20940 Federal Register / Vol. 87, No. 68 / Friday, April 8, 2022 / Rules and Regulations 

1For 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. 

2NTSB, 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. 

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., remotecontrol 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 RemoteControlled 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 largediameter 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. 

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 


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3NTSB, 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/Accident

Reports/Reports/PAR1101.pdf. 

4Most 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. 

5CPUC, ‘‘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. 

6The 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. 

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 § 192.903. 

8Oak 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). 

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). 

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. 

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 highconsequence areas (HCA); 7 technical 

reports commissioned by PHMSA on 

valves and leak detection; 8 9 comments 

received on related topics through 

advance notices of proposed rulemaking 

(ANPRM) and the notice of proposed 

rulemaking (NPRM) published in 

February 2020; 10 and feedback from 

members of the public, environmental 

advocacy organizations, State pipeline 

safety regulators, and industry 

representatives during Gas Pipeline 

Advisory Committee and Liquid 

Pipeline Advisory Committee meetings. 

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 


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20942 Federal Register / Vol. 87, No. 68 / Friday, April 8, 2022 / Rules and Regulations 

11A regulated rural hazardous liquid gathering 

pipeline is defined in § 195.11 as an onshore 

gathering line in a rural area that meets all of the 

following criteria: (1) A nominal diameter from 65⁄8

to 85⁄8 inches; (2) located in or within 1⁄4 mile of 

an unusually sensitive area, as that term is defined 

in § 195.6; and (3) operating at a maximum pressure 

established under § 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’’). 

13Class locations, defined at § 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. 

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

15PHMSA 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. 

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

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. 

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 shutoff, as soon as practicable. 

This final rule also requires operators 

of all gas and hazardous liquid pipelines 

subject to the emergency planning 

requirements at §§ 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 

§§ 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. 

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 


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16See 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/reportcongress-shipping-crude-oil-truck-rail-and-pipeline32019.pdf. 

17NTSB, 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. 

18See supra note 3. 

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. 

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. 

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 21⁄2

hours to stop the flow of natural gas 

from a ruptured pipeline in a highlypopulated 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. 

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 


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19As 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. 

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). 

21For natural gas and hazardous liquid pipelines, 

§§ 192.615(a)(3) and 195.402(e)(2), respectively. 

22Requirements for ASV and RCV installation on 

gas transmission pipelines are at § 192.935(c), and 

requirements for EFRD installation for hazardous 

liquid pipelines are at § 195.452(i)(4). 

install ASVs or RCVs in HCAs and Class 

3 and 4 locations, with the valve 

spacing based on risk analysis. 

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. 

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. 

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 RemoteControlled 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 thencurrent regulations for incident 

response and installation and use of 

ASVs and RCVs employed broadlystated 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

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 §§ 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. 


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23A break in the pipeline that involves the 

opening of the pipe in either the circumferential or 

longitudinal direction. 

24See supra note 9. 

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 shutoff 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. 

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 transportationrelated 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: 

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, postincident investigation and review, and 

local 9–1–1 notification to help 

operators achieve better rupture 


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25 166 Cong. Rec. H8823 (daily ed. Dec. 21, 2020) 

(joint explanatory statement on Consolidated 

Appropriations Act of FY 2021). 

26 86 FR 7037 (Jan. 20, 2021). 

27 86 FR 7619 (Feb. 1, 2021). 

28See, 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/statementsreleases/2021/04/22/fact-sheet-president-bidensets-2030-greenhouse-gas-pollution-reductiontarget-aimed-at-creating-good-paying-union-jobsand-securing-u-s-leadership-on-clean-energytechnologies/. 

29White 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-Plan1.pdf. 

30Those 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. 

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

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

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 § 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. 

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). 


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31The 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.’’ 

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. 

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 § 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 


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32PHMSA 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. 

33 Design regulations for computational pipeline 

monitoring (CPM) leak detection systems are at 

§ 195.134, and the operational requirements for 

CPM leak detection are at § 195.444. The 

requirement for operators of pipelines in HCAs and 

those that could affect HCAs to have an LDS are at 

§ 195.452(i)(3). 

34 84 FR 52260 (Oct. 1, 2019). 

35See § 195.412. 

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 costbenefit 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

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 

§§ 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 

§§ 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 §§ 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 PHMSAjurisdictional 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 §§ 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 

§ 192.705 to conduct periodic patrols of 

their pipelines, and by § 192.706 to 

conduct leak surveys twice per year in 

Class 3 locations and quarterly for Class 

4 locations. 

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 


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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 

§ 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 § 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 § 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 § 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 § 195.11, or (3) 

located within an inlet of the Gulf of 

Mexico as provided in § 195.413. 

Further, operators of regulated rural 

gathering lines have to follow specific 

safety provisions set out in § 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 § 195.260(e). PHMSA has required 

extra valves near such water crossings 

for several decades under § 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 

§ 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 § 192.615 for contacting 

9–1–1 call centers and at § 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 § 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, 


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36 Including pressure, temperature, meter flow, 

product characteristics, and geometry of the 

pipeline. 

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 pressurechange 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 § 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

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 thirdparty 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 


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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 onesize-fits-all rupture criteria, they 

recommended that PHMSA direct 

operators to establish rupturenotification 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-sizefits-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 rupturelike 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-losswithin-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 


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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 

(§§ 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 §§ 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 (§§ 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 (§§ 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 rupturemitigation 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 

§§ 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 


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37See 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). 

38PHMSA submits that operators may be able to 

leverage other provisions in this final rule 

(§§ 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. 

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 §§ 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 

§§ 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 §§ 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

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 §§ 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 

§§ 192.635(a)(1) and 195.417(a)(1); 38

and reports of rupture indicia from onscene, credible sources (e.g., on or offduty pipeline operator personnel, sheriff 

or police officers, fire department 

personnel, or other emergency response 

personnel). PHMSA understands this 

reading of its revisions at 

§§ 192.615(a)(12) and 195.402(e)(4) to be 

consistent with operators’ obligations 

elsewhere in §§ 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 §§ 192.615 and 195.402 

requiring operators to ensure that their 

protocols identify ruptures ‘‘as soon as 

practicable’’ and (2) language at 

§§ 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. 

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 


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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 § 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 § 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 worstcase 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 toorapid 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 PHMSAreportable 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 


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39PHMSA 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. 

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, nonHCA 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 

§§ 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. 

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 


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

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

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 sitespecific 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, costeffective, 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 

§ 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 

§ 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 §§ 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 § 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 nonHCA Class 1 locations are largely rural 

areas, PHMSA believes such a provision 

would be warranted if the operator 

could demonstrate they could not install 


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a compliant valve or technology in those 

locations. In this final rule at 

§ 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 § 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 § 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 

§ 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 

§§ 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 

§ 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 § 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 ‘‘shutoff segment’’ in the NPRM as the 

segment of applicable pipe between the 

RMVs closest to the upstream and 


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

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. 

Commenters representing hazardous 

liquid pipeline operators similarly 

requested that PHMSA exempt pipeline 

segments that could not affect HCAs 


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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 costbenefit 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 § 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 preinstallation notification procedure for 

alternative equivalent technologies and 

will consider requests to use such 

technologies on a case-by-case, sitespecific 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 


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42Rosenfeld & 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). 43Seven 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. 

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. 

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. 

For hazardous liquid pipelines, 

PHMSA notes that there are currently 

regulatory requirements for low-stress 

pipelines in rural areas. By definition (at 

§ 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, 


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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, § 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 §§ 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 §§ 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 § 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 § 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 § 195.18 in 

this final rule that functions similarly to 

§ 192.18. For any notifications related to 

the RMV and alternative equivalent 

technology requirements of this 

rulemaking, § 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 71⁄2 miles for HVL 

lines in populated HCAs. PHMSA also 


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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 §§ 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 largediameter 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 

§ 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 § 192.634 

apply to replacement projects covered 

by § 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 

§ 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 crossreferences 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 


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‘‘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 71⁄2

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 

§ 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 § 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 

§ 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 § 195.18, that 

installing an RMV or alternative 

equivalent technology as otherwise 

required by § 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 highpopulation areas or other populated 

areas as defined by § 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 § 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 


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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 shutoff 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 

§§ 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 71⁄2 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 § 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 §§ 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 shutoff 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 shutoff 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 

§§ 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 

§ 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 


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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 realtime 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 shutoff 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 

§ 192.179 and to apply the RMV and 

alternative equivalent technology 

installation requirement and rupturemitigation 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 § 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 §§ 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 § 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 § 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 


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44 In the Matter of Viking Gas Transmission, Final 

Order, C.P.F. No. 32102 (May 1, 1998). 

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 § 192.634 would, 

pursuant to § 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 

§ 192.634. 

3. PHMSA Response 

PHMSA intended for the RMV and 

alternative equivalent technology 

requirements, including those for valve 

spacing proposed in § 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 

§ 192.179(a) for the new class location.44

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 

§ 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 

§ 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 §§ 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 §§ 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 


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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 

§§ 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 valveclosure time of this rulemaking. A paper 

exercise cannot effectively confirm realVerDate Sep<11>2014 18:29 Apr 07, 2022 Jkt 256001 PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 E:\FR\FM\08APR2.SGM 08APR2

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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 nonfunctional 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 postincident 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 § 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 § 192.617 are fit-forpurpose 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 § 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 


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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 

§ 192.617(c) only apply to transmission 

lines, since the broad definition of 

‘‘rupture’’ in § 192.3 could lead to 

§ 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 postincident 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 § 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 § 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 § 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 IMrelated 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 

§§ 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 


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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 

§§ 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 §§ 192.935 and 195.452 to clarify 

the requirements for conducting ASV 


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Federal Register / Vol. 87, No. 68 / Friday, April 8, 2022 / Rules and Regulations 20971 

45See §§ 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 §§ 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. 

46https://www.dhs.gov/news/2021/05/27/dhsannounces-new-cybersecurity-requirements-criticalpipeline-owners-and-operators. 

47 86 FR 73173 (Dec. 27, 2021). 

48NAS, ‘‘Criteria for Installing Automatic and 

Remote-Controlled Shutoff Valves on Existing Gas 

and Hazardous Liquid Transmission Pipelines’’ 

(last visited Nov. 23, 2021). 

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 § 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 § 192.935(c) 

because they appear to be duplicative 

with the proposed requirements for 

RMV installation under § 192.634. 

Similarly, Northern Natural Gas 

Company recommended that PHMSA 

remove the proposed requirements at 

§ 192.935 because they are already 

partially addressed by the investigation 

of failures and incidents at § 192.617. 

The PST supported PHMSA’s 

proposed addition of performance 

measures for the installation of EFRDs 

and their use as RMVs under § 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 §§ 192.935 and 

195.452 must comply with all of the 

other RMV requirements in the 

respective parts of the regulations.45

Regarding cybersecurity issues, 

PHMSA notes that the recent 

cyberattack on the Colonial Pipeline 

underscores the urgency of publicprivate 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 cyberrelated 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. 

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


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IV. Section-by-Section Analysis of 

Changes to 49 CFR Part 192 for Gas 

Pipelines 

§ 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 § 192.3 

to define the ‘‘notification of potential 

rupture’’ in terms of notification of, or 

observation by, an operator of indicia 

specified in § 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 § 192.635. The 

final rule at § 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. 

§ 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. 

§ 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 

§ 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. 

§ 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 

§ 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 

§ 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 § 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, 71⁄2 miles in Class 3 

locations, and 10 miles in all other 

locations. 

§ 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 § 192.3, to meet the 

maximum allowable operating pressure 

in accordance with requirements for 

class location changes under §§ 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 


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spacing requirements at § 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. 

§ 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 § 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 

§ 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 

§ 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). 

§ 192.617 Investigation of Failures and 

Incidents 

In this final rule, PHMSA has revised 

§ 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 postevent 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 postincident 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 § 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. 

§ 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 § 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 § 192.18, a 

request for extension of the valve 

installation compliance deadline 

requirements of § 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 


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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 

§ 192.636. 

§ 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 

§ 192.3. 

§ 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, nonHCAs may request, within their 

notification under § 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 § 192.636(b). 

Operators seeking such an exemption 

must provide for PHMSA review within 

that notification the closing times for 

those manual valves. 

§ 192.745 Valve Maintenance: 

Transmission Lines 

In this final rule, PHMSA is revising 

§ 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 

§ 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 

§ 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 

§§ 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. 

§ 192.935 What additional preventive 

and mitigative measure must an 

operator take? 

In this final rule, PHMSA is revising 

§ 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 rupturemitigation processes and procedures. 

V. Section-by-Section Analysis for 

Changes to 49 CFR Part 195 for 

Hazardous Liquid Pipelines 

§ 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 § 195.2 

to define the ‘‘notification of potential 

rupture’’ in terms of notification of, or 

observation by, an operator of indicia 

specified in § 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 § 195.402 requires that 

operators must document, in their 

operations manual, their method for 

rupture identification. An operator, after 


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49A 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. 

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. 

§ 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 § 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. 

§ 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 

§ 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. 

§ 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 § 195.260, 

and all alternative equivalent 

technologies installed in accordance 

with this section must meet the 

operational requirements of RMVs 

outlined in § 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 

§ 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 sitespecific 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 § 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). 

§ 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 § 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 § 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 § 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 


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adjacent water crossings cannot exceed 

1 mile. 

In this section, PHMSA has also 

finalized spacing requirements for HVL 

pipelines in high-population areas or 

other populated areas, as defined in 

§ 195.450. These pipelines must have a 

maximum valve spacing of 71⁄2 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 93⁄8-mile spacing if the 

operator submits for PHMSA review, in 

accordance with § 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 

§ 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. 

§ 195.402 Procedural Manual for 

Operations, Maintenance, and 

Emergencies 

In this final rule, PHMSA revised 

§ 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 

§ 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 

§ 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 § 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. 

§ 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 

§ 195.2. 

§ 195.418 Valves: Onshore Valve ShutOff for Rupture Mitigation 

This section requires operators to 

install or use RMVs or alternative 

equivalent technologies on many newly 


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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 § 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 71⁄2 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 93⁄8 miles, 

subject to review by PHMSA of an 

operator’s request demonstrating that 

installation of a valve at a 7-mile to a 

71⁄2-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 § 195.419. 

§ 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 

§ 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 § 195.18 

requesting installation of manual valves 

as an alternative equivalent technology, 

an exemption from the valve operation 

requirements of § 195.419(b). An 

operator seeking such an exemption 

must provide for PHMSA review within 

that notification the closing times for 

those manual valves. 

§ 195.420 Valve Maintenance 

In this final rule, PHMSA is revising 

§ 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 

§ 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 § 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 §§ 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 § 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. 

§ 195.452 Pipeline Integrity 

Management in High Consequence 

Areas 

In this final rule, PHMSA is revising 

§ 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 


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

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

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

flow restricting device findings for any 

RMVs installed must meet § 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. 

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$] 

System type 

7% 

Discount 

rate 

3% 

Discount 

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, largevolume 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.’’ 

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. 

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. 


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53 65 FR 67249 (Nov. 6, 2000). 54 66 FR 28355 (May 18, 2001). 

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. 

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. 

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 postincident 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 


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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 § 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 

§ 195.18, that installing an otherwiserequired 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 postinstallation) 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 postincident 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 PHMSARegulated 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 


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

56 77 FR 26413 (May 4, 2012). 

57 59 FR 7629 (Feb. 16, 1994). 

58 86 FR 7009 (Jan. 20, 2021). 

59See 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). 

PHMSA that installing an otherwiserequired 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 PHMSARegulated 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. 

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. 

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, lowincome populations, and other 

underserved disadvantaged 

communities. 

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, lowincome 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. 

List of Subjects 

49 CFR Part 192 

Gas, Natural gas, Pipeline safety, 

Reporting and recordkeeping 

requirements. 


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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 

■ 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. 

■ 2. In § 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: 

§ 192.3 Definitions. 

* * * * * 

Entirely replaced onshore 

transmission pipeline segments means, 

for the purposes of §§ 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 

§ 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. 

* * * * * 

■ 3. In § 192.9, paragraphs (d)(1) and 

(e)(1)(i) are revised to read as follows: 

§ 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 §§ 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 §§ 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; 

* * * * * 

■ 4. In § 192.18, paragraph (c) is revised 

to read as follows: 

§ 192.18 How to notify PHMSA. 

* * * * * 

(c) Unless otherwise specified, if an 

operator submits, pursuant to § 192.8, 

§ 192.9, § 192.179, § 192.506, § 192.607, 

§ 192.619, § 192.624, § 192.632, 

§ 192.634, § 192.636, § 192.710, 

§ 192.712, § 192.745, § 192.921, or 

§ 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. 

■ 5. In § 192.179, paragraphs (e) through 

(h) are added to read as follows: 

§ 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 §§ 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 

§ 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 § 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 § 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 §§ 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 § 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 § 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 § 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 §§ 192.634 and 192.636. An 

operator requesting use of manual 

valves as an alternative equivalent 


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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 § 192.18, but it must comply with 

§ 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 (71⁄2) 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. 

■ 6. Section 192.610 is added to read as 

follows: 

§ 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 

§ 192.611, § 192.619, or § 192.620, then 

the requirements in §§ 192.179, 192.634, 

and 192.636, as applicable, apply to the 

new class location, and the operator 

must install valves, including rupturemitigation 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 

§ 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 § 192.611, § 192.619, or 

§ 192.620, then within 24 months of the 

class location change, in accordance 

with § 192.611(d), the operator must 

either: 

(1) Comply with the valve spacing 

requirements of § 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 

§ 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. 

■ 7. In § 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: 

§ 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 § 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 § 192.179, 

§ 192.634, or § 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 §§ 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 § 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 § 192.179(e), 

§ 192.179(f), or that are subject to the 

requirements in § 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: 

* * * * * 

■ 8. Section 192.617 is revised to read 

as follows: 

§ 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 § 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 


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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 shutoffs. 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 § 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 § 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 § 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 postfailure 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. 

■ 9. Section 192.634 is added to read as 

follows: 

§ 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 highconsequence 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 

§§ 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 § 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 § 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 § 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 

§ 192.3. Such a valve used as an 

alternative equivalent technology would 

not require a notification to PHMSA in 

accordance with § 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 


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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 § 192.636, 

but they must be inspected, operated, 

and remediated in accordance with 

§ 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 

§§ 192.18 and 192.179 develop and 

implement maintenance procedures for 

such equipment that meet § 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 

§§ 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 §§ 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 § 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 

§ 192.636(b). 

■ 10. Section 192.635 is added to read 

as follows: 

§ 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. 

■ 11. Section 192.636 is added to read 

as follows: 

§ 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 § 192.3, or 

alternative equivalent technologies, 

installed pursuant to §§ 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 

§ 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 § 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 

§ 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 remotecontrol valve (RCV) or automatic shutoff 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 shutoff 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 § 192.3 and this 

section. The flow modeling must 


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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 § 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 § 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 §§ 192.18 and 

192.179 for use of manual valves as an 

alternative equivalent technology may 

also request an exemption from the 

requirements of § 192.636(b). 

■ 12. In § 192.745, paragraphs (c) 

through (f) are added to read as follows: 

§ 192.745 Valve maintenance: 

Transmission lines. 

* * * * * 

(c) For each remote-control valve 

(RCV) installed in accordance with 

§ 192.179 or § 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 § 192.631(c) and (e). 

(d) For each alternative equivalent 

technology installed on an onshore 

pipeline under § 192.179(e) or (f) or 

§ 192.634 that is manually or locally 

operated (i.e., not a rupture-mitigation 

valve (RMV), as that term is defined in 

§ 192.3): 

(1) Operators must achieve a valve 

closure time of 30 minutes or less, 

pursuant to § 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 shutoff 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 

§ 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 § 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 responsetime 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 § 192.636(g), have been 

exempted from the requirements of 

§ 192.636(b). 

(e) Each operator must develop and 

implement remedial measures to correct 

any valve installed on an onshore 

pipeline under § 192.179(e) or (f) or 

§ 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 § 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 §§ 192.3, 

192.179, 192.634, and 192.636, must 

document and confirm the ASV shut-in 

pressures, in accordance with 

§ 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. 

■ 13. In § 192.935, paragraph (c) is 

revised and paragraph (f) is added to 

read as follows: 

§ 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 highconsequence 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 §§ 191.3 and 191.23, 

respectively. 


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PART 195—TRANSPORTATION OF 

HAZARDOUS LIQUIDS BY PIPELINE 

■ 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. 

■ 15. In § 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: 

§ 195.2 Definitions. 

* * * * * 

Entirely replaced onshore hazardous 

liquid or carbon dioxide pipeline 

segments, for the purposes of 

§§ 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 

§ 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. 

* * * * * 

■ 16. In § 195.11, paragraph (b)(2) is 

revised to read as follows: 

§ 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 § 195.5. 

(ii) Except for pipelines subject to 

§ 195.260(e), such pipelines are not 

subject to the rupture-mitigation valve 

(RMV) and alternative equivalent 

technology requirements in 

§§ 195.258(c) and (d), 195.418, and 

195.419. 

* * * * * 

■ 17. Section 195.18 is added to read as 

follows: 

§ 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 InformationResources

Manager@dot.gov; 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 § 195.258, 

§ 195.260, § 195.418, § 195.419, 

§ 195.420 or § 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. 

■ 18. In § 195.258, paragraphs (c) 

through (e) are added to read as follows: 

§ 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 

§ 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 § 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 

§ 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 

§ 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 

§ 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 § 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 §§ 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 § 195.18, but it must comply with 

§§ 195.419 and 195.420. 

■ 19. Section 195.260 is revised to read 

as follows: 


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§ 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 highconsequence areas (HCA). For newly 

constructed or entirely replaced onshore 

hazardous liquid or carbon dioxide 

pipeline segments, as that term is 

defined at § 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 § 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 § 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 71⁄2 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 

§ 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 highpopulation area or other populated area, 

as defined in § 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 71⁄2 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 § 195.18 

requesting alternative spacing because 

installation of a valve at a particular 

location between a 7-mile to a 71⁄2-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 

§ 195.18, a notification requesting sitespecific 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 § 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. 

■ 20. In § 195.402, paragraphs (c)(4), (5), 

and (12) and (e)(1), (4), (7), and (10) are 

revised to read as follows: 

§ 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 § 195.418 

or § 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 § 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 § 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 § 195.2; or the closure of an 


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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 postfailure 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 § 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 § 195.2. 

For operators installing valves in 

accordance with § 195.258(c), 

§ 195.258(d), or that are subject to the 

requirements in § 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 § 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 § 195.258 

(c) or (d), § 195.418, or § 195.419. 

* * * * * 

(10) Actions required to be taken by 

a controller during an emergency, in 

accordance with the operator’s 

emergency plans and §§ 195.418 and 

195.446. 

* * * * * 

■ 21. Section 195.417 is added to read 

as follows: 

§ 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. 

■ 22. Section 195.418 is added to read 

as follows: 

§ 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 

§ 195.2, with diameters of 6 inches or 

greater that could affect highconsequence 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 § 195.2, or alternative 

equivalent technologies according to the 

requirements of this section and 

§ 195.419. RMVs and alternative 


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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 § 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 § 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 § 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 71⁄2 miles from the endpoints of 

a shut-off segment: or 

(ii) For pipeline segments carrying 

HVLs: 71⁄2 miles. The maximum valve 

spacing intervals for these valves may 

be increased by 1.25 times the spacing 

distance, up to a 93⁄8-mile spacing at an 

endpoint, provided the operator notify 

PHMSA in accordance with § 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 § 195.419 

but must be inspected, operated, and 

remediated in accordance with 

§ 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 § 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 § 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 § 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 § 195.419(b). 

■ 23. Section 195.419 is added to read 

as follows: 

§ 195.419 Valve capabilities. 

(a) Scope. The requirements in this 

section apply to rupture-mitigation 

valves (RMV), as defined in § 195.2, or 

alternative equivalent technology, 

installed pursuant to §§ 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 

§§ 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 

§ 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 

§ 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 


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(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 remotecontrol 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 shutoff 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 § 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 § 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 § 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 highconsequence area (HCA) or that could 

not affect an HCA, an operator 

submitting a notification pursuant to 

§§ 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 § 195.419(b). 

■ 24. In § 195.420, paragraph (b) is 

revised and paragraphs (d) through (g) 

are added to read as follows: 

§ 195.420 Valve maintenance. 

* * * * * 

(b) Each operator must, at least twice 

each calendar year, but at intervals not 

exceeding 71⁄2 months, inspect each 

valve to determine that it is functioning 

properly. Each rupture-mitigation valve 

(RMV), as defined in § 195.2, or 

alternative equivalent technology that is 

installed under § 195.258(c) or 

§ 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 

§ 195.258(c) or § 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 

§ 195.446(c) and (e). 

(e) For each alternative equivalent 

technology installed under § 195.258(c) 

or (d) or § 195.418(a) that is manually or 

locally operated (i.e., not an RMV, as 

that term is defined in § 195.2): 

(1) Operators must achieve a response 

time of 30 minutes or less, as required 

by § 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 rupturemitigation alternative equivalent 

technology for an annual 30-minutetotal response time validation drill 

simulating worst-case conditions for 

that location to ensure compliance with 

§ 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 

§ 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 

§ 195.258(c), or an RMV or alternative 

equivalent technology installed in 

accordance with § 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 shutoff. 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 

§ 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 


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20992 Federal Register / Vol. 87, No. 68 / Friday, April 8, 2022 / Rules and Regulations 

comply with valve spacing requirements 

of this part. 

(g) An operator using an ASV as an 

RMV, in accordance with §§ 195.2, 

195.260, 195.418, and 195.419, must 

document, in accordance with 

§ 195.419(f), and confirm the ASV shutin 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 

§ 195.419(f), at least each calendar year, 

but at intervals not to exceed 15 months. 

■ 25. In § 195.452, paragraph (i)(4) is 

revised to read as follows: 

§ 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 §§ 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 § 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 § 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 


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