmission valves. More specifically, TC 
Energy requested that PHMSA clarify what is meant by ``alternative 
compliant valve,'' noting that, because of the proposed 6-month 
compliance deadline for completing maintenance or replacing a RMV or 
alternative equivalent technology, it is apparent that ``compliant'' is 
not intended to refer to proximity or spacing or whether a designated 
``alternative valve'' is automated or is manual. TC Energy suggested 
that PHMSA should direct operators to designate an alternative shut-off 
valve and document an interim response plan until the primary RMV or 
alternative equivalent technology is repaired or replaced.
    API/AOPL and GPA Midstream also suggested that PHMSA should revise 
the maintenance procedures to allow operators to obtain an authorized 
alternative response time.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
unanimously recommended that PHMSA delete the requirement for point-to-
point testing because it duplicates requirements in the existing 
control room management regulations in both parts 192 and 195.
    Regarding the drill requirements, the Committees unanimously 
recommended that PHMSA clarify that annual drills apply only to 
manually operated valves and involve the manual operation of a local 
actuator or by hand, and not to ASVs or RCVs. Further, the Committees 
unanimously recommended specifying that a 25 percent valve closure is 
sufficient to demonstrate the successful completion of the response 
time validation drill for manually operated valves.
    The Committees also unanimously recommended PHMSA provide operators 
with a notification process to justify a need to extend the timeframes 
for repair and establishing alternate RMVs, if necessary. Further, the 
Committees unanimously recommended PHMSA consider adjusting the 
timeframe for repairs to 12 months but as soon as practicable, rather 
than the proposed 6 months. Certain members of the Committees 
representing the public (including Pipeline Safety Trust) expressed a 
preference to keep the timeframe for repairs at 6 months. However, 
other members of the Committees representing industry (including 
Enbridge, Williams, Consumers Energy, Marathon Pipeline, and PECO) 
noted that 12 months might be more appropriate given difficulties with 
supplier access to inventory and procurement issues. Additionally, the 
Committees unanimously recommended that PHMSA specify that alternative 
compliant valves identified through this process would not be required 
to comply with the valve spacing requirements for RMVs.
3. PHMSA Response
    PHMSA acknowledges that the proposed point-to-point testing 
requirements were already a part of the control room management 
regulations at Sec. Sec.  192.631 and 195.446. However, PHMSA believes 
restating the provision in the valve maintenance requirements will 
provide additional clarity and will improve compliance and 
enforceability. Therefore, PHMSA has chosen to retain the language in 
this final rule.
    Regarding the proposed manual valve drill requirements, PHMSA 
intended the annual drills to apply to manually operated valves used as 
alternative equivalent technology only, and not ASVs or RCVs. PHMSA 
expects such a drill would include the manual operation of a local 
actuator or closing the valve via a hand-wheel. PHMSA confirms that 
annual drills are not required for every manual valve. Rather, an 
annual drill is required for one randomly selected manual valve in each 
of the operator's field work units. The way that an operator determines 
which manual valves would be randomly selected is at the discretion of 
the operator, but the selection method must be included in an 
operator's written procedures so it can be subject to inspection.
    PHMSA has determined that full closure of valves is not necessary 
for the purposes of the valve maintenance requirements of this final 
rule. Accordingly, PHMSA has revised the provision to require, at a 
minimum, a 25 percent closure of the valve. PHMSA recognizes that 
overcoming inertia is likely to be the most difficult work in getting a 
valve to operate. Therefore, PHMSA has determined that a 25 percent or 
more closure is sufficient to demonstrate the valve's operability and 
functionality while allowing pipeline operators to maintain service 
without major interruptions.
    Additionally, in this final rule, PHMSA is not allowing operators 
to perform tabletop drills to verify response times for manually 
operated valves. PHMSA believes that a tabletop drill would not be 
sufficient for ensuring that the valve is working, which is the intent 
of the provision. Operators need to ensure that manual valves being 
used as an alternative equivalent technology for the purposes of this 
rulemaking can be arrived at and physically operated so that they 
function as intended, achieving full closure within the maximum valve-
closure time of this rulemaking. A paper exercise cannot effectively 
confirm real-

[[Page 20968]]

time travel time to a valve location or the time it will take operator 
personnel to close a particular valve manually, given conditions that 
could occur during a rupture.
    Regarding the measures operators must take after a failed drill, 
PHMSA believes that a 7-day timeframe for identifying alternative shut-
off measures and a 6-month timeframe for valve repair are appropriate. 
Because the purpose of an RMV or alternative equivalent technology is 
to mitigate the consequences of a rupture, should one occur, the longer 
a valve stays non-functional or the longer it takes an operator to 
identify alternative measures increases the potential rupture 
consequences to the area near the impacted pipeline segment. In light 
of the comments and Committee recommendations for extending the repair 
period to 12 months given the likely delays involved in scoping and 
executing required repairs, PHMSA understands that there operators may 
need repair timeframes longer those identified in the NPRM; PHMSA has, 
therefore, extended the repair period to 12 months. PHMSA has also 
provided an advance notification process in this final rule for 
operators to request (before the repair is undertaken) an extension of 
that 12-month repair period by demonstrating to PHMSA that repair 
according to the final rule's timeline will be economically, 
technically, or operationally infeasible (e.g., by reference to 
prohibitive costs, difficulty in securing required access rights and 
permits, long procurement lead times, and component/labor 
availability). However, PHMSA declines to offer a similar notification 
process in connection with identification of alternative shut-off 
measures following a failed drill, as prompt identification of those 
alternatives are essential for ensuring that the public and the 
environment are not unprotected from a rupture for extended periods of 
time.
    PHMSA did not intend that any valves operators would identify as an 
alternative compliant RMV or equivalent technology based on a failed 
drill would need to comply with the valve spacing requirements of the 
rulemaking, and PHMSA is not requiring that in this final rule. PHMSA 
is requiring, however, that any alternative compliant RMV or equivalent 
technology would contain the entire shut-off segment and comply with 
the 30-minute valve closure standard of this rulemaking.
    Some commenters requested PHMSA enhance the proposed maintenance 
and drill requirements to cover valve-related specialized equipment and 
periodic personnel training and management programs. PHMSA notes that 
these requirements are already included in the Federal Pipeline Safety 
Regulations, including under the operator qualification and control 
room management regulations.

J. Failure Investigations

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise the regulations applicable to 
gas and hazardous liquid pipelines to define the elements that an 
operator must incorporate when conducting analyses of incidents and 
other releases and failures involving the activation of RMVs and 
alternative equivalent technologies, namely ruptures.
    The proposed revisions would require the operator to identify 
potential P&M measures that could be taken to reduce or limit the 
release volume and damage from similar events in the future. The post-
incident or -failure review would address factors associated with this 
rulemaking, including but not limited to detection and mitigation 
actions, response time, valve location, valve actuation, and SCADA 
system performance. Upon completing the post-incident or -failure 
analysis, the operator would be required to develop and implement the 
lessons learned throughout its suite of procedures, including in 
pertinent operator personnel training and qualification programs, and 
in design, construction, testing, maintenance, operations, and 
emergency procedure manuals and specifications.
2. Comments Received
    INGAA et al. stated that PHMSA should remove the references to 
``failures'' in Sec.  192.617, as ``failure'' is not defined in parts 
191 or 192, and it is unclear if the section accounts for abnormal 
operations that do not result in a rupture. Similar comments were made 
by representatives of hazardous liquid pipeline operators, requesting 
that ``failure'' be changed to ``accident'' to be more consistent with 
the part 195 regulations.
    INGAA et al. added that the prescriptive post-incident requirements 
proposed in Sec.  192.617 are fit-for-purpose following a rupture but 
are unnecessary and overly burdensome following an abnormal operation. 
Other commenters from industry noted that the investigation 
requirements seemed to be duplicative of existing accident and incident 
reporting requirements and suggested that PHMSA remove the proposed 
investigation requirements from the final rule.
    GPA Midstream stated that the proposal for operators to prepare and 
follow procedures for conducting failure and incident investigations 
should be stated in a new, separate paragraph, and the proposed 
requirement to incorporate any lessons learned into appropriate part 
192 procedures can be consolidated in another paragraph. They further 
stated that PHMSA could eliminate the other additional language 
proposed in the section (including sending the failed pipe, component, 
or equipment to a laboratory for testing), because it is unnecessary. 
Similarly, Magellan Midstream Partners, L.P., as well as other industry 
commenters, suggested that PHMSA should remove the proposed 
requirements for failure analysis because it is not appropriate or 
effective for an operator to send all failed pipe, components, or 
equipment for laboratory testing and examination. Further, several of 
these industry commenters requested PHMSA specify that the 
implementation of any lessons learned and any additional P&M measures 
following an incident would be required only if they are reasonable and 
practicable.
    INGAA et al. and GPA Midstream stated that the proposed 
documentation and recordkeeping requirements for failure investigations 
are unnecessary, with INGAA et al. stating that the requirements appear 
to be duplicative of requirements currently under PHMSA's incident 
reporting requirements. GPA Midstream stated that, to avoid imposing 
undue burdens on pipeline operators, the senior executive review and 
lifetime recordkeeping requirements PHMSA proposed should only apply to 
the final analysis prepared at the conclusion of the investigation 
rather than preliminary analyses. GPA Midstream and API/AOPL commented 
that such a requirement would create an additional recordkeeping burden 
without improving safety, with API requesting PHMSA delete the proposed 
requirement. AFPM provided similar comments.
    The PST stated that PHMSA should amend Sec.  192.617(c) to require 
that the results of an operator's post-incident review be incorporated 
into operators' procedures, not just read and kept, as it appears to be 
proposed. INGAA et al. stated that they support the incorporation of 
post-incident lessons learned as an important aspect of pipeline safety 
management systems. However, INGAA et al. added there may be some 
circumstances where an incident investigation would not yield a change 
to procedures, for example, some third-party damage incidents, and 
PHMSA should require operators to

[[Page 20969]]

incorporate lessons learned and P&M measures only if appropriate and 
practicable following an incident investigation. TPA generally echoed 
these remarks.
    Further, INGAA et al. stated that they support distribution 
operators incorporating post-incident lessons learned into their 
procedures even though the rule stated it only applies to gas 
transmission and hazardous liquid pipelines, but they recommended PHMSA 
clarify that the requirements in Sec.  192.617(c) only apply to 
transmission lines, since the broad definition of ``rupture'' in Sec.  
192.3 could lead to Sec.  192.617(c) being interpreted to apply to both 
gas distribution and gas transmission pipeline incidents.
    PST stated that, although the NPRM proposes operators incorporate 
post-incident lessons into their procedures, the paragraph relating to 
rupture and valve shut-off incident reviews does not include that same 
requirement. They added that the section should be amended to include a 
requirement that the results of the post-incident reviews be 
incorporated into operator's procedures, not just read and kept.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
unanimously recommended that PHMSA clarify that the implementation of 
lessons learned and additional P&M measures after incidents are 
required only where they are found to be reasonable and practicable. 
Additionally, the GPAC unanimously recommended that PHMSA specify that 
general failure investigations under these sections would apply to gas 
distribution pipelines; however, failure investigations specific to 
RMVs would not apply to gas distribution pipelines.
3. PHMSA Response
    PHMSA acknowledges the comments stating that it should clarify the 
terminology of its proposed regulatory amendments by using defined 
terms, such as removing the use of the term ``failure'' in favor of 
``incident'' or ``accident.'' However, PHMSA notes that existing 
regulations at Sec.  192.617 address the investigation of failures on 
gas lines, which is broader than reportable incidents. Similarly, the 
term ``failure'' is used throughout parts 192 and 195 of the Federal 
Pipeline Safety Regulations. Therefore, PHMSA has made no changes in 
this final rule to the phrasing as it was originally proposed in the 
NPRM, since the term ``failure'' is currently used throughout its 
regulations.
    Other commenters suggested that the failure investigation 
requirements would duplicate existing incident/accident reporting 
requirements. PHMSA does not consider the failure investigation 
requirements that were proposed and the existing incident/accident 
reporting requirements to be duplicative, as the proposed failure 
investigation requirements were intended to build on existing failure/
accident investigation requirements for gas and hazardous liquid 
pipelines, and provide more thorough technical evaluation of valve 
functionality and performance during the mitigation of an incident or 
accident. PHMSA intended for operators to investigate ``failures,'' as 
that term is used throughout parts 192 and 195 of its regulations, and 
as it is defined in ASME B31.8S and ASME B31.4. PHMSA has, however, 
revised the regulatory text in in this final rule to better convey that 
intent.
    Similarly, some industry commenters, including Magellan, opposed 
certain requirements in this section, especially with respect to 
operators sending failed pipe, components, or equipment for laboratory 
testing and examination. With respect to gas pipelines in particular, 
PHMSA provides in this final rule additional specificity to the 
existing regulation at Sec.  192.617, which states that ``each operator 
shall establish procedures for analyzing accidents and failures, 
including the selection of samples of the failed facility or equipment 
for laboratory examination, where appropriate [. . .].'' The underlying 
requirement remained unchanged, and PHMSA has finalized the clarifying 
changes proposed in the NPRM in a way that will improve the ability to 
identify and respond to safety issues that could be revealed in such 
testing and examinations. PHMSA believes that regulatory language in 
this final rule providing for parallel obligations for hazardous liquid 
pipelines are similarly essential to its continuing regulatory 
oversight of the safety of those pipelines.
    As for the scope of the proposed failure investigation requirements 
for gas pipelines, because PHMSA included the amendments in the 
existing regulations at Sec.  192.617(a) and (b), PHMSA intended those 
proposed requirements to apply to distribution pipelines, which were 
already subject to the existing requirements of that section. Because 
proposed paragraphs (c) and (d) of that section addressed failure 
investigations specific to the closure of RMVs or alternative 
equivalent technologies, however, and RMVs or alternative equivalent 
technologies were and are not required for gas distribution systems in 
this rulemaking, operators of gas distribution pipelines are not 
required to comply with those paragraphs as a result of this rule.
    INGAA et al. requested PHMSA clarify that the implementation of any 
post-incident lessons-learned and any additional P&M measures be 
required only where they are reasonable and practical. PHMSA would not 
expect operators to implement P&M measures that were clearly 
unreasonable or impractical. Regarding those measures, PHMSA did not 
intend to cause any confusion with similar IM requirements by 
referencing a term that is primarily used in the IM regulations. 
Subsequently, in this final rule, PHMSA has changed this phrase from 
``P&M measures'' to a more general phrase of ``operations and 
maintenance'' measures to avoid confusion with separate IM-related 
requirements.
    Several comments were submitted regarding senior executive 
involvement for the certification of failure investigations. PHMSA 
believes that senior executive certification is essential to ensuring a 
failure investigation's quality and highlighting the importance of the 
investigation results and their implementation into operations.

K. 9-1-1 Notification Requirements

1. Summary of Proposal
    In the NPRM, PHMSA proposed requirements related to operators 
responding to pipeline ``emergencies'' that built on existing 
regulations at Sec. Sec.  192.615 and 195.402. Specifically, PHMSA 
proposed to require that an operator's emergency procedures provide for 
rupture mitigation in response to a rupture event, and that operators 
contact and maintain liaison with the appropriate public safety 
answering point (9-1-1 emergency call center) in the event an 
operator's pipeline ruptures.
2. Comments Received
    NAPSR stated that the term ``emergency'' is not defined within part 
192, noting that, without a definition for ``emergency,'' operators may 
make unnecessary notifications to the appropriate fire, police, and 
public officials, and force responses to minor events instead of real 
emergencies. NAPSR suggested that if PHMSA is changing this 
specifically to address ruptures on gas transmission lines, then it may 
be appropriate for PHMSA to reference ``rupture'' in the final rule 
language instead of ``emergency.''
    TPA stated that the 10-minute requirement for contacting first 
responders is duplicative and unnecessary, as existing emergency 
procedures and damage prevention

[[Page 20970]]

procedures already contain requirements for the timely contact of 
emergency responders and calls to 9-1-1 numbers. They recommended that 
PHMSA remove this requirement from the rule. A member of the public 
agreed that the time to declare a rupture following the first sign of a 
problem should be no more than 10 minutes, and that emergency services 
must be notified right away.
    The NTSB stated that the proposed changes to the emergency planning 
regulations do not require immediate and direct notification to local 
jurisdictions of possible ruptures as recommended by Safety 
Recommendation P-11-9. They stated that the NPRM's clarifications for 
when notification is required could unnecessarily delay operators 
notifying local authorities and possibly exclude some ruptures from the 
notification requirement, such as distribution systems or portions of 
transmission systems that do not contain RMVs.
    AFPM stated that the language in the proposed sections is 
unnecessarily prescriptive and the language should be simplified, as 
the position title or function of the operator personnel that is 
responsible for contacting the appropriate public safety answering 
point is immaterial.
    AFPM stated that the use of ``may'' in the proposed revision to 
require notification of ``each government organization that may respond 
to a pipeline emergency'' vastly expands the universe of events for 
which operators would have to provide notice and is an unrealistic 
request. AFPM stated that the operator may not reasonably be able to 
identify all the possible jurisdictions or agencies that may need to be 
called upon. As such, AFPM recommended PHMSA allow an operator to 
identify and coordinate with the agency identified by local or State 
law as the lead agency in a pipeline emergency, or allow communication 
with a regional coordinating agency (e.g., Office of Emergency 
Management) to meet this requirement.
    AFPM stated that they support PHMSA's intent to require operators 
to establish and maintain adequate means of communication with the 
appropriate public safety officials, as previously established 
relationships between operators and safety officials could help 
mitigate the consequences of an incident.
    AFPM stated that they believe the use of ``and other public 
officials'' in the proposed requirements is too vague and potentially 
expansive. AFPM and INGAA et al. recommended that PHMSA should 
explicitly note with whom operators should liaise, such as county 
emergency managers, local emergency planning committees, or 9-1-1 
agencies, and limit the requirement to those emergency response 
agencies with primary jurisdiction for response to a pipeline incident. 
INGAA et al. stated that this approach would be consistent with the 
Pipeline Emergency Responder Initiatives that have been developed in 
several States with the support of PHMSA.
    AFPM added that ``notifying the appropriate public safety answering 
point (9-1-1 emergency call center), as well as fire, police, and other 
public officials'' is redundant and possibly confusing in jurisdictions 
where the 9-1-1 center is designated as the single point of emergency 
services contact. AFPM recommended PHMSA allow 9-1-1 to be the single 
point of contact for all jurisdictions for which the 9-1-1 center 
serves as such.
    At the Committee meetings on July 22 and 23, 2020, the Committees 
unanimously recommended that PHMSA state that communication with 9-1-1 
applies to all ruptures without exception. For operators of pipelines 
not located within 9-1-1 service areas or that otherwise have no public 
safety answering points, the Committees unanimously recommended PHMSA 
promulgate similar requirements. Further, the Committees unanimously 
recommended that PHMSA allow operators to establish liaison with the 
appropriate local emergency response coordinating agencies, such as 9-
1-1 emergency call centers or county emergency managers, in lieu of 
communicating individually with each fire, police, or other public 
entity, as was proposed in the NPRM.
    The Committees also unanimously recommended that PHMSA limit 
certain sections of the regulations to emergency preparedness 
activities and other sections to emergency response activities, rather 
than combining the two as PHMSA did in the NPRM.
3. PHMSA Response
    The NTSB and the PST were concerned that the NPRM, as proposed, 
could exclude certain ruptures from the notification requirements of 
this section. PHMSA did not intend to include any exceptions from the 
9-1-1 notification requirements of this rulemaking, including for those 
pipelines where RMV or alternative equivalent technology closure is not 
required, and does not believe the NPRM was worded as such. Further, 
PHMSA has modified the language in the NPRM regarding when the 9-1-1 
notification obligation has been triggered to reflect the substitution 
in this final rule of the term ``notification of potential rupture'' 
for the NPRM's definition of ``rupture''; PHMSA expects this 
substitution will reduce the time before response and mitigation 
actions are taken. Ultimately, the requirement in this final rule for 
9-1-1 notification applies to all notifications of potential ruptures 
on all gas and hazardous liquid pipeline systems governed by the 
emergency planning and procedure requirements at Sec. Sec.  192.615 and 
195.402, respectively.
    Industry commenters requested that PHMSA include in the final rule 
9-1-1 communication provisions for pipelines that are not located in 
areas served by 9-1-1 call centers or that have no public safety 
answering points. The emergency notification requirements in this final 
rule require operators to establish adequate means of communication 
with fire, police, and other public officials as needed, regardless of 
whether they are affiliated with public safety answering points. 
Operators must determine the jurisdictional areas, responsibilities, 
resources, and emergency contact numbers for those government 
organizations that may respond to pipeline emergencies involving their 
pipeline facilities.
    To the points commenters made on liaising with the appropriate 
local emergency coordinating entities and allowing coordination with a 
lead agency if recognized by State and local law, PHMSA will note that 
it did not propose to amend the long-standing requirements about 
coordinating with local officials, including fire and police officials. 
The NPRM intended to add the explicit requirement, when applicable, for 
operators to call 9-1-1 after the notification of a potential rupture. 
Per this final rule, to meet these requirements of this section, 
operators may liaise with the appropriate emergency response 
coordinating agencies, such as 9-1-1 emergency call centers or county 
emergency managers, in lieu of communicating individually with each 
fire, police, or other public entity. PHMSA believes that the 
requirement to liaise with appropriate emergency response coordinating 
agencies responds to the Committee recommendation for including 
provisions for operators of pipeline segments outside of 9-1-1 or 
public safety access point service areas.

L. Other

1. Summary of Proposal
    In the NPRM, PHMSA proposed to revise Sec. Sec.  192.935 and 
195.452 to clarify the requirements for conducting ASV

[[Page 20971]]

and RCV evaluations for HCAs, particularly when RCVs and ASVs are 
installed as P&M measures associated with improved response times for 
pipeline ruptures. The proposed amendments would have required that 
operators be able to evaluate and demonstrate that they could identify 
a rupture within 10 minutes in accordance with the proposed rupture 
identification regulations, meet the proposed RMV or alternative 
equivalent technology closure standard of 40 minutes, and demonstrate 
compliance with the proposed valve maintenance requirements.
2. Comments Received
    Regarding the installation of RMV technology in HCAs under Sec.  
192.935, INGAA et al. recommended that PHMSA clarify the decisions 
operators would be required to make, stating PHMSA proposed in the NPRM 
that these decisions should consider the swiftness of rupture detection 
capabilities, not leak detection capabilities. INGAA et al. and other 
industry commenters also recommended that PHMSA remove the proposed 
requirements in Sec.  192.935(c) because they appear to be duplicative 
with the proposed requirements for RMV installation under Sec.  
192.634. Similarly, Northern Natural Gas Company recommended that PHMSA 
remove the proposed requirements at Sec.  192.935 because they are 
already partially addressed by the investigation of failures and 
incidents at Sec.  192.617.
    The PST supported PHMSA's proposed addition of performance measures 
for the installation of EFRDs and their use as RMVs under Sec.  
195.452. API/AOPL and GPA Midstream suggested that PHMSA should restate 
that EFRDs installed under the IM regulations must meet the applicable 
requirements in part 195 for RMVs, as this would simplify the 
regulatory language.
    Northern Natural Gas Company noted that the use of automatic valves 
may create cybersecurity vulnerabilities. A private citizen echoed this 
sentiment, stating that PHMSA needs to address cybersecurity issues 
related to sensors and control systems associated with RMVs, as such 
issues could reduce the effectiveness of those valves. However, the 
private citizen noted that Congress has not provided PHMSA, or the U.S. 
DOT in general, with specific authority to regulate the cybersecurity 
of pipeline infrastructure. That private citizen suggested that these 
technologies should be protected from cyber-threats, and the failure of 
cybersecurity protections should trigger the same reporting 
requirements that accompany the failure of physical controls.
    The Clean Air Council suggested that PHMSA adjust the definition of 
HCAs to be broader than areas with higher population density, stating 
they believe that the environmental and historical value of certain 
locations should be included in an evaluation whether a location is an 
HCA.
3. PHMSA Response
    PHMSA was attempting to update the existing requirements for ASV 
and RCV analysis in HCAs with the terminology and specific requirements 
related to RMVs and alternative equivalent technology that were 
proposed in the NPRM. PHMSA was proposing no new requirements other 
than that, if operators performed a risk analysis indicating that an 
ASV or an RCV would provide protection to an HCA or a could-affect HCA 
pipeline segment, those valves that the operators installed would 
essentially be RMVs and would need to comply with the 10-minute rupture 
identification standard, the valve closure time, and the associated 
maintenance requirements. PHMSA believes that the wording of the 
section and duplication of those requirements, rather than cross-
references, may have confused readers. As such, in this final rule, 
PHMSA has retained those same requirements while simplifying the 
language to state that an RMV installed in accordance with Sec. Sec.  
192.935 and 195.452 must comply with all of the other RMV requirements 
in the respective parts of the regulations.\45\
---------------------------------------------------------------------------

    \45\ See Sec. Sec.  192.3, 192.9, 192.18, 192.179, 192.610, 
192.615, 192.617, 192.634, 192.636, 192.745, and 192.935, as 
appropriate, for gas transmission and gathering pipelines, and 
Sec. Sec.  195.2, 195.11, 195.18, 195.258, 195.260, 195.402, 
195.418, 195.419, 195.420, and 195.452, as appropriate, for 
hazardous liquid pipelines.
---------------------------------------------------------------------------

    Regarding cybersecurity issues, PHMSA notes that the recent 
cyberattack on the Colonial Pipeline underscores the urgency of public-
private collaboration to address international cybersecurity threats. 
PHMSA is working with a coalition of its Federal partners, including 
the Transportation Security Administration (TSA), to ensure that 
pertinent regulatory regimes adequately address cybersecurity risks on 
pipeline infrastructure. PHMSA notes that the TSA recently issued 
security directives that will enable the Department of Homeland 
Security (DHS) to better identify, protect against, and respond to 
threats to critical operators in the pipeline sector. The TSA's initial 
directive requires critical pipeline owners and operators to report 
confirmed and potential cybersecurity incidents to the DHS 
Cybersecurity and Infrastructure Security Agency (CISA) and to 
designate a Cybersecurity Coordinator, to be available 24 hours a day, 
7 days a week. It also requires critical pipeline owners and operators 
to review their current practices as well as to identify any gaps and 
related remediation measures to address cyber-related risks and report 
the results to TSA and CISA within 30 days.\46\ A second Security 
Directive requires owners and operators of TSA-designated critical 
pipelines to implement specific mitigation measures to protect against 
ransomware attacks and other known threats to information technology 
and operational technology systems, develop and implement a 
cybersecurity contingency and recovery plan, and conduct a 
cybersecurity architecture design review.
---------------------------------------------------------------------------

    \46\ https://www.dhs.gov/news/2021/05/27/dhs-announces-new-cybersecurity-requirements-critical-pipeline-owners-and-operators.
---------------------------------------------------------------------------

    Changing the HCA definition is outside the scope of the rulemaking 
and would require substantial technical analysis. However, in response 
to congressional mandates in the ``Protecting Our Infrastructure of 
Pipelines and Enhancing Safety Act of 2016'' (Pub. L. 114-183) and the 
2020 PIPES Act, PHMSA has promulgated an Interim Final Rule (under RIN 
2137-AF31) titled ``Pipeline Safety: Coastal Ecological Unusually 
Sensitive Areas,'' to amend the definition of an ``unusually sensitive 
area'' in part 195 for hazardous liquid pipelines to include the Great 
Lakes, coastal beaches, and certain coastal waters explicitly as 
ecological resources for the purposes of determining whether a pipeline 
is in, or could affect, an HCA.\47\ Further, section 119 of the 2020 
PIPES Act requires PHMSA to contract with the National Academy of 
Sciences (NAS) for development of a study evaluating potential 
regulatory amendments that would build on this final rule by requiring 
installation of RMVs on existing natural gas pipelines in HCAs, 
hazardous liquid pipelines in unusually sensitive areas, and hazardous 
liquid pipelines in commercially navigable waterways. The NAS committee 
has been formed and that committee is in the process of planning its 
activities.\48\
---------------------------------------------------------------------------

    \47\ 86 FR 73173 (Dec. 27, 2021).
    \48\ NAS, ``Criteria for Installing Automatic and Remote-
Controlled Shutoff Valves on Existing Gas and Hazardous Liquid 
Transmission Pipelines'' (last visited Nov. 23, 2021).

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

[[Page 20972]]

IV. Section-by-Section Analysis of Changes to 49 CFR Part 192 for Gas 
Pipelines

Sec.  192.3 Definitions

    Section 192.3 provides definitions for various terms used 
throughout part 192. Most of the requirements of this final rule would 
be triggered by an operator identifying a rupture following the 
notification of a potential rupture. Therefore, PHMSA is amending Sec.  
192.3 to define the ``notification of potential rupture'' in terms of 
notification of, or observation by, an operator of indicia specified in 
Sec.  192.635 of an unintentional or uncontrolled release of a large 
volume of gas from a pipeline.
    Once an operator is notified of a potential rupture, they must 
identify a rupture, if one exists. Therefore, PHMSA has established a 
concept of ``rupture identification'' to mean the point when a pipeline 
operator has sufficient information reasonably to determine that a 
rupture occurred. PHMSA believes this would occur following a 
``notification of potential rupture,'' as that term has been defined in 
this rulemaking, given that the operator would have been notified or 
would have had notice of some indicia of a potential rupture per Sec.  
192.635. The final rule at Sec.  192.615 requires that operators must 
document, in their operations manual or written procedures, their 
method for rupture identification. An operator, after identifying a 
rupture, would be required to close the RMVs or alternative equivalent 
technologies necessary to isolate the ruptured pipeline segment.
    As a part of this rulemaking, operators are required to install 
RMVs or alternative equivalent technology on certain pipeline segments, 
including those that are ``entirely replaced onshore pipeline 
segments.'' RMVs are defined in this rulemaking to mean ASVs or RCVs 
that a pipeline operator uses to minimize the volume of gas released 
from the pipeline and to minimize the consequences of a rupture. PHMSA 
has defined entirely replaced onshore transmission pipeline segments to 
mean those pipeline replacement projects where 2 or more miles of 
pipeline have been replaced within any length of 5 contiguous miles of 
pipeline during any 24-month period.

Sec.  192.9 What requirements apply to gathering lines?

    In this final rule, PHMSA has clarified that the RMV and 
alternative equivalent technology requirements being promulgated apply 
to Type A gas gathering pipelines (not Types B or C gathering lines), 
as these pipelines typically have risk profiles similar to transmission 
pipelines.

Sec.  192.18 How To Notify PHMSA

    In this final rule, operators can notify PHMSA in advance of their 
intent to use a technology, method, or compliance timeline that differs 
from that listed in the regulations, when the option for notification 
is specifically provided. PHMSA retains discretion under Sec.  192.18 
to reject, as appropriate, such requests. Accordingly, PHMSA has 
revised this section to provide for a consistent notification procedure 
across part 192 whenever an operator is required to notify PHMSA as a 
part of a requirement.

Sec.  192.179 Transmission Line Valves

    In this final rule, PHMSA is requiring the installation of RMVs or 
alternative equivalent technologies on certain gas pipelines. This 
section specifies that operators must install RMVs, or alternative 
equivalent technologies, on onshore gas pipeline segments with 
diameters greater than or equal to 6 inches that are newly constructed, 
or meet the definition of entirely replaced onshore transmission 
pipeline segments, after April 10, 2023. RMVs and alternative 
equivalent technologies installed in accordance with this section must 
meet the existing valve spacing requirements of this section, and all 
RMVs and alternative equivalent technologies installed in accordance 
with this section must meet the operational requirements outlined in 
Sec.  192.636.
    These installation requirements do not apply to those pipeline 
segments that are in Class 1 or Class 2 locations and that have a PIR 
of less than or equal to 150 feet. Further, the installation 
requirements for entirely replaced onshore pipeline segments only apply 
to those pipeline replacement projects that involve the addition, 
replacement, or removal of a valve.
    If an operator seeks to install alternative equivalent technology 
pursuant to this section, the operator must, in advance of such 
installation, submit a notification making such a request to PHMSA in 
accordance with Sec.  192.18. The operator must include in that 
notification a site-specific technical and safety evaluation 
demonstrating that technology provides an equivalent level of safety to 
an RMV by reference to factors including, but not limited to, the 
following: Design, construction, maintenance, and operating procedures; 
technology design and operational 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.
    If an operator requests use of manual valves as an alternative 
equivalent technology, the notification submitted to PHMSA must also 
demonstrate the site-specific economic, technical, or operational 
infeasibility of installing an RMV (e.g., 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).
    An operator may also submit for PHMSA review, in accordance with 
the notification procedures in Sec.  192.18, a project-specific request 
for extension of the compliance deadline in this section. That 
notification must demonstrate installation of an RMV or alternative 
equivalent technology in connection with near-term construction and 
replacement projects would be economically, technically, or 
operationally infeasible (e.g., by reference to prohibitive economic 
costs, difficulty in securing access rights, component/labor 
availability and procurement lead times, or permitting requirements).
    An operator that replaces pipeline segments is not required to meet 
the valve spacing requirements of this section if the distance between 
each point on the pipeline and the nearest valve does not exceed 4 
miles in Class 4 locations, 7\1/2\ miles in Class 3 locations, and 10 
miles in all other locations.

Sec.  192.610 Change in Class Location: Change in Valve Spacing

    This section specifies RMV and alternative equivalent technology 
requirements when a class location changes. In cases where pipeline 
segments are entirely replaced, as that term is defined in Sec.  192.3, 
to meet the maximum allowable operating pressure in accordance with 
requirements for class location changes under Sec. Sec.  192.611, 
192.619(a), and 192.620, then an operator must install valves, 
including RMVs or alternative equivalent technology, as necessary to 
comply with this part. An operator must install such valves within 24 
months of the class location change.
    If an operator replaces less than 2 miles of pipe in a length of 5 
contiguous miles of pipe during a 24-month period to comply with the 
maximum allowable operating pressure requirements after a class 
location changes, the operator must either: (1) Comply with the valve

[[Page 20973]]

spacing requirements at Sec.  192.179(a), or (2) install or use RMVs or 
alternative equivalent technology so that the entirety of the replaced 
pipeline segment is between 2 RMVs or alternative equivalent technology 
and so that the distance between those valves does not exceed 20 miles. 
Operators are not required to comply with this section if they replace 
less than 1,000 feet of pipe within any single contiguous mile within 
any 24-month period to comply with a class location change.

Sec.  192.615 Emergency Plans

    In this final rule, PHMSA revised paragraphs (a)(2), (a)(6), 
(a)(8), (a)(11), and (a)(12) and the introductory text of (c) in Sec.  
192.615 to require that emergency procedures provide for rupture 
mitigation in response to a rupture event. PHMSA is also requiring that 
operators maintain liaison with and contact the appropriate public 
safety answering point (i.e., 9-1-1 emergency call center), if such a 
service is available, in the event of pipeline emergencies. In lieu of 
communicating with individual fire, police, or other public entities, 
operators may instead establish liaison with appropriate local 
emergency coordinating agencies, such as 9-1-1 emergency call centers 
or county emergency managers, as appropriate.
    PHMSA is requiring, through this final rule, that operators learn 
the responsibilities, resources, jurisdictional areas, and emergency 
contact telephone numbers for each Federal, State, and local government 
organization that may respond to a pipeline emergency involving their 
pipeline facilities, and inform such officials of the operator's 
ability to respond to and communicate during pipeline emergencies. 
PHMSA has not changed the existing requirements for operators to 
maintain liaison with fire, police, and other public officials, as 
appropriate.
    In conjunction with the definition of the ``notification of 
potential rupture,'' PHMSA has in this final rule codified at Sec.  
192.615(a)(12) 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 their written 
procedures. At a minimum, the procedures must specify the sources of 
information, operational factors, and other criteria that the operator 
will use to evaluate a notification of a potential rupture as an actual 
rupture. Those written procedures should also incorporate procedures 
for 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.  192.635(a)(1); or 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).

Sec.  192.617 Investigation of Failures and Incidents

    In this final rule, PHMSA has revised Sec.  192.617 to define the 
elements that an operator must incorporate when conducting a post-event 
analysis of ruptures and other failure events involving the activation 
of RMVs or alternative equivalent technology.
    The revision requires the operator to identify potential preventive 
and mitigative measures that could be taken to reduce or limit the 
release volume and damage from similar events in the future. The post-
incident or -failure review would include, but not be limited to, 
detection and mitigation actions, response time, valve location, valve 
actuation, and SCADA system performance. Upon completing the post-event 
analysis, the operator must develop and implement the lessons learned 
throughout its suite of procedures, including in pertinent operator 
personnel training and qualification programs, and in design, 
construction, testing, maintenance, operations, and emergency procedure 
manuals and specifications. In accordance with this section, an 
operator must also complete a summary of the post-incident or -failure 
review within 90 days of the incident. The operator must conduct 
quarterly status reviews until the investigation is complete and a 
final post-incident summary is prepared. The final post-incident 
summary and all other reviews and analyses produced under the 
requirements of this section must be reviewed, dated, and signed by the 
operator's appropriate senior executive officer. Further, an operator 
must keep the final post-incident summary, all investigation and 
analysis documents used to prepare it, and records of lessons learned 
for the useful life of the pipeline. The requirements to produce a 
summary report are not applicable to gas distribution and Types B and C 
gathering pipelines.
    PHMSA has also modified the existing failure and incident 
investigation requirements at Sec.  192.617 to require operators 
subject to that provision to incorporate lessons learned from those 
investigations into their written procedures, including personnel 
training and qualification programs, and design, construction, testing, 
maintenance, operations, and emergency procedure manuals and 
specifications. PHMSA has otherwise not made changes to the existing 
requirements in this section for operators of gas pipelines to 
establish procedures for analyzing incidents and failures.

Sec.  192.634 Transmission Lines: Onshore Valve Shut-Off for Rupture 
Mitigation

    This section requires operators to install and use RMVs or 
alternative equivalent technology on newly constructed and entirely 
replaced onshore gas pipeline segments with diameters of 6 inches or 
greater. Such valves would be required to be operational within 14 days 
following placing the pipeline segment into service unless the operator 
has submitted for PHMSA review, in accordance with Sec.  192.18, a 
notification that operation of the RMV or alternative equivalent 
technology within that 14-day timeframe is not economically, 
technically, or operationally feasible. An operator may also submit for 
PHMSA review, in accordance with the notification procedures in Sec.  
192.18, a request for extension of the valve installation compliance 
deadline requirements of Sec.  192.179 and this section demonstrating 
that installation of an RMV or alternative equivalent technology in 
connection with particular near-term construction and replacement 
projects would be economically, technically, or operationally 
infeasible (e.g., by reference to prohibitive costs, difficulty in 
securing required access rights and permits, and component/labor 
availability).
    For the purposes of the RMV and alternative equivalent technology 
installation requirements, PHMSA created a definition for a ``shut-off 
segment,'' which is a pipeline segment that is entirely located between 
at least two RMVs or alternative equivalent technologies. If any 
crossover or lateral pipe for commodity receipts or deliveries connects 
to the shut-off segment between the upstream-most and downstream-most 
RMVs or alternative equivalent technologies, the shut-off segment also 
extends to valves on those crossover connections or laterals used for 
receipt or delivery so that, when all valves are closed, there is no 
flow path for commodity to be transported from outside the shut-off 
segment to the rupture site. Laterals that

[[Page 20974]]

connect to shut-off segments and that contribute less than 5 percent of 
the total shut-off segment volume may have RMVs or alternative 
equivalent technologies installed at locations other than mainline 
receipt or delivery points. A shut-off segment can include multiple 
HCAs, and operators are not required to select the closest valve to the 
shut-off segment as an RMV or alternative equivalent as long as the 
proper valve spacing is maintained.
    The requirements of this section apply to all applicable pipe 
replacement projects, even those that do not otherwise directly involve 
the addition or replacement of a valve. Consistent with the 
requirements for RMV and alternative equivalent technology 
installation, this section does not apply to pipe segments in Class 1 
or Class 2 locations that have a PIR less than or equal to 150 feet.
    This section also establishes valve spacing for RMVs and 
alternative equivalent technologies installed in accordance with this 
section, where the distance between such RMVs and alternative 
equivalent technologies must not exceed 8 miles in Class 4 locations, 
15 miles in Class 3 locations, and 20 miles in all other locations.
    Operators using a manual valve as an alternative equivalent 
technology in lieu of an RMV for the purposes of this section must 
appropriately locate personnel to ensure valve shut-off in accordance 
with this section and the RMV performance requirements in Sec.  
192.636.

Sec.  192.635 Notification of Potential Rupture

    In this section, PHMSA provides the criteria for a ``notification 
of potential rupture,'' as that term is defined in Sec.  192.3.

Sec.  192.636 Transmission Lines: Valve Capabilities

    In this section, PHMSA establishes the operational requirements for 
RMVs and alternative equivalent technologies. Following the 
``notification of potential rupture,'' an operator must, after 
identifying a rupture, close such valves as soon as practicable, but no 
later than within 30 minutes (measured from rupture identification). 
Operators may request to plan to leave RMVs or alternative equivalent 
technologies open for longer than 30 minutes following rupture 
identification if the operator previously has coordinated the plan with 
appropriate local emergency responders, notified PHMSA, and adequately 
demonstrated to PHMSA that closing such valves or technologies would be 
detrimental to public safety.
    RMVs and alternative equivalent technologies must be capable of 
being monitored or controlled by remote or on-site personnel, operated 
during all operating conditions, and monitored for valve status. 
Operators using ASVs as RMVs do not need to monitor those valves 
remotely if the operator has the capability to monitor pressures or gas 
flow rate on the pipeline in order to identify and locate a rupture 
pursuant to the requirements of this rulemaking.
    Operators of pipelines in Class 1, non-HCAs may request, within 
their notification under Sec.  192.18 seeking PHMSA review for 
installation of manual valves as alternative equivalent technologies as 
contemplated by this final rule, an exemption from the valve operation 
requirements of Sec.  192.636(b). Operators seeking such an exemption 
must provide for PHMSA review within that notification the closing 
times for those manual valves.

Sec.  192.745 Valve Maintenance: Transmission Lines

    In this final rule, PHMSA is revising Sec.  192.745 by adding 
paragraphs (c), (d), and (e) to incorporate the maintenance, 
inspection, and operator drills required to ensure operators can close 
an RMV or alternative equivalent technology as soon as practicable, but 
no more than 30 minutes, after identification of a rupture. PHMSA is 
finalizing initial validation drill requirements and requirements for 
periodic validation tests for any manually or locally operated valve 
installed as an alternative equivalent technology in lieu of an RMV. 
Operators are not required to close the valves fully during such 
drills; a closure of 25 percent, at a minimum, is sufficient to be 
compliant, unless the operator has information that requires additional 
closure requirements for the valve to be compliant with the 
requirement. If the 30-minute-maximum closure time cannot be achieved 
during the drill, the operator must revise their response efforts and 
repair any valves to achieve compliance as soon as practicable but no 
later than 12 months after the drill. Operators may request, pursuant 
to the notification procedure at Sec.  192.18, an extension of the 12-
month repair timeline if such repair within 12 months would be 
economically, technically, or operationally infeasible (e.g., by 
reference to prohibitive costs, difficulty in securing required access 
rights and permits, long procurement lead times, and component/labor 
availability). Alternative valve shut-off measures must be in place 
within 7 days of a failed drill. In accordance with Sec.  192.631(c) 
and (e), operators must also conduct a point-to-point verification 
between SCADA displays, sensors, communications equipment, and any RCVs 
installed in accordance with Sec. Sec.  192.179 or 192.634.
    Per this final rule, each operator is required to identify 
corrective actions and lessons learned resulting from the validation 
and confirmation drills and share and implement them across its entire 
network of pipeline systems.

Sec.  192.935 What additional preventive and mitigative measure must an 
operator take?

    In this final rule, PHMSA is revising Sec.  192.935(c) to clarify 
the requirements for conducting RMV evaluations for HCAs, particularly 
when an operator installs such valves as preventive and mitigative 
measures to improve response times for pipeline ruptures and mitigate 
the consequences of a rupture. RMVs installed in accordance with this 
section must meet all other RMV requirements in part 192.
    PHMSA is also requiring that risk analyses and assessments 
conducted under this section be reviewed by the operator and certified 
by a senior executive of the company. Review and certification must 
occur at least once per calendar year, with the period between reviews 
not to exceed a period of 15 months, and must also occur within 3 
months of an incident or a safety-related condition. Such analyses and 
assessments must consider new or existing operational and integrity 
matters that could affect rupture-mitigation processes and procedures.

V. Section-by-Section Analysis for Changes to 49 CFR Part 195 for 
Hazardous Liquid Pipelines

Sec.  195.2 Definitions

    Section 195.2 provides definitions for various terms used 
throughout part 195. Most of the requirements of this final rule would 
be triggered by an operator identifying a rupture following the 
notification of a potential rupture. Therefore, PHMSA is amending Sec.  
195.2 to define the ``notification of potential rupture'' in terms of 
notification of, or observation by, an operator of indicia specified in 
Sec.  195.417.
    Once an operator is notified of a potential rupture, they must 
identify the rupture, if one exists. Therefore, PHMSA has established a 
concept of ``rupture identification'' to mean the point when a pipeline 
operator has sufficient information reasonably to determine that a 
rupture occurred. The final rule at Sec.  195.402 requires that 
operators must document, in their operations manual, their method for 
rupture identification. An operator, after

[[Page 20975]]

identifying a rupture, would be required to close the RMVs or 
alternative equivalent technologies necessary to isolate the ruptured 
pipeline segment.
    As a part of this rulemaking, operators are required to install 
RMVs or alternative equivalent technologies on certain pipeline 
segments, including those that are ``entirely replaced onshore 
hazardous liquid or carbon dioxide pipeline segments.'' RMVs are 
defined in this rulemaking to mean ASVs or RCVs that a pipeline 
operator uses to minimize the volume of hazardous liquid or carbon 
dioxide released from the pipeline and to minimize the consequences of 
a rupture. PHMSA has defined entirely replaced onshore hazardous liquid 
or carbon dioxide pipeline segments to mean those pipeline replacement 
projects where 2 or more miles of pipeline have been replaced within 
any length of 5 contiguous miles of pipeline during any 24-month 
period.

Sec.  195.11 What is a regulated rural gathering line and what 
requirements apply?

    Section 195.11 contains the requirements for regulated rural 
gathering pipelines carrying hazardous liquid or carbon dioxide. In 
this final rule, PHMSA is specifying that the only regulated rural 
gathering pipelines that are required to install RMVs or alternative 
equivalent technologies are those pipelines subject to Sec.  
195.260(e), which requires the installation of RMVs or alternative 
equivalent technologies on pipelines that span water crossings more 
than 100 feet wide, from high water mark to high water mark.

Sec.  195.18 How To Notify PHMSA

    In this final rule, operators can notify PHMSA in advance of their 
intent to use a technology, compliance timeline, or method that differs 
from that listed in the regulations, when that option is specifically 
provided in the regulatory text. PHMSA retains discretion under Sec.  
195.18 to reject, as appropriate, such requests. Accordingly, PHMSA has 
revised this section to provide for a consistent notification procedure 
across part 195 whenever an operator is required to notify PHMSA as a 
part of a requirement of this final rule. This provision is similar to 
the notification procedure created for part 192.

Sec.  195.258 Valves: General

    In this final rule, PHMSA is requiring the installation of RMVs or 
alternative equivalent technologies on certain pipelines. This section 
specifies that operators must install RMVs, or alternative equivalent 
technologies, on onshore hazardous liquid or carbon dioxide pipeline 
segments with diameters greater than or equal to 6 inches that are 
constructed, or meet the definition of entirely replaced onshore 
hazardous liquid or carbon dioxide pipeline segments, after April 10, 
2023. RMVs and alternative equivalent technologies installed in 
accordance with this section must meet the existing valve spacing 
requirements of Sec.  195.260, and all alternative equivalent 
technologies installed in accordance with this section must meet the 
operational requirements of RMVs outlined in Sec.  195.419. These 
installation requirements for entirely replaced onshore hazardous 
liquid or carbon dioxide pipeline segments only apply to those pipeline 
replacement projects that involve the addition, replacement, or removal 
of an existing valve.
    If an operator seeks to install alternative equivalent technology 
pursuant to this section, the operator must, in advance of such 
installation, submit a notification making such a request to PHMSA in 
accordance with Sec.  195.18. The operator must include in that 
notification a site-specific technical and safety evaluation 
demonstrating that technology provides an equivalent level of safety to 
an RMV by reference to factors including, but not limited to, the 
following: Design, construction, maintenance, and operating procedures; 
technology design and operational 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.
    If an operator requests use of manual valves as an alternative 
equivalent technology, the notification submitted to PHMSA must also 
demonstrate site-specific economic, technical, or operational 
infeasibility of installing an RMV (e.g., 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.
    An operator may also submit for PHMSA review, in accordance with 
the notification procedures in Sec.  195.18, a project-specific request 
for extension of the compliance deadline in this section. That 
notification must demonstrate installation of an RMV or alternative 
equivalent technology in connection with near-term construction and 
replacement projects would be economically, technically, or 
operationally infeasible (e.g., by reference to prohibitive economic 
costs, difficulty in securing required access rights and permits, and 
component/labor availability).

Sec.  195.260 Valves: Location

    Section 195.260 finalizes requirements for the location of valves 
on newly constructed and entirely replaced onshore hazardous liquid or 
carbon dioxide pipelines, where such pipeline segments installed after 
April 10, 2023, must have valve spacing that does not exceed 15 miles 
for pipelines that could affect HCAs, as that term is defined in Sec.  
195.450. For those pipelines that could not affect HCAs, the valve 
spacing requirements for such pipelines cannot exceed 20 miles. An 
operator installing valves that protect HCAs must install those valves 
at locations determined through the operator's process for identifying 
preventive and mitigative measures established pursuant to Sec.  
195.452(i) and Appendix C, Section B of part 195. An operator may 
submit for PHMSA review, in accordance with the notification procedures 
in Sec.  195.18, a request for extension of the compliance deadline for 
valve installation and spacing in this section. That notification must 
demonstrate that the compliance timeline for valve spacing required by 
this final rule would be economically, technically, or operationally 
infeasible in connection with particular near-term construction and 
replacement projects (e.g., by reference to factors such as access to 
communications and power; terrain; prohibitive cost; component and 
labor availability; ability to secure access rights and necessary 
permits).
    PHMSA has also revised the valve location requirements for those 
pipelines that cross waterways that are more than 100 feet wide from 
high water mark to high water mark. Accordingly, in this final rule, 
operators must install valves at locations outside of the 100-year 
flood plain or otherwise install valves that are equipped with control 
equipment that would not be made inoperable by flood conditions.\49\ 
Additionally, the maximum spacing between valves protecting multiple

[[Page 20976]]

adjacent water crossings cannot exceed 1 mile.
---------------------------------------------------------------------------

    \49\ A 100-year flood plain is an area that has a 1-in-100 
chance of having a flood event that could be equaled or exceeded in 
any 1 year, and it has an average recurrence interval of 100 years. 
100-year flood plains are determined by the Federal Emergency 
Management Agency, which operates the official flood hazard Mapping 
Service Center in support of the National flood insurance program, 
and they offer flood zone maps online. If another agency, such as a 
State authority, is responsible for determining the 100-year flood 
plain for the area where the pipeline is located, the operator 
should use those resources and documents.
---------------------------------------------------------------------------

    In this section, PHMSA has also finalized spacing requirements for 
HVL pipelines in high-population areas or other populated areas, as 
defined in Sec.  195.450. These pipelines must have a maximum valve 
spacing of 7\1/2\ miles if they have been constructed or where 2 or 
more miles of pipeline have been replaced within a span of 5 contiguous 
miles within a 24-month period, following April 10, 2023. The maximum 
valve spacing for HVL pipelines can be increased by 1.25 times the 
distance to a maximum of a 9\3/8\-mile spacing if the operator submits 
for PHMSA review, in accordance with Sec.  195.18, within its 
notification (1) an evaluation of the safety of the alternative 
spacing, referencing technical and safety factors including, but not 
limited to, the following: Design, construction, maintenance, and 
operating procedures for pertinent pipeline segments; potential 
consequences to the environment and the public from a rupture on the 
pertinent pipeline segments; and mitigation measures in the event of a 
rupture; and (2) a demonstration that the installation of a valve at 
the otherwise-required spacing is economically, technically or 
operationally infeasible (e.g., 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).
    Additionally, operators may notify PHMSA, using the procedure at 
Sec.  195.18, if, in particular cases, the valve installation or valve 
spacing requirements of certain paragraphs of this section are not 
necessary to achieve an equivalent level of safety at a particular 
site. That notification must include a supporting technical and safety 
evaluation referencing technical and safety factors including, but not 
limited to, the following: Design, construction, maintenance, and 
operating procedures for pertinent pipeline segments; potential 
consequences to the environment and the public from a rupture on the 
pertinent pipeline segments; and mitigation measures in the event of a 
rupture.

Sec.  195.402 Procedural Manual for Operations, Maintenance, and 
Emergencies

    In this final rule, PHMSA revised Sec.  195.402 to require that 
emergency procedures provide for rupture mitigation in response to a 
rupture event. PHMSA is also requiring that operators maintain liaison 
with and contact the appropriate public safety answering point (i.e., 
9-1-1 emergency call center), if such a service is available, in the 
event of pipeline emergencies. In lieu of communicating with individual 
fire, police, or other public entities, operators may instead establish 
liaison with appropriate local emergency coordinating agencies, such as 
9-1-1 emergency call centers or county emergency managers, as 
appropriate.
    PHMSA is requiring, through this final rule, that operators must 
learn the responsibilities, resources, jurisdictional areas, and 
emergency contact telephone numbers for each Federal, State, and local 
government organization that may respond to a pipeline emergency 
involving their pipeline facilities, and inform such officials of the 
operator's ability to respond to and communicate during pipeline 
emergencies. PHMSA has not changed the existing requirements for 
operators to maintain liaison with fire, police, and other public 
officials, as appropriate.
    In conjunction with the definition of a ``notification of potential 
rupture,'' PHMSA has in this final rule codified at Sec.  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. At a minimum, 
the procedures must specify the sources of information, operational 
factors, and other criteria that the operator will use to evaluate a 
notification of a potential rupture as an actual rupture. Those written 
procedures should also incorporate procedures for 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.  
195.417(a)(1); or 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).
    Further, PHMSA has revised this section to define the elements that 
an operator must incorporate when conducting a post-accident or -
failure analysis of ruptures and other accident and failure events 
involving the activation of RMVs or alternative equivalent 
technologies. PHMSA has not made changes, otherwise, to the existing 
requirements in this section for operators of hazardous liquid and 
carbon dioxide pipelines to establish procedures for analyzing 
accidents and failures.
    The revision requires the operator to identify potential preventive 
and mitigative measures that could be taken to reduce or limit the 
release volume and damage from similar events in the future. The post-
incident review would include but not be limited to detection and 
mitigation actions, response time, valve location, valve actuation, and 
SCADA system performance. Upon completing the post-accident analysis, 
the operator must develop and implement the lessons learned throughout 
its suite of procedures, including in pertinent operator personnel 
training and qualification programs, and in design, construction, 
testing, maintenance, operations, and emergency procedure manuals and 
specifications. In accordance with this section, an operator must also 
complete a summary of the post-incident review within 90 days of the 
incident, and, while the investigation is pending, conduct quarterly 
status reviews until the investigation is complete and a final post-
incident summary is prepared. The final post-incident summary and all 
other reviews and analyses produced under the requirements of this 
section must be reviewed, dated, and signed by the operator's 
appropriate senior executive officer. Further, an operator must keep 
the final post-incident summary, all investigation and analysis 
documents used to prepare it, and records of lessons learned for the 
useful life of the pipeline. The requirements to produce a summary 
report are not applicable to gas distribution pipelines.
    PHMSA has also modified the failure and accident investigation 
requirements at Sec.  195.402 to require operators subject to that 
provision to incorporate lessons learned from those investigations into 
their written procedures, including personnel training and 
qualification programs, and design, construction, testing, maintenance, 
operations, and emergency procedure manuals and specifications.

Sec.  195.417 Notification of Potential Rupture

    In this section, PHMSA provides the criteria for a ``notification 
of potential rupture,'' as that term is defined in Sec.  195.2.

Sec.  195.418 Valves: Onshore Valve Shut-Off for Rupture Mitigation

    This section requires operators to install or use RMVs or 
alternative equivalent technologies on many newly

[[Page 20977]]

constructed and entirely replaced onshore hazardous liquid or carbon 
dioxide pipeline segments with diameters of 6 inches or greater. Such 
valves would be required to be operational within 14 days of placing 
the pipeline segment into service unless the operator has submitted for 
PHMSA review, in accordance with the notification procedure at Sec.  
195.18, a request for extension demonstrating that operation of that 
RMV or alternative equivalent technology within that 14-day timeframe 
is not economically, technically, or operationally feasible. The 
requirements of this section apply to all applicable pipe replacement 
projects, even those that do not otherwise directly involve the 
addition or replacement of a valve.
    For the purposes of the RMV and alternative equivalent technology 
installation requirements, PHMSA created a definition for a ``shut-off 
segment,'' which is a pipeline segment that is entirely located between 
at least two RMVs or alternative equivalent technologies. If any 
crossover or lateral pipe for commodity receipts or deliveries connects 
to the shut-off segment between the upstream-most and downstream-most 
RMV or alternative equivalent technology, the shut-off segment also 
extends to valves on those crossover connections or laterals, whether 
those laterals are used for receipt or delivery, so that, when all 
valves are closed, there is no flow path for commodity to be 
transported from outside the shut-off segment to the rupture site. 
Laterals that connect to shut-off segments and that contribute less 
than 5 percent of the total shut-off segment volume may have RMVs or 
alternative equivalent technologies installed at locations other than 
mainline receipt or delivery points. A shut-off segment can include 
multiple HCAs, and operators are not required to select the closest 
valve to the shut-off segment as an RMV or alternative equivalent 
technology as long as the proper valve spacing is maintained.
    This section also establishes valve spacing for RMVs or alternative 
equivalent technology installed in accordance with this section, where 
the distance between such RMVs and alternative equivalent technologies 
must not exceed 15 miles for lines carrying non-HVLs, and 7\1/2\ miles 
for lines carrying HVLs. The maximum valve spacing intervals for RMVs 
and alternative equivalent technologies on pipelines carrying HVLs may 
be increased by 1.25 times the spacing distance to a maximum of 9\3/8\ 
miles, subject to review by PHMSA of an operator's request 
demonstrating that installation of a valve at a 7-mile to a 7\1/2\-mile 
spacing is economically, technically, or operationally infeasible.
    Operators using a manual valve as an alternative equivalent 
technology in lieu of an RMV for the purposes of this section must 
appropriately designate and locate personnel near the valve to ensure 
valve shut-off in accordance with this section and the RMV performance 
requirements in Sec.  195.419.

Sec.  195.419 Valve Capabilities

    In this section, PHMSA establishes the operational requirements for 
RMVs and alternative equivalent technologies installed pursuant to this 
final rule. Following a ``notification of potential rupture,'' an 
operator must identify whether a rupture is occurring on their system 
and close RMVs and alternative equivalent technologies as soon as 
practicable, but no later than within 30 minutes of rupture 
identification, or, if applicable, no later than the shut-down times 
used in calculating a worst-case discharge in accordance with Sec.  
194.105(b)(1), whichever shut-off time is a shorter time interval.
    RMVs and alternative equivalent technologies must be capable of 
being monitored or controlled by remote or on-site personnel, operated 
during all operating conditions, and monitored for valve status. 
Operators using ASVs as RMVs do not need to monitor those valves 
remotely if the operator has the capability to monitor pressures or 
product flow rate on the pipeline in order to identify and locate a 
rupture.
    Operators of pipelines in non-HCAs or of segments that could not 
affect an HCA may submit for PHMSA review, within a notification under 
Sec.  195.18 requesting installation of manual valves as an alternative 
equivalent technology, an exemption from the valve operation 
requirements of Sec.  195.419(b). An operator seeking such an exemption 
must provide for PHMSA review within that notification the closing 
times for those manual valves.

Sec.  195.420 Valve Maintenance

    In this final rule, PHMSA is revising Sec.  195.420 to incorporate 
the maintenance, inspection, and operator drills required to ensure 
operators can close an RMV or alternative equivalent technology 
installed under this final rule as soon as practicable, but within 30 
minutes following rupture identification or within their shut-down 
times used in calculating the worst-case discharge in accordance with 
Sec.  194.105(b)(1), whichever is a shorter time interval. PHMSA is 
finalizing initial validation drill requirements and requirements for 
periodic confirmation drills for any manually or locally operated valve 
used as an alternative equivalent technology in lieu of an RMV. 
Operators are not required to close the valves fully during such 
drills; a closure of 25 percent, at a minimum, is sufficient to be 
compliant. If the 30-minute-maximum closure time cannot be achieved 
during the drill, or shorter time pursuant to its part 194 worst-case 
discharge calculations, the operator must revise their response efforts 
and repair any valves to achieve compliance as soon as practicable but 
no later than 12 months after the drill. Operators may request, 
pursuant to the notification procedure at Sec.  195.18, an extension of 
the 12-month repair timeline if such repair within 12 months would be 
economically, technically, or operationally infeasible (e.g., by 
reference to prohibitive costs, difficulty in securing required access 
rights and permits, long procurement lead times, and component/labor 
availability). Alternative valve shut-off measures must be in place 
within 7 days of a failed drill. For each RCV installed under 
Sec. Sec.  195.258(c) or 195.418, the operator must conduct a point-to-
point verification between SCADA displays, the installed valves, 
sensors, and communications equipment in accordance with Sec.  
195.446(c) and (e), or perform an equivalent verification.
    Per this final rule, operators are required to identify corrective 
actions and lessons learned resulting from the validation and 
confirmation drills and share and implement them across its entire 
network of pipeline systems.

Sec.  195.452 Pipeline Integrity Management in High Consequence Areas

    In this final rule, PHMSA is revising Sec.  195.452(i)(4) to 
clarify the requirements for conducting emergency flow restricting 
device evaluations for HCAs, particularly when an operator installs 
such valves as preventive and mitigative measures to improve response 
times for, and mitigate the consequences of, pipeline ruptures. 
Emergency flow restriction devices that are installed in accordance 
with this section must meet all RMV requirements in part 195.
    PHMSA is also requiring that risk analyses and assessments 
conducted under this section be completed prior to placing into service 
all onshore pipelines with diameters of 6 inches or greater and that 
are constructed or that have had 2 or more miles of pipeline replaced 
within 5 contiguous miles within a 24-month period after April 10, 
2023. The implementation of emergency

[[Page 20978]]

flow restricting device findings for any RMVs installed must meet Sec.  
195.418.

VI. Regulatory Analyses and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published pursuant to the authority granted to 
the Secretary of Transportation by the Federal Pipeline Safety Statutes 
(49 U.S.C. 60101 et seq.). Section 60102(a) authorizes issuance of 
regulations governing design, installation, inspection, emergency plans 
and procedures, testing, construction, extension, operation, 
replacement, and maintenance of pipeline facilities. The final rule 
also implements a statutory mandate at 49 U.S.C. 60102(n) requiring the 
Secretary to issue regulations requiring the installation of RMVs or 
equivalent technology on new and entirely replaced transmission lines. 
See also 49 U.S.C. 5103 (regulatory authority to prescribe regulations 
for transportation of hazardous materials), and 30 U.S.C. 185(w)(3)) 
(authority to prescribe reporting requirements for pipelines traversing 
Federal lands). The Secretary delegated these authorities to the PHMSA 
Administrator in 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 (``Regulatory Planning and Review'') \50\ 
requires that ``agencies should assess all costs and benefits of 
available regulatory alternatives, including the alternative of not 
regulating. Agencies should consider quantifiable measures and 
qualitative measures of costs and benefits that are difficult to 
quantify.'' Further, Executive Order 12866 requires that ``agencies 
should maximize net benefits (including potential economic, 
environmental, public health and safety, and other advantages; 
distributive impacts; and equity), unless a statute requires another 
regulatory approach.'' Similarly, DOT Order 2100.6A (``Rulemaking and 
Guidance Procedures'') requires that regulations issued by PHMSA and 
other DOT Operating Administrations should consider an assessment of 
the potential benefits, costs, and other important impacts of the 
proposed action and should quantify (to the extent practicable) the 
benefits, costs, and any significant distributional impacts, including 
any environmental impacts.
---------------------------------------------------------------------------

    \50\ 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------

    This action has been determined to be significant under Executive 
Order 12866. The final rule has been reviewed by the Office of 
Management and Budget (OMB) in accordance with Executive Order 12866 
and is consistent with the requirements of Executive Order 12866, 49 
U.S.C. 60102(b)(5), and DOT Order 2100.6A. The Office of Information 
and Regulatory Affairs (OIRA) has not designated this rule as a ``major 
rule'' as defined by the Congressional Review Act (5 U.S.C. 801 et 
seq.).
    Executive Order 12866 and DOT Order 2100.6A also require PHMSA to 
provide a meaningful opportunity for public participation, which also 
reinforces requirements for notice and comment under the Administrative 
Procedure Act (5 U.S.C. 551 et seq.). Therefore, in the NPRM, PHMSA 
sought public comment on its proposed revisions to the Federal Pipeline 
Safety Regulations and the preliminary cost and benefit analyses in the 
Preliminary RIA, as well as any information that could assist in 
quantifying the costs and benefits of this rulemaking. Those comments 
are addressed in this final rule, and additional discussion about the 
costs and benefits of the final rule are provided within the RIA posted 
in the rulemaking docket.
    The table below summarizes the annualized costs for the provisions 
in the final rule at a 3 percent and a 7 percent discount rate:

               Table 1--Annualized Costs of the Final Rule
                            [Millions 2019$]
------------------------------------------------------------------------
                                                        7%         3%
                    System type                      Discount   Discount
                                                       rate       rate
------------------------------------------------------------------------
Natural gas.......................................       $2.5       $1.0
Hazardous liquid..................................        3.4        1.5
                                                   ---------------------
  Total...........................................        5.9        2.5
------------------------------------------------------------------------

    The benefits of the final rule consist of improved safety and 
avoided unquantified environmental harms (including, but not limited 
to, unquantified greenhouse gas emissions) from 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. Benefits of the final rule will depend on 
the degree to which compliance actions result in additional safety 
measures, relative to the baseline, and the effectiveness of these 
measures in preventing or mitigating future pipeline releases or other 
incidents.

C. Executive Order 13132: Federalism

    PHMSA analyzed this final rule in accordance with Executive Order 
13132 (``Federalism'').\51\ Executive Order 13132 requires agencies to 
assure meaningful and timely input by State and local officials in the 
development of regulatory policies that may have ``substantial direct 
effects on the States, on the relationship between the national 
government and the States, or on the distribution of power and 
responsibilities among the various levels of government.''
---------------------------------------------------------------------------

    \51\ 64 FR 43255 (Aug. 10, 1999).
---------------------------------------------------------------------------

    The final rule does not have a substantial direct effect on the 
State and local governments, the relationship between the Federal 
government and the States, or the distribution of power and 
responsibilities among the various levels of government. This 
rulemaking action does not impose substantial direct compliance costs 
on State and local governments. Section 60104(c) of Title 49 of the 
United States Code prohibits certain State safety regulation of 
interstate pipelines. States can augment pipeline safety requirements 
for intrastate pipelines regulated by PHMSA, but may not approve safety 
requirements less stringent than those required by Federal law. A State 
may also regulate an intrastate pipeline facility that PHMSA does not 
regulate. The preemptive effect of this final rule is limited to the 
minimum level necessary to achieve the objectives of the statutory 
authorities under which the final rule is promulgated. Therefore, the 
consultation and funding requirements of Executive Order 13132 do not 
apply.

D. Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires 
agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for 
any final rule subject to notice-and-comment rulemaking under the 
Administrative Procedure Act unless the agency head certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. This final rule was developed in accordance 
with Executive Order 13272 (``Proper Consideration of Small Entities in 
Agency Rulemaking'') \52\ to promote compliance with the Regulatory 
Flexibility Act and to ensure that the potential impacts of the 
rulemaking on small entities has been properly considered.
---------------------------------------------------------------------------

    \52\ 67 FR 53461 (Aug. 16, 2002).
---------------------------------------------------------------------------

    PHMSA prepared a FRFA, which is available in the docket for the 
rulemaking. In it, PHMSA certifies that the rule will not have a 
significant impact on a substantial number of small entities.

[[Page 20979]]

E. National Environmental Policy Act

    The National Environmental Policy Act (42 U.S.C. 4321 et seq.; 
NEPA) requires Federal agencies to consider the consequences of major 
Federal actions and prepare a detailed statement on actions 
significantly affecting the quality of the human environment. The 
Council on Environmental Quality implementing regulations (40 CFR parts 
1500-1508) require Federal agencies to conduct an environmental review 
considering (1) the need for the action, (2) alternatives to the 
action, (3) probable environmental impacts of the action and 
alternatives, and (4) the agencies and persons consulted during the 
consideration process. DOT Order 5610.1C (``Procedures for Considering 
Environmental Impacts'') establishes departmental procedures for 
evaluation of environmental impacts under NEPA and its implementing 
regulations.
    PHMSA has completed its NEPA analysis. Based on the final 
Environmental Assessment (EA), PHMSA determined that an environmental 
impact statement is not required for this rulemaking because it will 
not have a significant impact on the human environment. The final EA 
and Finding of No Significant Impact have been placed into the docket 
and address comments received on an earlier draft EA.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    PHMSA analyzed this final rule per the principles and criteria in 
Executive Order 13175 (``Consultation and Coordination With Indian 
Tribal Governments'') \53\ and DOT Order 5301.1 (``Department of 
Transportation Policies, Programs, and Procedures Affecting American 
Indians, Alaska Natives, and Tribes''). Executive Order 13175 requires 
agencies to assure meaningful and timely input from Tribal Government 
representatives in the development of rules that significantly or 
uniquely affect Tribal communities by imposing ``substantial direct 
compliance costs'' or ``substantial direct effects'' on such 
communities or the relationship and distribution of power between the 
Federal Government and Tribes.
---------------------------------------------------------------------------

    \53\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------

    PHMSA assessed the impact of the rulemaking and determined that it 
would not significantly or uniquely affect Tribal communities or Tribal 
governments. The rulemaking's regulatory amendments are facially 
neutral and would have broad, national scope; PHMSA, therefore, does 
not expect this rulemaking to significantly or uniquely affect Tribal 
communities, much less impose substantial compliance costs on Native 
American Tribal governments or mandate Tribal action. And insofar as 
PHMSA expects the rulemaking will improve pipeline safety and reduce 
environmental risks, PHMSA does not expect it would entail 
disproportionately high adverse risks for Tribal communities. PHMSA 
also received no comments alleging ``substantial direct compliance 
costs'' or ``substantial direct effects'' on Tribal communities and 
Governments. For these reasons, PHMSA has determined the funding and 
consultation requirements of Executive Order 13175 and DOT Order 5301.1 
do not apply.

G. Executive Order 13211

    Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'') \54\ 
requires Federal agencies to prepare a Statement of Energy Effects for 
any ``significant energy action.'' Executive Order 13211 defines a 
``significant energy action'' as any action by an agency (normally 
published in the Federal Register) that promulgates, or is expected to 
lead to the promulgation of, a final rule or regulation that (1) (i) is 
a significant regulatory action under Executive Order 12866 or any 
successor order and (ii) is likely to have a significant adverse effect 
on the supply, distribution, or use of energy (including a shortfall in 
supply, price increases, and increased use of foreign supplies); or (2) 
is designated by the Administrator of the OIRA as a significant energy 
action.
---------------------------------------------------------------------------

    \54\ 66 FR 28355 (May 18, 2001).
---------------------------------------------------------------------------

    This final rule is a significant action under Executive Order 
12866; however, it is expected to have an annual effect on the economy 
of less than $100 million. Further, this action is not likely to have a 
significant adverse effect on the supply, distribution, or use of 
energy in the United States. The Administrator of OIRA has not 
designated the final rule as a significant energy action. For 
additional discussion of the anticipated economic impact of this 
rulemaking, please review the RIA posted in the rulemaking docket.

H. Paperwork Reduction Act

    Under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), 
no person is required to respond to an information collection unless it 
has been approved by OMB and displays a valid OMB control number. 
Pursuant to implementing regulations at 5 CFR 1320.8(d), PHMSA is 
required to provide interested members of the public and affected 
agencies with an opportunity to comment on information collection and 
recordkeeping requests.
    PHMSA published an NPRM seeking public comment on its proposed 
revisions to the Federal Pipeline Safety Regulations finalized in this 
rulemaking. Based on comments received and the updated provisions 
contained within this final rule, PHMSA is expanding the notification 
and recordkeeping requirements for gas and hazardous liquid pipeline 
operators. The provisions in this final rule include the following 
Paperwork Reduction Act impacts:
    Operators are required to document certain procedures and to 
maintain records pertaining to various aspects of their RMV and 
alternative equivalent technology operations. Operators who have 
experienced a rupture or RMV shut-off are required to complete a post-
incident or -accident analysis. The summary of this analysis, all 
documents used to prepare it, and records of lessons learned must be 
kept for the useful life of the pipeline.
    Operators must also develop written rupture identification 
procedures to evaluate and identify whether a notification of potential 
rupture is an actual rupture event or non-rupture event. These 
procedures must, at a minimum, specify the sources of information, 
operational factors, and other criteria that operator personnel use to 
evaluate a notification of potential rupture.
    The final rule (at 49 CFR 192.179 and 49 CFR 195.258) requires 
operators who elect to use alternative equivalent technology to notify 
PHMSA's Office of Pipeline Safety at least 90 days in advance of use. 
An operator choosing this option must submit a technical and safety 
evaluation (including design, construction, and operating procedures) 
for the alternative equivalent technology to the Associate 
Administrator of Pipeline Safety with the notification. PHMSA would 
then have 90 days to object to the alternative equivalent technology 
via letter from the Associate Administrator of Pipeline Safety; 
otherwise, the alternative equivalent technology would be acceptable 
for use. Operators who wish to use a manual valve as an alternative 
equivalent technology will also be required to include within their 
notification to PHMSA an explanation that installation of an RMV would 
be economically, technically, or operationally infeasible.
    An operator may seek PHMSA's approval for an exemption from several 
other regulatory installation and

[[Page 20980]]

operational requirements under the final rule by notifying PHMSA in 
certain instances. For example, an operator of a gas pipeline may plan 
to leave an RMV open for more than 30 minutes following rupture 
identification if the operator demonstrates to PHMSA, in accordance 
with the notification procedures in Sec.  192.18, that closing an RMV, 
or alternative equivalent technology would be detrimental to public 
safety. Likewise, for hazardous liquid pipeline segments not in an HCA 
and which could not affect an HCA, an operator may request exemption 
from specified requirements if it can demonstrate to PHMSA, in 
accordance with the notification procedures in Sec.  195.18, that 
installing an otherwise-required RMV, or alternative equivalent 
technology, would be economically, technically, or operationally 
infeasible. Similarly, the maximum valve spacing for HVL pipelines can 
be increased by 1.25 times the distance to a maximum of 9 \3/8\ miles 
if the operator submits a notification for PHMSA review demonstrating 
that the installation of a valve at the otherwise-required spacing is 
economically, technically, or operationally infeasible. Lastly, the 
final rule also identifies procedures for operators of gas and 
hazardous liquid lines to submit for PHMSA review a notification 
requesting extension of required timelines (e.g., for RMV or 
alternative equivalent technology installation, RMV operability post-
installation) specified in the final rule.
    PHMSA proposes to create an information collection under OMB 
Control Number 2137-0637 titled, ``Rupture Mitigation Valve 
Recordkeeping Requirements'' to account for the expanded recordkeeping 
requirements in this final rule. PHMSA also proposes to create an 
information collection under OMB Control Number 2137-0638 titled, 
``Rupture Mitigation Valve Notification Requirements'' to account for 
the expanded notification requirements in this final rule.
    PHMSA will request approval of these information collections from 
the Office of Management and Budget (OMB) based on the requirements 
that trigger components of the Paperwork Reduction Act and will notify 
the public through a separate notice published in the Federal Register 
upon OMB approval of the information collection requirements.
    The following information is provided for each of these information 
collections: (1) Title of the information collection; (2) OMB control 
number; (3) current expiration date; (4) type of request; (5) abstract 
of the information collection activity; (6) description of affected 
public; (7) estimate of total annual reporting and recordkeeping 
burden; and (8) frequency of collection. The information collection 
burdens are estimated as follows:
    1. Title: ``Rupture Mitigation Valve Recordkeeping Requirements.''
    OMB Control Number: 2137-0637.
    Current Expiration Date: To be determined by OMB.
    Abstract: The ``Amendments to parts 192 and 195 to Require Valve 
Installation and Minimum Rupture Detection Standards Final Rule'' 
requires operators of gas and hazardous liquid pipelines to document 
certain procedures and to maintain records pertaining to various 
aspects of their RMV and alternative equivalent technology operations. 
Operators who have experienced a rupture or RMV valve shut-off are 
required to complete a post-incident review. The post-incident summary, 
all investigation and analysis documents used to prepare it, and 
records of lessons learned must be kept for the life of the pipeline. 
PHMSA estimates that it will take operators, on average, 40 hours to 
comply with this requirement.
    Operators must also develop written rupture identification 
procedures to evaluate and identify whether a notification of potential 
rupture is an actual rupture event or non-rupture event as soon as 
practicable. These procedures must, at a minimum, specify the sources 
of information, operational factors, and other criteria that operator 
personnel use to evaluate a notification of potential rupture. PHMSA 
estimates that it will take operators 40 hours to comply with this 
requirement. Operators are also required to maintain certain records if 
they experience certain circumstances involving their RMV operations. 
On average, PHMSA expects that it will take operators 8 hours to 
complete these recordkeeping requirements.
    PHMSA estimates that 1,812 operators (1,304 natural gas and 508 
hazardous liquid operators) will be potentially impacted by these 
requirements. At minimum, all 1,812 operators will be required to 
develop written rupture identification procedures. PHMSA estimates 46 
of these operators will experience a rupture that will require the 
completion of a post-incident or -accident summary. PHMSA expects that 
10 percent of the affected community will be subject to the various 
other recordkeeping requirements. As a result, PHMSA expects this 
information collection to result in 4,213 responses and 85,724 burden 
hours annually.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 4,213.
    Total Annual Burden Hours: 85,724.
    Frequency of Collection: On occasion.
    2. Title: ``Rupture Mitigation Valve Notification Requirements.''
    OMB Control Number: 2137-0638.
    Current Expiration Date: To be determined by OMB.
    Abstract: The ``Amendments to Parts 192 and 195 to Require Valve 
Installation and Minimum Rupture Detection Standards Final Rule'' 
requires operators to notify PHMSA in certain instances regarding 
installation and operation of RMVs and alternative equivalent 
technologies. 49 CFR 192.179 and 195.258 require operators who elect to 
use alternative equivalent technology to notify the Office of Pipeline 
Safety at least 90 days in advance of use. An operator choosing this 
option must include a technical and safety evaluation, including 
design, construction, and operating procedures for the alternative 
equivalent technology with the notification. Operators who wish to use 
a manual valve as an alternative equivalent technology will also be 
required to include within their notification to PHMSA an explanation 
that installation of an RMV would be economically, technically, or 
operationally infeasible. PHMSA expects most operators to use standard 
technology and, as such, estimates this notification requirement will 
result in approximately four responses annually. PHMSA estimates each 
operator will spend 40 hours annually compiling the necessary 
components of this notification requirement.
    Operators must notify PHMSA if an RMV cannot be made operational 
within 14 days of installation. Operators must also notify PHMSA if a 
valve cannot be repaired or replaced within 12 months. PHMSA expects 
roughly 10 percent of operators to experience these circumstances 
taking 2 hours to complete the notification requirement.
    An operator may seek exemption from certain regulatory requirements 
by notifying PHMSA in certain instances. For example, an operator may 
plan to leave an RMV open for more than 30 minutes following rupture 
identification if the operator demonstrates to PHMSA, that closing an 
RMV, or alternative equivalent technology, would be detrimental to 
public safety.
    Likewise, for hazardous liquid pipeline segments not in an HCA 
which could not affect an HCA, an operator may request exemption from 
certain requirements if it can demonstrate to

[[Page 20981]]

PHMSA that installing an otherwise-required RMV, or alternative 
equivalent technology, would be economically, technically, or 
operationally infeasible. PHMSA expects 10 percent of operators to make 
each of these and other notifications annually. PHMSA estimates that it 
will take operators, on average, 8 hours to make these notifications.
    Affected Public: Operators of PHMSA-Regulated Pipelines.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 598.
    Total Annual Burden Hours: 2,378.
    Frequency of Collection: On occasion.
    Questions regarding these information collections should be 
directed to Angela Hill, Office of Pipeline Safety (PHP-30), Pipeline 
and Hazardous Materials Safety Administration, 2nd Floor, 1200 New 
Jersey Avenue SE, Washington, DC 20590-0001. Telephone: 202-366-1246.

I. Unfunded Mandates Reform Act of 1995

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1501 et seq.) 
requires agencies to assess the effects of Federal regulatory actions 
on State, local, and Tribal governments, and the private sector. For 
any NPRM or final rule that includes a Federal mandate that may result 
in the expenditure by State, local, and Tribal governments, in the 
aggregate, or by the private sector of $100 million or more (adjusted 
annually for inflation) in any given year, the agency must prepare, 
among other things, a written statement that qualitatively and 
quantitatively assesses the costs and benefits of the Federal mandate.
    As explained in the RIA, PHMSA determined that this final rule does 
not impose enforceable duties on State, local, or Tribal governments or 
on the private sector of $100 million or more (adjusted annually for 
inflation) in any one year. A copy of the RIA is available for review 
in the docket. Therefore, the Department has determined that no 
assessment is required pursuant to UMRA.

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
\55\ at http://www.dot.gov/privacy.
---------------------------------------------------------------------------

    \55\ 65 FR 19476 (Apr. 11, 2000).
---------------------------------------------------------------------------

K. Regulation Identifier Number

    A regulation identifier number (RIN) is assigned to each regulatory 
action listed in the Unified Agenda of Federal Regulations. The 
Regulatory Information Service Center publishes the Unified Agenda in 
April and October of each year. The RIN number contained in the heading 
of this document can be used to cross-reference this action with the 
Unified Agenda.

L. Executive Order 13609 and International Trade Analysis

    Executive Order 13609 (``Promoting International Regulatory 
Cooperation'') \56\ requires agencies consider whether the impacts 
associated with significant variations between domestic and 
international regulatory approaches are unnecessary or may impair the 
ability of American business to export and compete internationally. In 
meeting shared challenges involving health, safety, labor, security, 
environmental, and other issues, international regulatory cooperation 
can identify approaches that are at least as protective as those that 
are or would be adopted in the absence of such cooperation. 
International regulatory cooperation can also reduce, eliminate, or 
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------

    \56\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

    Similarly, the Trade Agreements Act of 1979 (Pub. L. 96-39), as 
amended by the Uruguay Round Agreements Act (Pub. L. 103-465), 
prohibits Federal agencies from establishing any standards or engaging 
in related activities that create unnecessary obstacles to the foreign 
commerce of the United States. For purposes of these requirements, 
Federal agencies may participate in the establishment of international 
standards, so long as the standards have a legitimate domestic 
objective, such as providing for safety, and do not operate to exclude 
imports that meet this objective. The statute also requires 
consideration of international standards and, where appropriate, that 
they be the basis for U.S. standards.
    PHMSA participates in the establishment of international standards 
to protect the safety of the American public. PHMSA has assessed the 
effects of the rulemaking and determined that it will not cause 
unnecessary obstacles to foreign trade.

M. Environmental Justice

    DOT Order 5610.2(b) and Executive Orders 12898 (``Federal Actions 
to Address Environmental Justice in Minority Populations and Low-Income 
Populations''),\57\ 13985 (``Advancing Racial Equity and Support for 
Underserved Communities Through the Federal Government''),\58\ 13990, 
and 14008 require DOT operational administrations to achieve 
environmental justice as part of their mission by identifying and 
addressing, as appropriate, disproportionately high and adverse human 
health or environmental effects, including interrelated social and 
economic effects, of their programs, policies, and activities on 
minority populations, low-income populations, and other underserved 
disadvantaged communities.
---------------------------------------------------------------------------

    \57\ 59 FR 7629 (Feb. 16, 1994).
    \58\ 86 FR 7009 (Jan. 20, 2021).
---------------------------------------------------------------------------

    PHMSA has evaluated this final rule under DOT Order 5610.2(b) and 
the Executive Orders listed above and determined it will not cause 
disproportionately high and adverse human health and environmental 
effects on minority populations, low-income populations, or other 
underserved and disadvantaged communities. The rulemaking is facially 
neutral and national in scope; it is neither directed toward a 
particular population, region, or community, nor is it expected to 
adversely impact any particular population, region, or community. And 
insofar as PHMSA expects the rulemaking would reduce the safety and 
environmental risks associated with affected natural gas and hazardous 
liquid pipelines, many of which are sited in the vicinity of 
environmental justice communities,\59\ PHMSA does not expect the 
regulatory amendments introduced by this final rule would entail 
disproportionately high adverse risks for minority populations, low-
income populations, or other underserved and other disadvantaged 
communities in the vicinity of those pipelines. Lastly, as explained in 
final EA, PHMSA expects that the regulatory amendments in this final 
rule will yield GHG emissions reductions, thereby reducing the risks 
posed by anthropogenic climate change to minority, low-income, 
underserved, and other disadvantaged populations and communities.
---------------------------------------------------------------------------

    \59\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and 
Transmission Pipelines and Social Vulnerability in the United 
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding 
that natural gas gathering and transmission infrastructure is 
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------

List of Subjects

49 CFR Part 192

    Gas, Natural gas, Pipeline safety, Reporting and recordkeeping 
requirements.

[[Page 20982]]

49 CFR Part 195

    Anhydrous ammonia, Carbon dioxide, Petroleum, Pipeline safety, 
Reporting and recordkeeping requirements.

    In consideration of the foregoing, PHMSA amends 49 CFR parts 192 
and 195 as follows:

PART 192--TRANSPORTATION OF NATURAL GAS AND OTHER GAS BY PIPELINE: 
MINIMUM FEDERAL SAFETY STANDARDS

0
1. The authority citation for part 192 continues to read as follows:

    Authority:  30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et seq., 
and 49 CFR 1.97.


0
2. In Sec.  192.3, definitions for ``entirely replaced onshore 
transmission pipeline segments'', ``notification of potential 
rupture'', and ``rupture-mitigation valve'' are added in alphabetical 
order to read as follows:


Sec.  192.3   Definitions.

* * * * *
    Entirely replaced onshore transmission pipeline segments means, for 
the purposes of Sec. Sec.  192.179 and 192.634, where 2 or more miles, 
in the aggregate, of onshore transmission pipeline have been replaced 
within any 5 contiguous miles of pipeline within any 24-month period.
* * * * *
    Notification of potential rupture means the notification to, or 
observation by, an operator of indicia identified in Sec.  192.635 of a 
potential unintentional or uncontrolled release of a large volume of 
gas from a pipeline.
* * * * *
    Rupture-mitigation valve (RMV) means an automatic shut-off valve 
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to 
minimize the volume of gas released from the pipeline and to mitigate 
the consequences of a rupture.
* * * * *

0
3. In Sec.  192.9, paragraphs (d)(1) and (e)(1)(i) are revised to read 
as follows:


Sec.  192.9   What requirements apply to gathering lines?

* * * * *
    (d) * * *
    (1) If a line is new, replaced, relocated, or otherwise changed, 
the design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines. Compliance with Sec. Sec.  192.67, 192.127, 
192.179(e), 192.179(f), 192.205, 192.227(c), 192.285(e), 192.506, 
192.634, and 192.636 is not required.
* * * * *
    (e) * * *
    (1) * * *
    (i) Except as provided in paragraph (h) of this section for pipe 
and components made with composite materials, the design, installation, 
construction, initial inspection, and initial testing of a new, 
replaced, relocated, or otherwise changed Type C gathering line, must 
be done in accordance with the requirements in subparts B though G and 
J of this part applicable to transmission lines. Compliance with 
Sec. Sec.  192.67, 192.127, 192.179(e), 192.179(f), 192.205, 
192.227(c), 192.285(e), 192.506, 192.634, and 192.636 is not required;
* * * * *

0
4. In Sec.  192.18, paragraph (c) is revised to read as follows:


Sec.  192.18   How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec.  192.8, Sec.  192.9, Sec.  192.179, Sec.  192.506, Sec.  192.607, 
Sec.  192.619, Sec.  192.624, Sec.  192.632, Sec.  192.634, Sec.  
192.636, Sec.  192.710, Sec.  192.712, Sec.  192.745, Sec.  192.921, or 
Sec.  192.937, a notification for use of a different integrity 
assessment method, analytical method, sampling approach, or technique 
(e.g., ``other technology'' or ``alternative equivalent technology'') 
than otherwise prescribed in those sections, that notification must be 
submitted to PHMSA for review at least 90 days in advance of using the 
other method, approach, compliance timeline, or technique. An operator 
may proceed to use the other method, approach, compliance timeline, or 
technique 91 days after submitting the notification unless it receives 
a letter from the Associate Administrator for Pipeline Safety informing 
the operator that PHMSA objects to the proposal, or that PHMSA requires 
additional time and/or more information to conduct its review.

0
5. In Sec.  192.179, paragraphs (e) through (h) are added to read as 
follows:


Sec.  192.179   Transmission line valves.

* * * * *
    (e) For onshore transmission pipeline segments with diameters 
greater than or equal to 6 inches that are constructed after April 10, 
2023, the operator must install rupture-mitigation valves (RMV) or an 
alternative equivalent technology whenever a valve must be installed to 
meet the appropriate valve spacing requirements of this section. An 
operator seeking to use alternative equivalent technology must notify 
PHMSA in accordance with the procedures set forth in paragraph (g) of 
this section. All RMVs and alternative equivalent technologies 
installed pursuant to this paragraph must meet the requirements of 
Sec. Sec.  192.634 and 192.636. Exempted from this paragraph's 
installation requirements are pipeline segments in Class 1, or Class 2 
locations that have a potential impact radius (PIR), as defined in 
Sec.  192.903, of 150 feet or less. An operator may request an 
extension of the installation compliance deadline requirements of this 
paragraph (e) if it can demonstrate to PHMSA, in accordance with the 
notification procedures in Sec.  192.18, that those installation 
compliance deadlines would be economically, technically, or 
operationally infeasible for a particular new pipeline.
    (f) For entirely replaced onshore transmission pipeline segments, 
as defined in Sec.  192.3, with diameters greater than or equal to 6 
inches and that are installed after April 10, 2023, the operator must 
install RMVs or an alternative equivalent technology whenever a valve 
must be installed to meet the appropriate valve spacing requirements of 
this section. An operator seeking to use alternative equivalent 
technology must notify PHMSA in accordance with the procedures set 
forth in paragraph (g) of this section. All RMVs and alternative 
equivalent technologies installed pursuant to this paragraph must meet 
the requirements of Sec. Sec.  192.634 and 192.636. The requirements of 
this paragraph apply when the applicable pipeline replacement project 
involves a valve, either through addition, replacement, or removal. 
This paragraph's installation requirements do not apply to pipe 
segments in Class 1 or Class 2 locations that have a PIR, as defined in 
Sec.  192.903, that is less than or equal to 150 feet. An operator may 
request an extension of the installation compliance deadline 
requirements of this paragraph if it can demonstrate to PHMSA, in 
accordance with the notification procedures in Sec.  192.18, that those 
installation compliance deadlines would be economically, technically, 
or operationally infeasible for a particular pipeline replacement 
project.
    (g) If an operator elects to use alternative equivalent technology 
in accordance with paragraph (e) or (f) of this section, the operator 
must notify PHMSA in accordance with the procedures in Sec.  192.18. 
The operator must include a technical and safety evaluation in its 
notice to PHMSA. Valves that are installed as alternative equivalent 
technology must comply with Sec. Sec.  192.634 and 192.636. An operator 
requesting use of manual valves as an alternative equivalent

[[Page 20983]]

technology must also include within the notification submitted to PHMSA 
a demonstration that installation of an RMV as otherwise required would 
be economically, technically, or operationally infeasible. An operator 
may use a manual compressor station valve at a continuously manned 
station as an alternative equivalent technology, and use of such valve 
would not require a notification to PHMSA in accordance with Sec.  
192.18, but it must comply with Sec.  192.636.
    (h) The valve spacing requirements of paragraph (a) of this section 
do not apply to pipe replacements on a pipeline if the distance between 
each point on the pipeline and the nearest valve does not exceed:
    (1) Four (4) miles in Class 4 locations, with a total spacing 
between valves no greater than 8 miles;
    (2) Seven-and-a-half (7\1/2\) miles in Class 3 locations, with a 
total spacing between valves no greater than 15 miles; or
    (3) Ten (10) miles in Class 1 or 2 locations, with a total spacing 
between valves no greater than 20 miles.

0
6. Section 192.610 is added to read as follows:


Sec.  192.610   Change in class location: Change in valve spacing.

    (a) If a class location change on a transmission pipeline occurs 
after October 5, 2022, and results in pipe replacement, of 2 or more 
miles, in the aggregate, within any 5 contiguous miles within a 24-
month period, to meet the maximum allowable operating pressure (MAOP) 
requirements in Sec.  192.611, Sec.  192.619, or Sec.  192.620, then 
the requirements in Sec. Sec.  192.179, 192.634, and 192.636, as 
applicable, apply to the new class location, and the operator must 
install valves, including rupture-mitigation valves (RMV) or 
alternative equivalent technologies, as necessary, to comply with those 
sections. Such valves must be installed within 24 months of the class 
location change in accordance with the timing requirement in Sec.  
192.611(d) for compliance after a class location change.
    (b) If a class location change occurs after October 5, 2022, and 
results in pipe replacement of less than 2 miles within 5 contiguous 
miles during a 24-month period, to meet the MAOP requirements in Sec.  
192.611, Sec.  192.619, or Sec.  192.620, then within 24 months of the 
class location change, in accordance with Sec.  192.611(d), the 
operator must either:
    (1) Comply with the valve spacing requirements of Sec.  192.179(a) 
for the replaced pipeline segment; or
    (2) Install or use existing RMVs or alternative equivalent 
technologies so that the entirety of the replaced pipeline segments are 
between at least two RMVs or alternative equivalent technologies. The 
distance between RMVs and alternative equivalent technologies for the 
replaced segment must not exceed 20 miles. The RMVs and alternative 
equivalent technologies must comply with the applicable requirements of 
Sec.  192.636.
    (c) The provisions of paragraph (b) of this section do not apply to 
pipeline replacements that amount to less than 1,000 feet within any 
one contiguous mile during any 24-month period.

0
7. In Sec.  192.615, paragraphs (a)(2), (6), (8), and (11) are revised, 
paragraph (a)(12) is added, and paragraph (c) introductory text is 
revised to read as follows:


Sec.  192.615   Emergency plans.

    (a) * * *
    (2) Establishing and maintaining adequate means of communication 
with the appropriate public safety answering point (i.e., 9-1-1 
emergency call center), where direct access to a 9-1-1 emergency call 
center is available from the location of the pipeline, and fire, 
police, and other public officials. Operators may establish liaison 
with the appropriate local emergency coordinating agencies, such as 9-
1-1 emergency call centers or county emergency managers, in lieu of 
communicating individually with each fire, police, or other public 
entity. An operator must determine the responsibilities, resources, 
jurisdictional area(s), and emergency contact telephone number(s) for 
both local and out-of-area calls of each Federal, State, and local 
government organization that may respond to a pipeline emergency, and 
inform such officials about the operator's ability to respond to a 
pipeline emergency and the means of communication during emergencies.
* * * * *
    (6) Taking necessary actions, including but not limited to, 
emergency shutdown, valve shut-off, or pressure reduction, in any 
section of the operator's pipeline system, to minimize hazards of 
released gas to life, property, or the environment.
* * * * *
    (8) Notifying the appropriate public safety answering point (i.e., 
9-1-1 emergency call center) where direct access to a 9-1-1 emergency 
call center is available from the location of the pipeline, and fire, 
police, and other public officials, of gas pipeline emergencies to 
coordinate and share information to determine the location of the 
emergency, including both planned responses and actual responses during 
an emergency. The operator must immediately and directly notify the 
appropriate public safety answering point or other coordinating agency 
for the communities and jurisdictions in which the pipeline is located 
after receiving a notification of potential rupture, as defined in 
Sec.  192.3, to coordinate and share information to determine the 
location of any release, regardless of whether the segment is subject 
to the requirements of Sec.  192.179, Sec.  192.634, or Sec.  192.636.
* * * * *
    (11) Actions required to be taken by a controller during an 
emergency in accordance with the operator's emergency plans and 
requirements set forth in Sec. Sec.  192.631, 192.634, and 192.636.
    (12) Each operator must develop written rupture identification 
procedures to evaluate and identify whether a notification of potential 
rupture, as defined in Sec.  192.3, is an actual rupture event or a 
non-rupture event. These procedures must, at a minimum, specify the 
sources of information, operational factors, and other criteria that 
operator personnel use to evaluate a notification of potential rupture 
and identify an actual rupture. For operators installing valves in 
accordance with Sec.  192.179(e), Sec.  192.179(f), or that are subject 
to the requirements in Sec.  192.634, those procedures must provide for 
rupture identification as soon as practicable.
* * * * *
    (c) Each operator must establish and maintain liaison with the 
appropriate public safety answering point (i.e., 9-1-1 emergency call 
center) where direct access to a 9-1-1 emergency call center is 
available from the location of the pipeline, as well as fire, police, 
and other public officials, to:
* * * * *

0
8. Section 192.617 is revised to read as follows:


Sec.  192.617   Investigation of failures and incidents.

    (a) Post-failure and incident procedures. Each operator must 
establish and follow procedures for investigating and analyzing 
failures and incidents as defined in Sec.  191.3, including sending the 
failed pipe, component, or equipment for laboratory testing or 
examination, where appropriate, for the purpose of determining the 
causes and contributing factor(s) of the failure or incident and

[[Page 20984]]

minimizing the possibility of a recurrence.
    (b) Post-failure and incident lessons learned. Each operator must 
develop, implement, and incorporate lessons learned from a post-failure 
or incident review into its written procedures, including personnel 
training and qualification programs, and design, construction, testing, 
maintenance, operations, and emergency procedure manuals and 
specifications.
    (c) Analysis of rupture and valve shut-offs. If an incident on an 
onshore gas transmission pipeline or a Type A gathering pipeline 
involves the closure of a rupture-mitigation valve (RMV), as defined in 
Sec.  192.3, or the closure of alternative equivalent technology, the 
operator of the pipeline must also conduct a post-incident analysis of 
all of the factors that may have impacted the release volume and the 
consequences of the incident and identify and implement operations and 
maintenance measures to prevent or minimize the consequences of a 
future incident. The requirements of this paragraph (c) are not 
applicable to distribution pipelines or Types B and C gas gathering 
pipelines. The analysis must include all relevant factors impacting the 
release volume and consequences, including, but not limited to, the 
following:
    (1) Detection, identification, operational response, system shut-
off, and emergency response communications, based on the type and 
volume of the incident;
    (2) Appropriateness and effectiveness of procedures and pipeline 
systems, including supervisory control and data acquisition (SCADA), 
communications, valve shut-off, and operator personnel;
    (3) Actual response time from identifying a rupture following a 
notification of potential rupture, as defined at Sec.  192.3, to 
initiation of mitigative actions and isolation of the pipeline segment, 
and the appropriateness and effectiveness of the mitigative actions 
taken;
    (4) Location and timeliness of actuation of RMVs or alternative 
equivalent technologies; and
    (5) All other factors the operator deems appropriate.
    (d) Rupture post-failure and incident summary. If a failure or 
incident on an onshore gas transmission pipeline or a Type A gathering 
pipeline involves the identification of a rupture following a 
notification of potential rupture, or the closure of an RMV (as those 
terms are defined in Sec.  192.3), or the closure of an alternative 
equivalent technology, the operator of the pipeline must complete a 
summary of the post-failure or incident review required by paragraph 
(c) of this section within 90 days of the incident, and while the 
investigation is pending, conduct quarterly status reviews until the 
investigation is complete and a final post-incident summary is 
prepared. The final post-failure or incident summary, and all other 
reviews and analyses produced under the requirements of this section, 
must be reviewed, dated, and signed by the operator's appropriate 
senior executive officer. The final post-failure or incident summary, 
all investigation and analysis documents used to prepare it, and 
records of lessons learned must be kept for the useful life of the 
pipeline. The requirements of this paragraph (d) are not applicable to 
distribution pipelines or Types B and C gas gathering pipelines.

0
9. Section 192.634 is added to read as follows:


Sec.  192.634   Transmission lines: Onshore valve shut-off for rupture 
mitigation.

    (a) Applicability. For new or entirely replaced onshore 
transmission pipeline segments with diameters of 6 inches or greater 
that are located in high-consequence areas (HCA) or Class 3 or Class 4 
locations and that are installed after April 10, 2023, an operator must 
install or use existing rupture-mitigation valves (RMV), or an 
alternative equivalent technology, according to the requirements of 
this section and Sec. Sec.  192.179 and 192.636. RMVs and alternative 
equivalent technologies must be operational within 14 days of placing 
the new or replaced pipeline segment into service. An operator may 
request an extension of this 14-day operation requirement if it can 
demonstrate to PHMSA, in accordance with the notification procedures in 
Sec.  192.18, that application of that requirement would be 
economically, technically, or operationally infeasible. The 
requirements of this section apply to all applicable pipe replacement 
projects, even those that do not otherwise involve the addition or 
replacement of a valve. This section does not apply to pipe segments in 
Class 1 or Class 2 locations that have a potential impact radius (PIR), 
as defined in Sec.  192.903, that is less than or equal to 150 feet.
    (b) Maximum spacing between valves. RMVs, or alternative equivalent 
technology, must be installed in accordance with the following 
requirements:
    (1) Shut-off segment. For purposes of this section, a ``shut-off 
segment'' means the segment of pipe located between the upstream valve 
closest to the upstream endpoint of the new or replaced Class 3 or 
Class 4 or HCA pipeline segment and the downstream valve closest to the 
downstream endpoint of the new or replaced Class 3 or Class 4 or HCA 
pipeline segment so that the entirety of the segment that is within the 
HCA or the Class 3 or Class 4 location is between at least two RMVs or 
alternative equivalent technologies. If any crossover or lateral pipe 
for gas receipts or deliveries connects to the shut-off segment between 
the upstream and downstream valves, the shut-off segment also must 
extend to a valve on the crossover connection(s) or lateral(s), such 
that, when all valves are closed, there is no flow path for gas to be 
transported to the rupture site (except for residual gas already in the 
shut-off segment). Multiple Class 3 or Class 4 locations or HCA 
segments may be contained within a single shut-off segment. The 
operator is not required to select the closest valve to the shut-off 
segment as the RMV, as that term is defined in Sec.  192.3, or the 
alternative equivalent technology. An operator may use a manual 
compressor station valve at a continuously manned station as an 
alternative equivalent technology, but it must be able to be closed 
within 30 minutes following rupture identification, as that term is 
defined at Sec.  192.3. Such a valve used as an alternative equivalent 
technology would not require a notification to PHMSA in accordance with 
Sec.  192.18.
    (2) Shut-off segment valve spacing. A pipeline subject to paragraph 
(a) of this section must have RMVs or alternative equivalent technology 
on the upstream and downstream side of the pipeline segment. The 
distance between RMVs or alternative equivalent technologies must not 
exceed:
    (i) Eight (8) miles for any Class 4 location,
    (ii) Fifteen (15) miles for any Class 3 location, or
    (iii) Twenty (20) miles for all other locations.
    (3) Laterals. Laterals extending from shut-off segments that 
contribute less than 5 percent of the total shut-off segment volume may 
have RMVs or alternative equivalent technologies that meet the 
actuation requirements of this section at locations other than mainline 
receipt/delivery points, as long as all of the laterals contributing 
gas volumes to the shut-off segment do not contribute more than 5 
percent of the total shut-off segment gas volume based upon maximum 
flow volume at the operating pressure. For laterals that are 12 inches 
in diameter or less, a check valve that allows gas to flow freely in 
one direction and contains a mechanism to automatically prevent flow in 
the other direction may be used as an alternative equivalent technology 
where it is

[[Page 20985]]

positioned to stop flow into the shut-off segment. Such check valves 
that are used as an alternative equivalent technology in accordance 
with this paragraph are not subject to Sec.  192.636, but they must be 
inspected, operated, and remediated in accordance with Sec.  192.745, 
including for closure and leakage to ensure operational reliability. An 
operator using such a check valve as an alternative equivalent 
technology must notify PHMSA in accordance with Sec. Sec.  192.18 and 
192.179 develop and implement maintenance procedures for such equipment 
that meet Sec.  192.745.
    (4) Crossovers. An operator may use a manual valve as an 
alternative equivalent technology in lieu of an RMV for a crossover 
connection if, during normal operations, the valve is closed to prevent 
the flow of gas by the use of a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator. The operator must develop and implement 
operating procedures and document that the valve has been closed and 
locked in accordance with the operator's lock-out and tag-out 
procedures to prevent the flow of gas. An operator using such a manual 
valve as an alternative equivalent technology must notify PHMSA in 
accordance with Sec. Sec.  192.18 and 192.179.
    (c) Manual operation upon identification of a rupture. Operators 
using a manual valve as an alternative equivalent technology as 
authorized pursuant to Sec. Sec.  192.18 and 192.179 must develop and 
implement operating procedures that appropriately designate and locate 
nearby personnel to ensure valve shut-off in accordance with this 
section and Sec.  192.636. Manual operation of valves must include time 
for the assembly of necessary operating personnel, the acquisition of 
necessary tools and equipment, driving time under heavy traffic 
conditions and at the posted speed limit, walking time to access the 
valve, and time to shut off all valves manually, not to exceed the 
maximum response time allowed under Sec.  192.636(b).

0
10. Section 192.635 is added to read as follows:


Sec.  192.635   Notification of potential rupture.

    (a) As used in this part, a ``notification of potential rupture'' 
refers to the notification of, or observation by, an operator (e.g., by 
or to its controller(s) in a control room, field personnel, nearby 
pipeline or utility personnel, the public, local responders, or public 
authorities) of one or more of the below indicia of a potential 
unintentional or uncontrolled release of a large volume of gas from a 
pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the 
pipeline's normal operating pressures, as defined in the operator's 
written procedures. The operator must establish in its written 
procedures that an unanticipated or unplanned pressure loss is outside 
of the pipeline's normal operating pressures when there is a pressure 
loss greater than 10 percent occurring within a time interval of 15 
minutes or less, unless the operator has documented in its written 
procedures the operational need for a greater pressure-change threshold 
due to pipeline flow dynamics (including changes in operating pressure, 
flow rate, or volume), that are caused by fluctuations in gas demand, 
gas receipts, or gas deliveries; or
    (2) An unanticipated or unexplained flow rate change, pressure 
change, equipment function, or other pipeline instrumentation 
indication at the upstream or downstream station that may be 
representative of an event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large 
volume of gas, a fire, or an explosion in the immediate vicinity of the 
pipeline.
    (b) A notification of potential rupture occurs when an operator 
first receives notice of or observes an event specified in paragraph 
(a) of this section.

0
11. Section 192.636 is added to read as follows:


Sec.  192.636   Transmission lines: Response to a rupture; capabilities 
of rupture-mitigation valves (RMVs) or alternative equivalent 
technologies.

    (a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMVs), as defined in Sec.  192.3, or alternative 
equivalent technologies, installed pursuant to Sec. Sec.  192.179(e), 
(f), and (g) and 192.634.
    (b) Rupture identification and valve shut-off time. An operator 
must, as soon as practicable but within 30 minutes of rupture 
identification (see Sec.  192.615(a)(12)), fully close any RMVs or 
alternative equivalent technologies necessary to minimize the volume of 
gas released from a pipeline and mitigate the consequences of a 
rupture.
    (c) Open valves. An operator may leave an RMV or alternative 
equivalent technology open for more than 30 minutes, as required by 
paragraph (b) of this section, if the operator has previously 
established in its operating procedures and demonstrated within a 
notice submitted under Sec.  192.18 for PHMSA review, that closing the 
RMV or alternative equivalent technology would be detrimental to public 
safety. The request must have been coordinated with appropriate local 
emergency responders, and the operator and emergency responders must 
determine that it is safe to leave the valve open. Operators must have 
written procedures for determining whether to leave an RMV or 
alternative equivalent technology open, including plans to communicate 
with local emergency responders and minimize environmental impacts, 
which must be submitted as part of its notification to PHMSA.
    (d) Valve monitoring and operation capabilities. An RMV, as defined 
in Sec.  192.3, or alternative equivalent technology, must be capable 
of being monitored or controlled either remotely or by on-site 
personnel as follows:
    (1) Operated during normal, abnormal, and emergency operating 
conditions;
    (2) Monitored for valve status (i.e., open, closed, or partial 
closed/open), upstream pressure, and downstream pressure. For automatic 
shut-off valves (ASV), 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 within each pipeline segment located between RMVs or 
alternative equivalent technologies to identify and locate a rupture. 
Pipeline segments that use manual valves or other alternative 
equivalent technologies must have the capability to monitor pressures 
or gas flow rates on the pipeline to identify and locate a rupture; and
    (3) Have a back-up power source to maintain SCADA systems or other 
remote communications for remote-control valve (RCV) or automatic shut-
off valve (ASV) operational status, or be monitored and controlled by 
on-site personnel.
    (e) Monitoring of valve shut-off response status. The position and 
operational status of an RMV must be appropriately monitored through 
electronic communication with remote instrumentation or other 
equivalent means. An operator does not need to monitor remotely an 
ASV's status if the operator has the capability to monitor pressures or 
gas flow rate on the pipeline to identify and locate a rupture.
    (f) Flow modeling for automatic shut-off valves. Prior to using an 
ASV as an RMV, an operator must conduct flow modeling for the shut-off 
segment and any laterals that feed the shut-off segment, so that the 
valve will close within 30 minutes or less following rupture 
identification, consistent with the operator's procedures, and in 
accordance with Sec.  192.3 and this section. The flow modeling must

[[Page 20986]]

include the anticipated maximum, normal, or any other flow volumes, 
pressures, or other operating conditions that may be encountered during 
the year, not exceeding a period of 15 months, and it must be modeled 
for the flow between the RMVs or alternative equivalent technologies, 
and any looped pipelines or gas receipt tie-ins. If operating 
conditions change that could affect the ASV set pressures and the 30-
minute valve closure time after notification of potential rupture, as 
defined at Sec.  192.3, an operator must conduct a new flow model and 
reset the ASV set pressures prior to the next review for ASV set 
pressures in accordance with Sec.  192.745. The flow model must include 
a time/pressure chart for the segment containing the ASV if a rupture 
occurs. An operator must conduct this flow modeling prior to making 
flow condition changes in a manner that could render the 30-minute 
valve closure time unachievable.
    (g) Manual valves in non-HCA, Class 1 locations. For pipeline 
segments in a Class 1 location that do not meet the definition of a 
high consequence area (HCA), an operator submitting a notification 
pursuant to Sec. Sec.  192.18 and 192.179 for use of manual valves as 
an alternative equivalent technology may also request an exemption from 
the requirements of Sec.  192.636(b).

0
12. In Sec.  192.745, paragraphs (c) through (f) are added to read as 
follows:


Sec.  192.745   Valve maintenance: Transmission lines.

* * * * *
    (c) For each remote-control valve (RCV) installed in accordance 
with Sec.  192.179 or Sec.  192.634, an operator must conduct a point-
to-point verification between SCADA system displays and the installed 
valves, sensors, and communications equipment, in accordance with Sec.  
192.631(c) and (e).
    (d) For each alternative equivalent technology installed on an 
onshore pipeline under Sec.  192.179(e) or (f) or Sec.  192.634 that is 
manually or locally operated (i.e., not a rupture-mitigation valve 
(RMV), as that term is defined in Sec.  192.3):
    (1) Operators must achieve a valve closure time of 30 minutes or 
less, pursuant to Sec.  192.636(b), through an initial drill and 
through periodic validation as required in paragraph (d)(2) of this 
section. An operator must review and document the results of each phase 
of the drill response to validate the total response time, including 
confirming the rupture, and valve shut-off time as being less than or 
equal to 30 minutes after rupture identification.
    (2) Within each pipeline system and within each operating or 
maintenance field work unit, operators must randomly select a valve 
serving as an alternative equivalent technology in lieu of an RMV for 
an annual 30-minute-total response time validation drill that simulates 
worst-case conditions for that location to ensure compliance with Sec.  
192.636. Operators are not required to close the valve fully during the 
drill; a minimum 25 percent valve closure is sufficient to demonstrate 
compliance with drill requirements unless the operator has operational 
information that requires an additional closure percentage for 
maintaining reliability. The response drill must occur at least once 
each calendar year, with intervals not to exceed 15 months. Operators 
must include in their written procedures the method they use to 
randomly select which alternative equivalent technology is tested in 
accordance with this paragraph.
    (3) If the 30-minute-maximum response time cannot be achieved 
during the drill, the operator must revise response efforts to achieve 
compliance with Sec.  192.636 as soon as practicable but no later than 
12 months after the drill. Alternative valve shut-off measures must be 
in place in accordance with paragraph (e) of this section within 7 days 
of a failed drill.
    (4) Based on the results of response-time drills, the operator must 
include lessons learned in:
    (i) Training and qualifications programs;
    (ii) Design, construction, testing, maintenance, operating, and 
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing 
improvement.
    (5) The requirements of this paragraph (d) do not apply to manual 
valves who, pursuant to Sec.  192.636(g), have been exempted from the 
requirements of Sec.  192.636(b).
    (e) Each operator must develop and implement remedial measures to 
correct any valve installed on an onshore pipeline under Sec.  
192.179(e) or (f) or Sec.  192.634 that is indicated to be inoperable 
or unable to maintain effective shut-off as follows:
    (1) Repair or replace the valve as soon as practicable but no later 
than 12 months after finding that the valve is inoperable or unable to 
maintain effective shut-off. An operator must request an extension from 
PHMSA in accordance with Sec.  192.18 if repair or replacement of a 
valve within 12 months would be economically, technically, or 
operationally infeasible; and
    (2) Designate an alternative valve acting as an RMV within 7 
calendar days of the finding while repairs are being made and document 
an interim response plan to maintain safety. Such valves are not 
required to comply with the valve spacing requirements of this part.
    (f) An operator using an ASV as an RMV, in accordance with 
Sec. Sec.  192.3, 192.179, 192.634, and 192.636, must document and 
confirm the ASV shut-in pressures, in accordance with Sec.  192.636(f), 
on a calendar year basis not to exceed 15 months. ASV shut-in set 
pressures must be proven and reset individually at each ASV, as 
required, on a calendar year basis not to exceed 15 months.

0
13. In Sec.  192.935, paragraph (c) is revised and paragraph (f) is 
added to read as follows:


Sec.  192.935   What additional preventive and mitigative measures must 
an operator take?

* * * * *
    (c) Risk analysis for gas releases and protection against ruptures. 
If an operator determines, based on a risk analysis, that a rupture-
mitigation valve (RMV) or alternative equivalent technology would be an 
efficient means of adding protection to a high-consequence area (HCA) 
in the event of a gas release, an operator must install the RMV or 
alternative equivalent technology. In making that determination, an 
operator must, at least, evaluate the following factors--timing of leak 
detection and pipe shutdown capabilities, the type of gas being 
transported, operating pressure, the rate of potential release, 
pipeline profile, the potential for ignition, and location of nearest 
response personnel. An RMV or alternative equivalent technology 
installed under this paragraph must meet all of the other applicable 
requirements in this part.
* * * * *
    (f) Periodic evaluations. Risk analyses and assessments conducted 
under paragraph (c) of this section must be reviewed by the operator 
and certified by a senior executive of the company, for operational 
matters that could affect rupture-mitigation processes and procedures. 
Review and certification must occur once per calendar year, with the 
period between reviews not to exceed 15 months, and must also occur 
within 3 months of an incident or safety-related condition, as those 
terms are defined at Sec. Sec.  191.3 and 191.23, respectively.

[[Page 20987]]

PART 195--TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE

0
14. The authority citation for part 195 continues to read as follows:

    Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 5103, 60101 et. seq., 
and 49 CFR 1.97.


0
15. In Sec.  195.2, definitions for ``entirely replaced onshore 
hazardous liquid or carbon dioxide line segments'', ``notification of 
potential rupture'', and ``rupture-mitigation valve'' are added in 
alphabetical order to read as follows:


Sec.  195.2   Definitions.

* * * * *
    Entirely replaced onshore hazardous liquid or carbon dioxide 
pipeline segments, for the purposes of Sec. Sec.  195.258, 195.260, and 
195.418, means where 2 or more miles of pipe, in the aggregate, have 
been replaced within any 5 contiguous miles within any 24-month period.
* * * * *
    Notification of Potential Rupture means the notification to, or 
observation by, an operator of indicia identified in Sec.  195.417 of a 
potential unintentional or uncontrolled release of a large volume of 
commodity from a pipeline.
* * * * *
    Rupture-mitigation valve (RMV) means an automatic shut-off valve 
(ASV) or a remote-control valve (RCV) that a pipeline operator uses to 
minimize the volume of hazardous liquid or carbon dioxide released from 
the pipeline and to mitigate the consequences of a rupture.
* * * * *

0
16. In Sec.  195.11, paragraph (b)(2) is revised to read as follows:


Sec.  195.11   What is a regulated rural gathering line and what 
requirements apply?

* * * * *
    (b) * * *
    (2) For steel pipelines contracted, replaced, relocated, or 
otherwise changed after July 3, 2009:
    (i) Design, install, construct, initially inspect, and initially 
test the pipeline in compliance with this part, unless the pipeline is 
converted under Sec.  195.5.
    (ii) Except for pipelines subject to Sec.  195.260(e), such 
pipelines are not subject to the rupture-mitigation valve (RMV) and 
alternative equivalent technology requirements in Sec. Sec.  195.258(c) 
and (d), 195.418, and 195.419.
* * * * *

0
17. Section 195.18 is added to read as follows:


Sec.  195.18   How to notify PHMSA.

    (a) An operator must provide any notification required by this part 
by:
    (1) Sending the notification by electronic mail to 
<a href="/cdn-cgi/l/email-protection#83caede5ecf1eee2f7eaecedd1e6f0ecf6f1e0e6f0cee2ede2e4e6f1c3e7ecf7ade4ecf5"><span class="__cf_email__" data-cfemail="61280f070e130c0015080e0f3304120e14130204122c000f0006041321050e154f060e17">[email protected]</span></a>; or
    (2) Sending the notification by mail to ATTN: Information Resources 
Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New 
Jersey Ave. SE, Washington, DC 20590.
    (b) An operator must also notify the appropriate State or local 
pipeline safety authority when an applicable pipeline segment is 
located in a State where OPS has an interstate agent agreement, or an 
intrastate pipeline segment is regulated by that State.
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec.  195.258, Sec.  195.260, Sec.  195.418, Sec.  195.419, Sec.  
195.420 or Sec.  195.452 a notification requesting use of a different 
integrity assessment method, analytical method, sampling approach, 
compliance timeline, or technique (e.g., ``other technology'' or 
``alternative equivalent technology'') than otherwise prescribed in 
those sections, that notification must be submitted to PHMSA for review 
at least 90 days in advance of using that other method, approach, 
compliance timeline, or technique. An operator may proceed to use the 
other method, approach, compliance timeline, or technique 91 days after 
submittal of the notification unless it receives a letter from the 
Associate Administrator of Pipeline Safety informing the operator that 
PHMSA objects to the proposal, or that PHMSA requires additional time 
and/or information to conduct its review.

0
18. In Sec.  195.258, paragraphs (c) through (e) are added to read as 
follows:


Sec.  195.258   Valves: General.

* * * * *
    (c) For all onshore hazardous liquid or carbon dioxide pipeline 
segments with diameters greater than or equal to 6 inches that are 
constructed after April 10, 2023, the operator must install rupture-
mitigation valves (RMV) or an alternative equivalent technology 
whenever a valve must be installed to meet the appropriate valve 
spacing requirements of this section and Sec.  195.260. An operator 
using alternative equivalent technology must notify PHMSA in accordance 
with the procedure in paragraph (e) of this section. All RMVs and 
alternative equivalent technology installed as required by this section 
must meet the requirements of Sec.  195.419. An operator may request an 
extension of the installation compliance deadline requirements of this 
paragraph if it can demonstrate to PHMSA, in accordance with the 
notification procedures in Sec.  195.18, that those installation 
deadline requirements would be economically, technically, or 
operationally infeasible for a particular new pipeline.
    (d) For all entirely replaced onshore hazardous liquid or carbon 
dioxide pipeline segments with diameters greater than or equal to 6 
inches that have been replaced after April 10, 2023, the operator must 
install RMVs or an alternative equivalent technology whenever a valve 
must be installed to meet the appropriate valve spacing requirements of 
this section. An operator using alternative equivalent technology must 
notify PHMSA in accordance with the procedure in paragraph (e) of this 
section. All valves installed as required by this section must meet the 
requirements of Sec.  195.419. The requirements of this paragraph (d) 
apply when the applicable pipeline replacement project involves a 
valve, either through addition, replacement, or removal. An operator 
may request an extension of the installation compliance deadline 
requirements of this paragraph if it can demonstrate to PHMSA, in 
accordance with the notification procedures in Sec.  195.18, that those 
installation deadline requirements would be economically, technically, 
or operationally infeasible for a particular pipeline replacement 
project.
    (e) If an operator elects to use alternative equivalent technology 
in accordance with paragraph (c) or (d) of this section, the operator 
must notify PHMSA in accordance with Sec.  195.18. The operator must 
include a technical and safety evaluation in its notice to PHMSA. 
Valves that are installed as alternative equivalent technology must 
comply with Sec. Sec.  195.418, 195.419, and 195.420. An operator 
requesting use of manual valves as an alternative equivalent technology 
must also include within the notification submitted to PHMSA a 
demonstration that installation of an RMV as otherwise required would 
be economically, technically, or operationally infeasible. An operator 
may use a manual compressor station valve at a continuously manned 
station as an alternative equivalent technology. Such a valve used as 
an alternative equivalent technology would not require a notification 
to PHMSA in accordance with Sec.  195.18, but it must comply with 
Sec. Sec.  195.419 and 195.420.

0
19. Section 195.260 is revised to read as follows:

[[Page 20988]]

Sec.  195.260   Valves: Location.

    A valve must be installed at each of the following locations:
    (a) On the suction end and the discharge end of a pump station in a 
manner that permits isolation of the pump station equipment in the 
event of an emergency.
    (b) On each pipeline entering or leaving a breakout storage tank 
area in a manner that permits isolation of the tank from other 
facilities.
    (c) On each pipeline at locations along the pipeline system that 
will minimize or prevent safety risks, property damage, or 
environmental harm from accidental hazardous liquid or carbon dioxide 
discharges, as appropriate for onshore areas, offshore areas, and high-
consequence areas (HCA). For newly constructed or entirely replaced 
onshore hazardous liquid or carbon dioxide pipeline segments, as that 
term is defined at Sec.  195.2, that are installed after April 10, 
2023, valve spacing must not exceed 15 miles for pipeline segments that 
could affect or are in HCAs, as defined in Sec.  195.450, and 20 miles 
for pipeline segments that could not affect HCAs. Valves on pipeline 
segments that are located in HCAs or which could affect HCAs must be 
installed at locations as determined by the operator's process for 
identifying preventive and mitigative measures established pursuant to 
Sec.  195.452(i) and by using the selection process in section I.B of 
appendix C of part 195, but with a maximum distance that does not 
exceed 7\1/2\ miles from the endpoints of the HCA segment or the 
segment that could affect an HCA. An operator may request an exemption 
from the compliance deadline requirements of this section for valve 
installation at the specified valve spacing if it can demonstrate to 
PHMSA, in accordance with the notification procedures in Sec.  195.18, 
that those compliance deadline requirements would be economically, 
technically, or operationally infeasible.
    (d) On each lateral takeoff from a pipeline in a manner that 
permits shutting off the lateral without interrupting flow in the 
pipeline.
    (e) On each side of one or more adjacent water crossings that are 
more than 100 feet (30 meters) wide from high water mark to high water 
mark, as follows:
    (1) Valves must be installed at locations outside of the 100-year 
flood plain or be equipped with actuators or other control equipment 
that is installed so as not to be impacted by flood conditions; and
    (2) The maximum spacing interval between valves that protect 
multiple adjacent water crossings cannot exceed 1 mile in length.
    (f) On each side of a reservoir holding water for human 
consumption.
    (g) On each highly volatile liquid (HVL) pipeline that is located 
in a high-population area or other populated area, as defined in Sec.  
195.450, and that is constructed, or where 2 or more miles of pipe have 
been replaced within any 5 contiguous miles within any 24-month period, 
after April 10, 2023, with a maximum valve spacing of 7\1/2\ miles. The 
maximum valve spacing intervals may be increased by 1.25 times the 
distance up to a 9 \3/8\-mile spacing, provided the operator:
    (1) Submits for PHMSA review a notification pursuant to Sec.  
195.18 requesting alternative spacing because installation of a valve 
at a particular location between a 7-mile to a 7\1/2\-mile spacing 
would be economically, technically, or operationally infeasible, and 
that an alternative spacing would not adversely impact safety; and
    (2) Keeps the records necessary to support that determination for 
the useful life of the pipeline.
    (h) An operator may submit for PHMSA review, in accordance with 
Sec.  195.18, a notification requesting site-specific exemption from 
the valve installation requirements or valve spacing requirements of 
paragraph (c), (e), or (f) of this section and demonstrating such 
exemption would not adversely affect safety. An operator may also 
submit for PHMSA review, in accordance with Sec.  195.18, a 
notification requesting an extension of the compliance deadline 
requirements for valve installation and spacing of this section because 
those compliance deadline requirements would be economically, 
technically, or operationally infeasible for a particular new 
construction or pipeline replacement project.

0
20. In Sec.  195.402, paragraphs (c)(4), (5), and (12) and (e)(1), (4), 
(7), and (10) are revised to read as follows:


Sec.  195.402   Procedural manual for operations, maintenance, and 
emergencies.

* * * * *
    (c) * * *
    (4) Determining which pipeline facilities are in areas that would 
require an immediate response by the operator to prevent hazards to the 
public, property, or the environment if the facilities failed or 
malfunctioned, including segments that could affect high-consequence 
areas (HCA) or are in HCAs, and valves specified in Sec.  195.418 or 
Sec.  195.452(i)(4).
    (5) Investigating and analyzing pipeline accidents and failures, 
including sending the failed pipe, component, or equipment for 
laboratory testing or examination where appropriate, to determine the 
cause(s) and contributing factors of the failure and to minimize the 
possibility of a recurrence.
    (i) Post-failure and -accident lessons learned. Each operator must 
develop, implement, and incorporate lessons learned from a post-failure 
and accident review into its written procedures, including in pertinent 
operator personnel training and qualifications programs, and in design, 
construction, testing, maintenance, operations, and emergency procedure 
manuals and specifications.
    (ii) Analysis of rupture and valve shut-offs; preventive and 
mitigative measures. If a failure or accident on an onshore hazardous 
liquid or carbon dioxide pipeline involves the closure of a rupture-
mitigation valve (RMV), as defined in Sec.  195.2, or the closure of an 
alternative equivalent technology, the operator of the pipeline must 
also conduct a post-failure or -accident analysis of all of the factors 
that may have impacted the release volume and the consequences of the 
release and identify and implement operations and maintenance measures 
to minimize the consequences of a future failure or incident. The 
analysis must include all relevant factors impacting the release volume 
and consequences, including, but not limited to, the following:
    (A) Detection, identification, operational response, system shut-
off, and emergency-response communications, based on the type and 
volume of the release or failure event;
    (B) Appropriateness and effectiveness of procedures and pipeline 
systems, including supervisory control and data acquisition (SCADA), 
communications, valve shut-off, and operator personnel;
    (C) Actual response time from identifying a rupture following a 
notification of potential rupture, as defined at Sec.  195.2, to 
initiation of mitigative actions and isolation of the segment, and the 
appropriateness and effectiveness of the mitigative actions taken;
    (D) Location and timeliness of actuation of all RMVs or alternative 
equivalent technologies; and
    (E) All other factors the operator deems appropriate.
    (iii) Rupture post-failure and accident summary. If a failure or 
accident on an onshore hazardous liquid or carbon dioxide pipeline 
involves the identification of a rupture following a notification of 
potential rupture; the closure of an RMV, as those terms are defined in 
Sec.  195.2; or the closure of an

[[Page 20989]]

alternative equivalent technology, the operator must complete a summary 
of the post-failure or -accident review required by paragraph 
(c)(5)(ii) of this section within 90 days of the failure or accident. 
While the investigation is pending, the operator must conduct quarterly 
status reviews until the investigation is completed and a final post-
failure or -accident review is prepared. The final post-failure or -
accident summary and all other reviews and analyses produced under the 
requirements of this section must be reviewed, dated, and signed by the 
operator's appropriate senior executive officer. An operator must keep, 
for the useful life of the pipeline, the final post-failure or -
accident summary, all investigation and analysis documents used to 
prepare it, and records of lessons learned.
* * * * *
    (12) Establishing and maintaining adequate means of communication 
with the appropriate public safety answering point (i.e., 9-1-1 
emergency call center), where direct access to a 9-1-1 emergency call 
center is available from the location of the pipeline, and fire, 
police, and other public officials. Operators must determine the 
responsibilities, resources, jurisdictional area(s), and emergency 
contact telephone numbers for both local and out-of-area calls of each 
Federal, State, and local government organization that may respond to a 
pipeline emergency, and inform the officials about the operator's 
ability to respond to the pipeline emergency and means of communication 
during emergencies. Operators may establish liaison with the 
appropriate local emergency coordinating agencies, such as 9-1-1 
emergency call centers or county emergency managers, in lieu of 
communicating individually with each fire, police, or other public 
entity.
* * * * *
    (e) * * *
    (1) Receiving, identifying, and classifying notices of events that 
need immediate response by the operator or notice to the appropriate 
public safety answering point (i.e., 9-1-1 emergency call center), 
where direct access to a 9-1-1 emergency call center is available from 
the location of the pipeline, and fire, police, and other appropriate 
public officials, and communicating this information to appropriate 
operator personnel for prompt corrective action. Operators may 
establish liaison with the appropriate local emergency coordinating 
agencies, such as 9-1-1 emergency call centers or county emergency 
managers, in lieu of communicating individually with each fire, police, 
or other public entity.
* * * * *
    (4) Taking necessary actions, including but not limited to, 
emergency shutdown, valve shut-off, or pressure reduction, in any 
section of the operator's pipeline system, to minimize hazards of 
released hazardous liquid or carbon dioxide to life, property, or the 
environment. Each operator must also develop written rupture 
identification procedures to evaluate and identify whether a 
notification of potential rupture, as defined in Sec.  195.2, is an 
actual rupture event or non-rupture event. These procedures must, at a 
minimum, specify the sources of information, operational factors, and 
other criteria that operator personnel use to evaluate a notification 
of potential rupture, as defined at Sec.  195.2. For operators 
installing valves in accordance with Sec.  195.258(c), Sec.  
195.258(d), or that are subject to the requirements in Sec.  195.418, 
those procedures should provide for rupture identification as soon as 
practicable.
* * * * *
    (7) Notifying the appropriate public safety answering point (i.e., 
9-1-1 emergency call center), where direct access to a 9-1-1 emergency 
call center is available from the location of the pipeline, and fire, 
police, and other public officials, of hazardous liquid or carbon 
dioxide pipeline emergencies to coordinate and share information to 
determine the location of the release, including both planned responses 
and actual responses during an emergency, and any additional 
precautions necessary for an emergency involving a pipeline 
transporting a highly volatile liquid (HVL). The operator must 
immediately and directly notify the appropriate public safety answering 
point or other coordinating agency for the communities and 
jurisdiction(s) in which the pipeline is located after notification of 
potential rupture, as defined at Sec.  195.2, has occurred to 
coordinate and share information to determine the location of the 
release, regardless of whether the segment is subject to the 
requirements of Sec.  195.258 (c) or (d), Sec.  195.418, or Sec.  
195.419.
* * * * *
    (10) Actions required to be taken by a controller during an 
emergency, in accordance with the operator's emergency plans and 
Sec. Sec.  195.418 and 195.446.
* * * * *

0
21. Section 195.417 is added to read as follows:


Sec.  195.417   Notification of potential rupture.

    (a) As used in this part, a notification of potential rupture means 
refers to the notification to, or observation by, an operator (e.g., by 
or to its controller(s) in a control room, field personnel, nearby 
pipeline or utility personnel, the public, local responders, or public 
authorities) of one or more of the below indicia of a potential 
unintentional or uncontrolled release of a large volume of hazardous 
liquids from a pipeline:
    (1) An unanticipated or unexplained pressure loss outside of the 
pipeline's normal operating pressures, as defined in the operator's 
written procedures. The operator must establish in its written 
procedures that an unanticipated or unplanned pressure loss is outside 
of the pipeline's normal operating pressures when there is a pressure 
loss greater than 10 percent occurring within a time interval of 15 
minutes or less, unless the operator has documented in its written 
procedures the operational need for a greater pressure-change threshold 
due to pipeline flow dynamics (including changes in operating pressure, 
flow rate, or volume), that are caused by fluctuations in product 
demand, receipts, or deliveries;
    (2) An unanticipated or unexplained flow rate change, pressure 
change, equipment function, or other pipeline instrumentation 
indication at the upstream or downstream station that may be 
representative of an event meeting paragraph (a)(1) of this section; or
    (3) Any unanticipated or unexplained rapid release of a large 
volume of hazardous liquid, a fire, or an explosion, in the immediate 
vicinity of the pipeline.
    (b) A notification of potential rupture occurs when an operator 
first receives notice of or observes an event specified in paragraph 
(a) of this section.

0
22. Section 195.418 is added to read as follows:


Sec.  195.418   Valves: Onshore valve shut-off for rupture mitigation.

    (a) Applicability. For newly constructed and entirely replaced 
onshore hazardous liquid or carbon dioxide pipeline segments, as 
defined at Sec.  195.2, with diameters of 6 inches or greater that 
could affect high-consequence areas or are located in high consequence 
areas (HCA), and that have been installed after April 10, 2023, an 
operator must install or use existing rupture-mitigation valves (RMV), 
as defined at Sec.  195.2, or alternative equivalent technologies 
according to the requirements of this section and Sec.  195.419. RMVs 
and alternative

[[Page 20990]]

equivalent technologies must be operational within 14 days of placing 
the new or replaced pipeline segment in service. An operator may 
request an extension of this 14-day operation requirement if it can 
demonstrate to PHMSA, in accordance with the notification procedures in 
Sec.  195.18, that application of that requirement would be 
economically, technically, or operationally infeasible. The 
requirements of this section apply to all applicable pipe replacements, 
even those that do not otherwise directly involve the addition or 
replacement of a valve.
    (b) Maximum spacing between valves. RMVs and alternative equivalent 
technology must be installed in accordance with the following 
requirements:
    (1) Shut-off Segment. For purposes of this section, a ``shut-off 
segment'' means the segment of pipeline located between the upstream 
valve closest to the upstream endpoint of the replaced pipeline segment 
in the HCA or the pipeline segment that could affect an HCA and the 
downstream valve closest to the downstream endpoint of the replaced 
pipeline segment of the HCA or the pipeline segment that could affect 
an HCA so that the entirety of the segment that could affect the HCA or 
the segment within the HCA is between at least two RMVs or alternative 
equivalent technologies. If any crossover or lateral pipe for commodity 
receipts or deliveries connects to the replaced segment between the 
upstream and downstream valves, the shut-off segment also extends to a 
valve on the crossover connection(s) or lateral(s), such that, when all 
valves are closed, there is no flow path for commodity to be 
transported to the rupture site (except for residual liquids already in 
the shut-off segment). Multiple segments that could affect HCAs or are 
in HCAs may be contained within a single shut-off segment. All entirely 
replaced onshore hazardous liquid or carbon dioxide pipeline segments, 
as defined in Sec.  195.2, that could affect or are in an HCA must 
include a minimum of one valve that meets the requirements of this 
section and section 195.419. The operator is not required to select the 
closest valve to the shut-off segment as the RMV or alternative 
equivalent technology. An operator may use a manual pump station valve 
at a continuously manned station as an alternative equivalent 
technology. Such a manual valve used as an alternative equivalent 
technology would not require a notification to PHMSA in accordance with 
Sec.  195.18.
    (2) Shut-off segment valve spacing. Pipeline segments subject to 
paragraph (a) of this section must be protected on the upstream and 
downstream side with RMVs or alternative equivalent technologies. The 
distance between RMVs or alternative equivalent technologies must not 
exceed:
    (i) For pipeline segments carrying non-highly volatile liquids 
(HVL): 15 miles, with a maximum distance not to exceed 7\1/2\ miles 
from the endpoints of a shut-off segment: or
    (ii) For pipeline segments carrying HVLs: 7\1/2\ miles. The maximum 
valve spacing intervals for these valves may be increased by 1.25 times 
the spacing distance, up to a 9\3/8\-mile spacing at an endpoint, 
provided the operator notify PHMSA in accordance with Sec.  195.260 
(g).
    (3) Laterals. Laterals extending from shut-off segments that 
contribute less than 5 percent of the total shut-off segment volume may 
have RMVs or alternative equivalent technologies that meet the 
actuation requirements of this section at locations other than mainline 
receipt/delivery points, as long as all of these laterals contributing 
hazardous liquid volumes to the shut-off segment do not contribute more 
than 5 percent of the total shut-off segment volume, based upon maximum 
flow volume at the operating pressure. A check valve may be used as an 
alternative equivalent technology where it is positioned to stop flow 
into the lateral. Check valves used as an alternative equivalent 
technology in accordance with this paragraph are not subject to Sec.  
195.419 but must be inspected, operated, and remediated in accordance 
with Sec.  195.420, including for closure and leakage, to ensure 
operational reliability. An operator using a such a valve as an 
alternative equivalent technology must submit a request to PHMSA in 
accordance with Sec.  195.18.
    (4) Crossovers. An operator may use a manual valve as an 
alternative equivalent technology for a crossover connection if, during 
normal operations, the valve is closed to prevent the flow of hazardous 
liquid or carbon dioxide with a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator. The operator must document that the valve 
has been closed and locked in accordance with the operator's lock-out 
and tag-out procedures to prevent the flow of hazardous liquid or 
carbon dioxide. An operator using a such a valve as an alternative 
equivalent technology must submit a request to PHMSA in accordance with 
Sec.  195.18.
    (c) Manual operation upon identification of a rupture. Operators 
using a manual valve as an alternative equivalent technology pursuant 
to paragraph (a) of this section must develop and implement operating 
procedures and appropriately designate and locate nearby personnel to 
ensure valve shut-off in accordance with this section and Sec.  
195.419. Manual operation of valves must include time for the assembly 
of necessary operating personnel, the acquisition of necessary tools 
and equipment, driving time under heavy traffic conditions and at the 
posted speed limit, walking time to access the valve, and time to 
manually shut off all valves, not to exceed the response time in Sec.  
195.419(b).

0
23. Section 195.419 is added to read as follows:


Sec.  195.419   Valve capabilities.

    (a) Scope. The requirements in this section apply to rupture-
mitigation valves (RMV), as defined in Sec.  195.2, or alternative 
equivalent technology, installed pursuant to Sec. Sec.  195.258 and 
195.418.
    (b) Rupture identification and valve shut-off time. If an operator 
observes or is notified of a release of hazardous liquid or carbon 
dioxide that may be representative of an unintentional or uncontrolled 
release event meeting a notification of potential rupture (see 
Sec. Sec.  195.2 and 195.417), including any unexplained flow rate 
changes, pressure changes, equipment functions, or other pipeline 
instrumentation indications observed by the operator, the operator 
must, as soon as practicable but within 30 minutes of rupture 
identification (see Sec.  195.402(e)(4)), identify the rupture and 
fully close any RMVs or alternative equivalent technologies necessary 
to minimize the volume of hazardous liquid or carbon dioxide released 
from a pipeline and mitigate the consequences of a rupture.
    (c) Valve shut-off capability. A valve must have the actuation 
capability necessary to close an RMV or alternative equivalent 
technology to mitigate the consequences of a rupture in accordance with 
the requirements of this section.
    (d) Valve monitoring and operational capabilities. An RMV, as 
defined in Sec.  195.2, or alternative equivalent technology, must be 
capable of being monitored or controlled by either remote or onsite 
personnel as follows:
    (1) Operated during normal, abnormal, and emergency operating 
conditions;
    (2) Monitored for valve status (i.e., open, closed, or partial 
closed/open), upstream pressure, and downstream pressure. For automatic 
shut-off valves

[[Page 20991]]

(ASV), an operator does not need to monitor remotely a valve's status 
if the operator has the capability to monitor pressures or flow rate 
within each pipeline segment located between RMVs or alternative 
equivalent technologies to identify and locate a rupture. Pipeline 
segments that use an alternative equivalent technology must have the 
capability to monitor pressures and hazardous liquid or carbon dioxide 
flow rates on the pipeline in order to identify and locate a rupture; 
and
    (3) Have a back-up power source to maintain supervisory control and 
data acquisition (SCADA) systems or other remote communications for 
remote-control valve (RCV) or ASV operational status or be monitored 
and controlled by on-site personnel.
    (e) Monitoring of valve shut-off response status. The position and 
operational status of an RMV must be appropriately monitored through 
electronic communication with remote instrumentation or other 
equivalent means. An operator does not need to monitor remotely an 
ASV's status if the operator has the capability to monitor pressures or 
hazardous liquid or carbon dioxide s flow rate on the pipeline to 
identify and locate a rupture.
    (f) Flow modeling for automatic shut-off valves. Prior to using an 
ASV as an RMV, the operator must conduct flow modeling for the shut-off 
segment and any laterals that feed the shut-off segment, so that the 
valve will close within 30 minutes or less following rupture 
identification, consistent with the operator's procedures, and in 
accordance with Sec.  195.2 and this section. The flow modeling must 
include the anticipated maximum, normal, or any other flow volumes, 
pressures, or other operating conditions that may be encountered during 
the year, not to exceed a period of 15 months, and it must be modeled 
for the flow between the RMVs or alternative equivalent technologies, 
and any looped pipelines or hazardous liquid or carbon dioxide receipt 
tie-ins. If operating conditions change that could affect the ASV set 
pressures and the 30-minute valve closure time following a notification 
of potential rupture, as defined at Sec.  195.2, an operator must 
conduct a new flow model and reset the ASV set pressures prior to the 
next review for ASV set pressures in accordance with Sec.  195.420. The 
flow model must include a time/pressure chart for the segment 
containing the ASV if a rupture event occurs. An operator must conduct 
this flow modeling prior to making flow condition changes in a manner 
that could render the 30-minute valve closure time unachievable.
    (g) Pipelines not affecting HCAs. For pipeline segments that are 
not in a high-consequence area (HCA) or that could not affect an HCA, 
an operator submitting a notification pursuant to Sec. Sec.  195.18 and 
195.258 for use of manual valves as an alternative equivalent 
technology may also request an exemption from the valve operation 
requirements of Sec.  195.419(b).

0
24. In Sec.  195.420, paragraph (b) is revised and paragraphs (d) 
through (g) are added to read as follows:


Sec.  195.420   Valve maintenance.

* * * * *
    (b) Each operator must, at least twice each calendar year, but at 
intervals not exceeding 7\1/2\ months, inspect each valve to determine 
that it is functioning properly. Each rupture-mitigation valve (RMV), 
as defined in Sec.  195.2, or alternative equivalent technology that is 
installed under Sec.  195.258(c) or Sec.  195.418, must also be 
partially operated. Operators are not required to close the valve fully 
during the drill; a minimum 25 percent valve closure is sufficient to 
demonstrate compliance, unless the operator has operational information 
that requires an additional closure percentage for maintaining 
reliability.
* * * * *
    (d) For each remote-control valve (RCV) installed in accordance 
with Sec.  195.258(c) or Sec.  195.418, an operator must conduct a 
point-to-point verification between SCADA system displays and the 
installed valves, sensors, and communications equipment, in accordance 
with Sec.  195.446(c) and (e).
    (e) For each alternative equivalent technology installed under 
Sec.  195.258(c) or (d) or Sec.  195.418(a) that is manually or locally 
operated (i.e., not an RMV, as that term is defined in Sec.  195.2):
    (1) Operators must achieve a response time of 30 minutes or less, 
as required by Sec.  195.419(b), through an initial drill and through 
periodic validation as required by paragraph (e)(2) of this section. An 
operator must review each phase of the drill response and document the 
results to validate the total response time, including the 
identification of a rupture, and valve shut-off time as being less than 
or equal to 30 minutes after rupture identification.
    (2) Within each pipeline system, and within each operating or 
maintenance field work unit, operators must randomly select an 
authorized rupture-mitigation alternative equivalent technology for an 
annual 30-minute-total response time validation drill simulating worst-
case conditions for that location to ensure compliance with Sec.  
195.419. Operators are not required to close the alternative equivalent 
technology fully during the drill; a minimum 25 percent valve closure 
is sufficient to demonstrate compliance with the drill requirements 
unless the operator has operational information that requires an 
additional closure percentage for maintaining reliability. The response 
drill must occur at least once each calendar year, at intervals not to 
exceed 15 months. Operators must include in their written procedures 
the method they use to randomly select which alternative equivalent 
technology is tested in accordance with this paragraph.
    (3) If the 30-minute-maximum response time cannot be achieved in 
the drill, the operator must revise response efforts to achieve 
compliance with Sec.  195.419 no later than 12 months after the drill. 
Alternative valve shut-off measures must be in accordance with 
paragraph (f) of this section within 7 days of the drill.
    (4) Based on the results of the response-time drills, the operator 
must include lessons learned in:
    (i) Training and qualifications programs;
    (ii) Design, construction, testing, maintenance, operating, and 
emergency procedures manuals; and
    (iii) Any other areas identified by the operator as needing 
improvement.
    (f) Each operator must implement remedial measures as follows to 
correct any valve installed on an onshore pipeline in accordance with 
Sec.  195.258(c), or an RMV or alternative equivalent technology 
installed in accordance with Sec.  195.418, that is indicated to be 
inoperable or unable to maintain effective shut-off:
    (1) Repair or replace the valve as soon as practicable but no later 
than 12 months after finding that the valve is inoperable or unable to 
maintain shut-off. An operator may request an extension of the 
compliance deadline requirements of this section if it can demonstrate 
to PHMSA, in accordance with the notification procedures in Sec.  
195.18, that repairing or replacing a valve within 12 months would be 
economically, technically, or operationally infeasible; and
    (2) Designate an alternative compliant valve within 7 calendar days 
of the finding while repairs are being made and document an interim 
response plan to maintain safety. Alternative compliant valves are not 
required to

[[Page 20992]]

comply with valve spacing requirements of this part.
    (g) An operator using an ASV as an RMV, in accordance with 
Sec. Sec.  195.2, 195.260, 195.418, and 195.419, must document, in 
accordance with Sec.  195.419(f), and confirm the ASV shut-in pressures 
on a calendar year basis not to exceed 15 months. ASV shut-in set 
pressures must be proven and reset individually at each ASV, as 
required by Sec.  195.419(f), at least each calendar year, but at 
intervals not to exceed 15 months.

0
25. In Sec.  195.452, paragraph (i)(4) is revised to read as follows:


Sec.  195.452   Pipeline integrity management in high consequence 
areas.

* * * * *
    (i) * * *
    (4) Emergency Flow Restricting Devices (EFRD). If an operator 
determines that an EFRD is needed on a pipeline segment that is located 
in, or which could affect, a high-consequence area (HCA) in the event 
of a hazardous liquid pipeline release, an operator must install the 
EFRD. In making this determination, an operator must, at least, 
evaluate the following factors--the swiftness of leak detection and 
pipeline shutdown capabilities, the type of commodity carried, the rate 
of potential leakage, the volume that can be released, topography or 
pipeline profile, the potential for ignition, proximity to power 
sources, location of nearest response personnel, specific terrain 
within the HCA or between the pipeline segment and the HCA it could 
affect, and benefits expected by reducing the spill size. An RMV 
installed under this paragraph must meet all of the other applicable 
requirements in this part.
    (i) Where EFRDs are installed on pipeline segments in HCAs and that 
could affect HCAs with diameters of 6 inches or greater and that are 
placed into service or that have had 2 or more miles of pipe replaced 
within 5 contiguous miles within a 24-month period after April 10, 
2023, the location, installation, actuation, operation, and maintenance 
of such EFRDs (including valve actuators, personnel response, 
operational control centers, supervisory control and data acquisition 
(SCADA), communications, and procedures) must meet the design, 
operation, testing, maintenance, and rupture-mitigation requirements of 
Sec. Sec.  195.258, 195.260, 195.402, 195.418, 195.419, and 195.420.
    (ii) The EFRD analysis and assessments specified in this paragraph 
(i)(4) must be completed prior to placing into service all onshore 
pipelines with diameters of 6 inches or greater and that are 
constructed or that have had 2 or more miles of pipe within any 5 
contiguous miles within any 24-month period replaced after April 10, 
2023. Implementation of EFRD findings for RMVs must meet Sec.  195.418.
    (iii) An operator may request an exemption from the compliance 
deadline requirements of this section if it can demonstrate to PHMSA, 
in accordance with the notification procedures in Sec.  195.18, that 
installing an EFRD by that compliance deadline would be economically, 
technically, or operationally infeasible.
* * * * *

    Issued in Washington, DC, on March 31, 2022, under authority 
delegated in 49 CFR 1.97.
Tristan H. Brown,
Deputy Administrator.
[FR Doc. 2022-07133 Filed 4-7-22; 8:45 am]
BILLING CODE 4910-60-P


</pre><script data-cfasync="false" src="/cdn-cgi/scripts/5c5dd728/cloudflare-static/email-decode.min.js"></script></body>
</html>