2210 Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations 

1 82 FR 45750 (Oct. 2, 2017). 

2 85 FR 35240. 

3 ‘‘Regulatory Planning and Review,’’ 58 FR 51735 

(Oct. 4, 1993). 

DEPARTMENT OF TRANSPORTATION 

Pipeline and Hazardous Materials 

Safety Administration 

49 CFR Parts 191 and 192 

[Docket No. PHMSA–2018–0046; Amdt Nos. 

191–29; 192–128] 

RIN 2137–AF36 

Pipeline Safety: Gas Pipeline 

Regulatory Reform 

AGENCY: Pipeline and Hazardous 

Materials Safety Administration 

(PHMSA), DOT. 

ACTION: Final rule; withdrawal of 

enforcement discretion. 

SUMMARY: PHMSA is amending the 

Federal Pipeline Safety Regulations to 

ease regulatory burdens on the 

construction, maintenance, and 

operation of gas transmission, 

distribution, and gathering pipeline 

systems without adversely affecting 

safety. The amendments in this rule are 

based on rulemaking petitions from 

stakeholders, and DOT and PHMSA 

initiatives to identify appropriate areas 

where regulations might be repealed, 

replaced, or modified, and PHMSA’s 

review of public comments. PHMSA 

also, as of the effective date of this final 

rule, withdraws the March 29, 2019 

‘‘Exercise of Enforcement Discretion 

Regarding Farm Taps’’ and the 

unpublished October 27, 2015 letter to 

the Interstate Natural Gas Association of 

America announcing a stay of 

enforcement pertaining to certain 

pressure vessels. 

DATES: Effective Date: This rule is 

effective March 12, 2021. 

Incorporation by reference date: The 

incorporation by reference of certain 

publications listed in the rule is 

approved by the Director of the Federal 

Register as of March 12, 2021. 

Voluntary compliance date: March 12, 

2021. 

Delayed compliance date: 

Compliance with the amendments 

adopted in the rule is required 

beginning October 1, 2021. 

Enforcement discretion withdrawal 

date: The withdrawal of 84 FR 11253 

(Mar. 26, 2019) is effective as of March 

12, 2021. 

FOR FURTHER INFORMATION CONTACT: 

Sayler Palabrica, Transportation 

Specialist, by telephone at 202–366– 

0559. 

SUPPLEMENTARY INFORMATION: 

I. Executive Summary 

II. Background 

III. Analysis of Comments, GPAC 

Recommendations, and PHMSA’s 

Response 

IV. Availability of Standards Incorporated by 

Reference 

V. Regulatory Analyses and Notices 

I. Executive Summary 

A. Purpose of This Deregulatory Action 

PHMSA is amending the Federal 

Pipeline Safety Regulations (PSR) at 49 

CFR parts 191 and 192 to ease 

regulatory burdens on the construction, 

operation, and maintenance of gas 

transmission, distribution, and 

gathering pipeline systems without 

adversely affecting safety. These 

amendments include regulatory relief 

actions identified by internal agency 

review, petitions for rulemaking, and 

public comments submitted in response 

to a Department of Transportation 

(DOT) regulatory reform notice entitled 

‘‘Notification of Regulatory Review.’’ 1

On June 9, 2020, PHMSA published a 

notice of proposed rulemaking (NPRM) 

to seek public comments on proposed 

changes to the PSR.2 A summary of 

those proposed changes, and PHMSA’s 

response to stakeholder feedback on the 

individual provisions, is provided 

below in section III (Analysis of 

Comments, GPAC Recommendations, 

and PHMSA’s Response). 

B. Summary of PSR Amendments 

The final rule makes the following 

amendments to 49 CFR parts 191 and 

192: 

A. Revision of certain requirements 

(at §§ 191.11, 192.740, and 192.1003) 

pertaining to farm taps giving operators 

the choice of managing inspections of 

pressure regulators serving farm taps 

under either their distribution integrity 

management plan (DIMP) or by 

following the inspection requirements at 

§ 192.740; 

B. Revision of certain requirements (at 

§§ 192.1003, 192.1005 and 192.1015) 

pertaining to master meter systems to 

exempt operators of these simple 

pipeline facilities from DIMP 

requirements that had been designed 

with complex distribution systems in 

mind; 

C. Revision of certain reporting 

requirements (at §§ 191.12 and 

192.1009) to eliminate a dedicated 

report form for mechanical fitting 

failures (MFFs), and modify other 

required report forms to incorporate 

more information on MFFs; 

D. Revision of the monetary threshold 

for incident reporting (at § 191.3) to 

update for inflation over the three 

decades since the current monetary 

threshold was established, and 

introduce a new appendix A to part 191 

to provide for annual updates to that 

threshold to account for inflation; 

E. Revision of § 192.465 to clarify that 

operators may remotely inspect rectifier 

stations for external corrosion; 

F. Revision of atmospheric corrosion 

monitoring requirements (at §§ 192.481, 

192.491, 192.1007, and 192.1015) both 

to align the inspection interval for 

atmospheric corrosion on gas 

distribution service pipelines with 

leakage survey requirements at 

§ 192.723, and to clarify that 

consideration of corrosion risks under 

DIMP explicitly includes atmospheric 

corrosion; 

G. Revision of requirements governing 

plastic pipe (at §§ 192.7, 192.121, 

192.281, 192.285, and appendix B to 

part 192) to improve alignment with, 

and incorporate by reference, certain 

updated industry standards; 

H. Revision of test requirements for 

pressure vessels at § 192.153 to align 

pressure test factor requirements with 

industry standards, and to clarify 

certain other pressure testing 

requirements; 

I. Revision of the welding process 

requirement at § 192.229 to align better 

with welder requalification requirement 

at § 192.229(d)(2); and 

J. Revision of language at § 192.507 to 

extend an existing authorization for pretesting of fabricated units and short 

segments of steel pipe prior to 

installation on pipelines with highstress operating conditions to pipelines 

operating at lower-stress operating 

conditions. 

C. Costs and Benefits 

In accordance with 49 U.S.C. 60102, 

Executive Order (E.O.) 12866,3 and DOT 

regulations at § 5.13(e), PHMSA has 

prepared an assessment of the costs and 

benefits of this final rule as well as 

reasonable alternatives. The 

amendments promulgated in this final 

rule are deregulatory, with the intention 

and effect of reducing regulatory 

burdens, increasing flexibility, 

improving efficiency, and adding clarity 

to existing rules without adversely 

affecting safety. PHMSA expects the 

incremental cost savings to accrue on an 

ongoing annual basis. PHMSA used a 

20-year analysis period for this final 

rule. PHMSA estimates the total 

quantified annualized cost savings to be 

approximately $129.8 million (at a 

discount rate of 7 percent) or 

approximately $132.5 million (at a 

discount rate of 3 percent). Table-1 

presents the estimated total cost savings 

for the 20-year period and the estimated 


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Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations 2211 

4 85 FR 35241–42. 

5 82 FR 45750. 

6 82 FR 51178. 

7 Docket No. DOT–OST–2017–0069. 

8 85 FR 35240. 

9 GPA, formerly the Gas Processors Association. 

10 85 FR 31353 (May 22, 2020). 

11E.O. 13924 at § 4. 

annualized cost savings over the same 

period. 

TABLE 1—TOTAL ESTIMATED DISCOUNTED COST SAVINGS

[2019 $ in millions] 

Category Estimated cost 

savings 

Total (20 years; discounted at 7 percent) ....................................................................................................................................... $1,374.8 

Total (20 years; discounted at 3 percent ........................................................................................................................................ 1,971 

Annualized (discounted at 7 percent) .............................................................................................................................................. 129.8 

Annualized (discounted at 3 percent) .............................................................................................................................................. 132.5 

PHMSA does not anticipate that the 

amendments will have an adverse 

impact on safety or a significant effect 

on the environment. The largest 

quantified cost savings are due to the 

PSR amendments related to farm taps 

and atmospheric corrosion discussed in 

sections III.A and III.F, respectively, of 

the preamble to this final rule. PHMSA 

expects other amendments to improve 

regulatory flexibility, clarity, and 

simplicity. Additional details regarding 

PHMSA’s evaluation of the costs and 

benefits of this final rule are available in 

the Final Regulatory Impact Analysis 

(RIA) posted in the rulemaking docket. 

II. Background 

A. Regulatory Reform Executive Orders 

and Department Response 

As explained at greater length in the 

NPRM,4 DOT published a notice, 

‘‘Notification of Regulatory Review,’’ on 

October 2, 2017,5 requesting 

recommendations on existing DOT rules 

and other agency actions that could be 

eliminated without adversely affecting 

safety. DOT in particular solicited the 

public’s assistance in identifying DOT 

regulations and other actions which 

eliminate jobs or inhibit job creation; are 

outdated, unnecessary, or ineffective; 

impose costs that exceed benefits; create 

a serious inconsistency or otherwise 

interfere with regulatory reform 

initiatives and policies; could be revised 

to use performance standards in lieu of 

design standards; or that potentially 

unnecessarily encumber energy 

production. After a 30-day comment 

period, DOT re-opened the comment 

period until December 1, 2017.6 DOT 

received nearly 3,000 public comments. 

Approximately 30 pertained to the 

PSR.7

B. PHMSA Notice of Proposed 

Rulemaking 

Consistent with DOT’s regulatory 

reform efforts and informed by PSRpertinent comments received in 

response to the DOT Notification of 

Regulatory Review discussed above, 

PHMSA’s Office of Pipeline Safety 

(OPS) reviewed the PSR and identified 

unnecessary, outdated, and non-costjustified regulatory requirements that 

could be repealed, replaced, or modified 

without adversely affecting safety. 

PHMSA also considered certain 

petitions for rulemaking and petitions 

for reconsideration of earlier PSR 

amendments. 

On June 9, 2020, PHMSA published 

an NPRM 8 proposing several 

amendments to 49 CFR parts 191 and 

192 to reduce regulatory burdens on 

operators of gas pipelines without 

adversely affecting safety. The comment 

period for the NPRM ended on August 

10, 2020. PHMSA received 46 

comments on the NPRM, including latefiled comments. PHMSA received 

comments from groups representing the 

regulated pipeline industry; groups 

representing various public interests, 

including environmental groups; State 

utility commissions and regulators; 

individual pipeline operators; and 

private citizens. PHMSA received latefiled comments from the National 

Association of State Pipeline Safety 

Representatives (NAPSR), the Gas 

Piping Technology Committee (GPTC), a 

coalition of several industry trade 

associations, and GPA Midstream.9

PHMSA also had a conversation with a 

member of the Gas Pipeline Advisory 

Committee (GPAC) and representatives 

of the Pipeline Safety Trust (PST) after 

the end of the comment period; a 

summary of that meeting has been 

placed in the rulemaking docket. 

Consistent with §§ 5.13(i)(5) and 

190.323, PHMSA considered the latefiled comments and materials because of 

their relevance to the rulemaking and 

the absence of additional expense or 

delay resulting from their consideration. 

Some of the comments PHMSA 

received were beyond the scope of the 

amendments proposed in the NPRM. 

The issues raised in those comments 

may be the subject of other existing or 

future rulemaking proceedings. 

The remaining comments reflect a 

wide variety of views on the merits of 

the proposed PSR amendments. PHMSA 

read and considered all the comments 

posted to the docket for this rulemaking. 

These comments and PHMSA’s 

response to those comments are 

described in section III. 

Contemporaneously with PHMSA’s 

development of the NPRM, the 

President issued E.O. 13924, 

‘‘Regulatory Relief to Support Economic 

Recovery,’’ 10 directing Federal agencies 

to respond to the economic harm caused 

by the novel coronavirus by reviewing 

their regulations and considering taking 

appropriate action, consistent with 

applicable law, to temporarily or 

permanently rescind or modify those 

regulations to reduce regulatory burdens 

and thereby promote economic 

growth.11 PHMSA understands the cost 

savings expected from this final rule to 

be consistent with E.O. 13924’s 

mandate. 

C. Gas Pipeline Advisory Committee 

Meeting 

The Technical Pipeline Safety 

Standards Committee, commonly 

known as the Gas Pipeline Advisory 

Committee (GPAC; the committee), is an 

advisory committee mandated by statute 

(49 U.S.C. 60115) that advises PHMSA 

on proposed safety standards. The 

GPAC is one of two pipeline advisory 

committees that focus on technical 

safety standards that were established 

under the Federal Advisory Committee 

Act, as amended (5 U.S.C. App. 1–16). 

The GPAC consists of 15 members, with 

membership divided among Federal and 

State agencies, the natural gas industry, 


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12https://primis.phmsa.dot.gov/meetings/ 

MtgHome.mtg?mtg=151&nocache=4862. 

13 74 FR 63905. 

14A ‘‘farm tap’’ is the common name for a 

pipeline directly connected to a gas transmission, 

production, or gathering pipeline that provides gas 

to a customer. The term farm tap is not defined in 

the PSR; however, portions of a farm tap upstream 

of either the outlet of the customer’s meter or the 

connection to a customer’s piping, whichever is 

further downstream, may be a service line regulated 

under part 192. See § 192.3 (definition of ‘‘service 

line’’). 

15 82 FR 7972. 

and the public. The GPAC considers the 

‘‘technical feasibility, reasonableness, 

cost-effectiveness, and practicability’’ of 

each proposed pipeline safety standard 

and provides PHMSA with 

recommended actions pertaining to 

those proposals. 

The GPAC met in an online virtual 

meeting on October 7, 2020 to consider 

the regulatory proposals of the NPRM. 

The GPAC members discussed 

comments made on the NPRM. To assist 

the GPAC in its deliberations, PHMSA 

presented a description and summary of 

the proposals in the NPRM and the 

comments received on those issues. 

PHMSA also assisted the committee by 

fostering discussion, developing 

recommendations, and providing 

direction on which issues were most 

pressing. A transcript of the meeting 

and all presented materials is available 

in the docket for the rulemaking and on 

the web page PHMSA established for 

the meeting.12

The committee voted on the technical 

feasibility, reasonableness, costeffectiveness, and practicability of each 

of the NPRM’s provisions. In many 

instances, the committee recommended 

changes that the committee found 

would make certain proposals more 

feasible, reasonable, cost-effective, or 

practicable. These balloted 

recommendations and the transcript for 

the meeting serve as the GPAC’s report 

pursuant to 49 U.S.C. 60115. These 

recommendations are discussed in 

section III of the preamble to this final 

rule for each of the topics proposed in 

the NPRM. 

III. Analysis of Comments, GPAC 

Recommendations, and PHMSA’s 

Response 

The proposals in the NPRM, 

substantive comments received, as well 

as the GPAC’s recommendations are 

organized by topic below and are 

discussed in the appropriate section 

with PHMSA’s response to and 

resolution of those comments. 

Distribution Integrity Management 

Program (DIMP) 

On December 4, 2009, PHMSA issued 

a final rule titled, ‘‘Pipeline Safety: 

Integrity Management Program for Gas 

Distribution Pipelines.’’ 13 The 2009 rule 

created 49 CFR part 192, subpart P, 

requiring gas distribution operators to 

develop and implement integrity 

management (IM) programs. The NPRM 

contained two proposed revisions to 

DIMP requirements to ease or eliminate 

regulatory burdens on certain gas 

distribution operators. The first revision 

is to allow operators of farm taps 14

connected to transmission or regulated 

gathering lines the option of managing 

maintenance of pressure regulating 

devices under either § 192.740 or their 

DIMP in accordance with subpart P. As 

part of this amendment, PHMSA also 

proposed to exempt farm taps 

originating from unregulated gathering 

and production pipelines from DIMP, 

§ 192.740, and incident and annual 

reporting requirements in part 191. 

Second, the NPRM included a proposal 

to revise §§ 192.1003 and 192.1015 to 

exempt master meter operators from 

DIMP due to their simplicity. Master 

meter systems that serve fewer than 100 

customers from a single source are 

currently required to comply with a 

simplified set of DIMP requirements 

detailed in § 192.1015. 

A. Farm Taps (Sections 191.11, 192.740, 

192.1003) 

1. PHMSA’s Proposal 

In the NPRM, PHMSA proposed to 

revise §§ 192.740 and 192.1003 to give 

operators the choice to manage 

inspections of pressure regulators 

serving farm taps under either their 

DIMP or by following the inspection 

requirements at § 192.740. 

On January 23, 2017, PHMSA 

published a final rule that added 

§ 192.740, ‘‘Pressure regulating, 

limiting, and overpressure protection— 

Individual service lines directly 

connected to production, gathering, or 

transmission pipelines.’’ 15 Section 

192.740 includes maintenance 

requirements for regulators and 

overpressure protection equipment for 

an individual service line that originates 

from a transmission, gathering, or 

production pipeline (i.e., a farm tap). 

Currently, such devices must be 

inspected and tested at least once every 

3 calendar years, with intervals not to 

exceed 39 months. The 2017 rule also 

revised the DIMP applicability 

regulations at § 192.1003 to exclude 

farm taps from DIMP requirements. The 

change was intended to create uniform 

compliance requirements for farm taps, 

address over-pressurization risks, and 

decrease the burden of meeting the 

DIMP requirements for transmission and 

gathering line operators who otherwise 

do not operate distribution assets. 

However, PHMSA had not considered 

that some farm taps are operated by 

local distribution companies rather than 

the operator of the transmission, 

gathering or production line itself. 

Operators who historically had included 

farm taps in their DIMP found it 

burdensome to remove those facilities 

from their plan and reevaluate the risks 

under a new, prescriptive program. 

DOT received a comment in response 

to the Notification of Regulatory Review 

from the American Gas Association 

(AGA), the American Petroleum 

Institute (API), and Interstate Natural 

Gas Association of America (INGAA) 

(collectively, ‘‘the Associations’’), which 

recommended that PHMSA revise 

§§ 192.740 and 192.1003 to allow 

operators the flexibility to address the 

maintenance of farm taps under either 

of these regulatory requirements. After 

considering those comments, the NPRM 

proposed to revise §§ 192.740 and 

192.1003 to exempt farm taps 

originating from transmission lines and 

regulated gathering lines from § 192.740 

if they are included in a DIMP under 

subpart P. This provides operators the 

choice to manage the safety of farm tap 

regulators under either DIMP or the 

§ 192.740 inspection requirement. 

Finally, the NPRM included a 

proposal to exempt farm tap service 

lines connected to unregulated 

gathering or production pipelines from 

annual reporting (§ 191.11), farm tap 

regulator maintenance (§ 192.740), and 

DIMP (part 192, subpart P). Any portion 

of a farm tap that meets the definition 

of a service pipeline at § 192.3 must still 

comply with all other requirements in 

parts 191 and 192 applicable to service 

pipelines, even if the source of the 

service pipeline is not regulated by 

PHMSA. For example, an entity that 

operates a service line connected to a 

production pipeline must have an 

operator identification number in 

accordance with § 191.22 and must 

submit gas distribution incident reports 

for incidents that occur on the service 

line (§ 191.9). While the operator’s 

production pipeline is exempt from part 

191 (see § 191.1(b)(4)), any facility that 

meets the definition of a service line is 

a regulated distribution pipeline and 

therefore does not fall within the 

exemption for unregulated gathering 

and production pipelines. 

2. Summary of Public Comments 

Several commenters suggested 

PHMSA should simplify how farm tap 

requirements are presented in the PSR. 

The American Association of Laboratory 


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Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations 2213 

Accreditation (A2LA) recommend 

adding a provision requiring that those 

entities conducting inspections achieve 

and maintain ISO/IEC 17020 

(Conformity Assessment-Requirements 

for the Operation of Various Types of 

Bodies Performing Inspection) 

accreditation. The FreedomWorks 

Foundation (FreedomWorks) 

commented that the proposed changes 

in the NPRM would especially benefit 

smaller operations burdened by the high 

cost of compliance upon startup. PST 

commented the proposed PSR 

amendments appear to demonstrate an 

equivalent level of safety and they do 

not oppose this change. One company 

provided an editorial suggestion that the 

last word in proposed § 192.740(c)(3) 

should be ‘‘or’’ to clarify that this 

section (§ 192.740) does not apply if any 

one of the listed conditions apply. 

Several commenters commented on 

farm tap-related terms and definitions 

proposed in § 192.740. Sander 

Resources suggested there were at least 

two significant definitional issues 

contained within the proposed rule that 

confused farm tap operators. The first 

relates to ‘‘unregulated . . . gathering.’’ 

Sander Resources commented that, 

technically, there is no such thing as 

‘‘unregulated gathering.’’ All gathering 

lines are subject to the jurisdiction of 

PHMSA, but some are exempted from 

the requirements of part 192 as specified 

in § 192.9. Thus, this reference could be 

interpreted to mean that all gathering 

lines are still subject to the requirements 

of § 192.740 or § 192.1003 and related 

provisions, which could encompass 

much of part 192. They recommended 

that PHMSA clarify what it means to be 

‘‘unregulated,’’ possibly through a 

reference to whether a line is subject to 

regulation under § 192.9. The Gas 

Piping Technology Committee (GPTC) 

similarly suggested that PHMSA clarify 

that regulated and unregulated gathering 

lines are as determined in § 192.8. 

Sander Resources (on behalf of the 

Independent Petroleum Association of 

America, or IPAA) also raised a concern 

related to the definition of ‘‘service 

line’’ and, in particular, language in the 

NPRM’s preamble suggesting that the 

part 192-regulated ‘‘service line’’ 

portion of a farm tap would begin at the 

‘‘first aboveground point where 

downstream piping can be isolated from 

source piping (e.g., a valve or regulator 

inlet).’’ AGA, API, the American Public 

Gas Association (APGA), and INGAA 

(collectively, AGA et al.) jointly 

submitted a similar comment 

recommending against PHMSA defining 

the ‘‘service line’’ portion of a farm tap 

in the proposed amendment to 

§ 192.740. They commented it is neither 

practicable nor necessary for safety to 

define a uniform starting point for the 

service line on every farm tap directly 

connected to a transmission line. Their 

preferred approach would be to 

incorporate a distribution center 

definition that allows farm tap piping to 

be classified as a distribution center and 

explicitly allow operators to designate 

piping as transmission, even if the 

pipeline could be classified as 

distribution under the existing § 192.3. 

Rather than defining where the ‘‘service 

line’’ starts for farm taps under part 192, 

TC Energy commented PHMSA should 

revise § 192.740 to apply to ‘‘pipelines’’ 

serving farm tap customers instead of 

‘‘service lines,’’ and eliminate the 

description of the source of supply to 

the farm tap customer. TC Energy 

believes that these changes would 

maintain the intended protections to 

farm tap customers and address 

industry concerns. A private citizen 

similarly commented that, in addition to 

these clarifications, PHMSA should 

clarify the definitions for transmission 

lines and distribution centers. 

GPA Midstream stated that they did 

not support the NPRM preamble 

statement that, on a farm tap, the 

boundary between source piping and 

the distribution service lines is the first 

aboveground isolation point 

downstream from the source piping. 

They stated that there is no legal basis 

for using that point to delineate where 

a source production, gathering, or 

transmission line ends and a gas 

distribution service line under part 192 

begins in a farm tap configuration. GPA 

Midstream urged PHMSA to 

acknowledge in the final rule that an 

operator may exercise reasonable 

discretion in determining where source 

piping ends and distribution service 

line piping, if any, begins in farm tap 

configurations. The Independent Oil 

and Gas Association of West Virginia 

(IOGAWV) commented PHMSA should 

not attempt to use its authority to 

change private contracts by transferring 

the cost of complying with the PSR to 

producers and unregulated gathering 

line operators. IOGAWV and the Ohio 

Oil and Gas Association (OOGA) stated 

PHMSA should take this opportunity to 

exempt farm taps from the PSR. IPAA 

urged PHMSA to recognize the 

significant difference between privatelyowned farm taps, governed by contract 

or statute, and true distribution systems. 

GPA Midstream reiterated concerns 

with the definition of the start of a 

service line and the applicability of part 

192 to farm taps connected to 

production lines and unregulated 

gathering lines in supplemental 

comments submitted after the GPAC 

meeting. 

The GPAC voted unanimously in 

favor of the PSR amendments proposed 

in the NPRM, provided that PHMSA 

remove § 192.740(c)(4), thus eliminating 

language implying where a service line 

starts on a farm tap. 

3. PHMSA Response 

The final rule adopts the amendments 

with respect to farm taps as proposed in 

the NPRM, but revises the proposed 

§ 192.740 as discussed below. PHMSA 

determined that compliance with the 

pressure regulator inspection 

requirements in § 192.740 or 

compliance with DIMP provide an 

equivalent level of safety. DIMP does 

not include specific, prescriptive 

inspection requirements for pressure 

regulating devices; however, operators 

are required by § 192.1007 to evaluate 

risks due to equipment failure under 

DIMP, which includes pressure 

regulating devices. Accordingly, farm 

tap operators must consider 

overpressure risk due to regulator 

failure in their DIMP, especially if the 

source pipeline pressure is very high. 

While § 192.740 is focused on pressure 

regulator maintenance, DIMP is a 

broader safety program that requires 

operators identify, evaluate, rank, and 

mitigate a wide range of risks to 

pipeline safety. Either requirement 

provides safety to farm tap customers by 

reducing the probability of a regulator 

system malfunction and, in the case of 

DIMP, incidents caused by other threats 

such as excavation damage and 

corrosion. Therefore, this change 

provides greater flexibility for operators 

of these farm taps while still requiring 

that operators evaluate all equipment to 

protect against failures and protect 

human health and the physical 

environment. 

This proposed amendment was 

intended to provide flexibility for farm 

tap operators. It was not designed to 

resolve more general definitional 

questions surrounding the topic of farm 

taps. Therefore, PHMSA agrees with the 

suggestion to remove the proposed 

§ 192.740(c)(4) from the final rule, 

which implied where the source piping 

on a farm tap ends and distribution, 

transmission, or customer piping begins. 

PHMSA believes that this change 

resolves most of the concerns about 

definitional changes raised by 

commenters. To the extent that there are 

remaining questions surrounding farm 

taps following this rulemaking, PHMSA 

will use ongoing efforts such as the 

proposed Farm Taps Frequently Asked 


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16 85 FR 21820 (Apr. 20, 2020). 17RINs 2137–AF39 (Pipeline Safety: Safety of Gas 

Gathering Pipelines) and 2137–AF38 (Pipeline 

Safety: Safety of Gas Transmission Pipelines, Repair 

Criteria, Integrity Management Improvements, 

Cathodic Protection, Management of Change, and 

Other Related Amendments), associated with 

PHMSA, ‘‘Notice of Proposed Rulemaking: 

‘‘Pipeline Safety—Safety of Gas Transmission and 

Gathering Pipelines,’’ 81 FR 20721 (Apr. 8, 2016). 

18 36 FR 9667. 

19 38 FR 9083. 

20 60 FR 41821. 

21 60 FR 41821. 

22PHMSA Interpretation #PI–73–0110 (June 6, 

1973), https://cms7.phmsa.dot.gov/regulations/ 

title49/interp/PI-73-0110. 

23 84 FR 11253. 

24PHMSA, ‘‘Notice of Proposed Rulemaking: 

Integrity Management Program for Gas Distribution 

Pipelines,’’ 73 FR 36015 (June 25, 2008) (DIMP 

NPRM). 

Questions (FAQs); 16 the remaining 

rulemaking projects associated with the 

Safety of Gas Transmission and Gas 

Gathering Pipelines NPRM; 17 and, if 

necessary, additional rulemaking and 

guidance. While the comment from TC 

Energy sidesteps these definitional 

issues, and has the benefit of extending 

protection to farm taps that operate at 

greater than 20 percent of specified 

minimum yield strength (SMYS) (and 

are therefore classified as transmission 

lines rather than service lines pursuant 

to the definition of a transmission line 

in § 192.3), it requires defining an 

additional term (‘‘farm tap customer’’) 

which was not made available for public 

comment in the NPRM or discussed by 

other comments in the rulemaking 

docket. 

While this final rule does not define 

the boundaries of that portion of a farm 

tap that is regulated as a service line 

under part 192, the fact that a farm tap 

may include a regulated service line 

remains unchanged. Therefore, PHMSA 

disagrees with comments that the 

NPRM’s characterization of portions of 

farm taps as jurisdictional service lines 

creates ‘‘entirely new’’ legal obligations 

for operators of service lines who also 

operate non-jurisdictional production 

lines and rural gathering lines that are 

not subject to safety regulation under 

part 192. Removing farm taps connected 

to production lines and unregulated 

gathering lines from the scope of the 

entire PSR, as suggested by some 

commenters, would be a consequential 

change from longstanding regulatory 

application and is beyond the scope of 

this final rule. 

PHMSA and its predecessor agencies 

have been explicit and consistent with 

respect to the applicability of the part 

192 regulations to distribution service 

lines in farm tap applications since the 

earliest years of Federal gas pipeline 

safety oversight. The Office of Pipeline 

Safety revised the definition of a service 

line in § 192.3 to clarify the point at 

which a service line ends and customer 

piping begins in an NPRM entitled, 

‘‘Minimum Federal Safety Standards for 

Transportation of Natural and Other Gas 

by Pipeline: Definition of Service Line,’’ 

published on April 10, 1971.18 On April 

10, 1973, PHMSA finalized the proposal 

and defined the downstream end of a 

service line as the customer meter or 

connection to customer piping, 

whichever is further downstream.19

This boundary stands with minor 

clarifications to this day at § 192.3. 

PHMSA formulated the definition of 

‘‘service line’’ to address service lines in 

farm tap applications and other 

situations where no meter is present. 

PHMSA’s predecessor agency, the 

Research and Special Programs 

Administration, again acknowledged the 

regulated status of service lines in farm 

tap applications in a final rule titled, 

‘‘Pipeline Safety: Customer-Owned 

Service Lines’’ issued on August 14, 

1995.20 Finally, providing gas to farm 

tap customers is not a defined gathering 

or production function in either § 192.3 

or in API Recommended Practice (RP) 

80 (incorporated by reference in 

§ 192.7). While production pipelines 

and some gathering pipelines are not 

subject to safety regulation under part 

192, the distribution of national gas to 

customers is subject to PHMSA 

jurisdiction (49 U.S.C. 60101(a)(21)(i)) 

and the applicability of part 192 

(§§ 192.1(a), 192.3) regardless of other 

activities in which an operator may also 

be engaged. 

Regarding operators’ concerns about 

their responsibility for customer-owned 

piping that they do not own or have 

access to, PHMSA reiterates that the 

final rule imposes no new requirements 

on operators of service lines in farm tap 

applications. Section 192.3 provides 

that a service line ends at the 

connection to customer-owned piping, 

or the outlet of the meter, whichever is 

further downstream. In the preamble to 

the 1995 customer-owned service line 

rule described above, PHMSA explained 

that that the PSR applies to the 

distribution of gas up to the end of a 

pipeline operator’s service line.21 In an 

earlier interpretation, PHMSA also 

noted that customer piping downstream 

of the end of a service line as defined 

in § 192.3 is not subject to part 192, 

provided the gas is for the customer’s 

own use.22 Therefore, the PSR does not 

require the source pipeline operator to 

maintain customer-owned piping 

downstream of the customer meter as 

defined in § 192.3. If there is no 

customer meter, then the service line 

terminates at the connection to 

customer-owned piping. Some operators 

do maintain customer piping 

voluntarily or as required by State, 

local, or contractual requirements. If an 

operator of a service line does not 

maintain the customer’s piping under 

such arrangement, then the customer 

notification requirements in § 192.16 

may apply. 

PHMSA agrees with certain comments 

to clarify language in § 192.740. In the 

final rule, PHMSA has replaced the term 

‘‘unregulated gathering line’’ with a 

gathering line other than a regulated 

gathering line as determined in § 192.8. 

In other words, a gathering line as 

determined in accordance with § 192.8 

and API RP 80, but excluding a Type A 

or Type B regulated gathering line as 

defined in § 192.8. In addition, the 

exceptions in paragraph (c) are now 

separated by an ‘‘or’’ in the final rule. 

Lastly, because the PSR revisions 

adopted in this final rule obviate the 

need for its March 29, 2019 ‘‘Exercise of 

Enforcement Discretion Regarding Farm 

Taps,’’ 23 PHMSA withdraws that 

document as of the effective date of this 

final rule. 

B. Master Meter Operators (Sections 

192.1003, 192.1005, 192.1015) 

1. PHMSA’s Proposal 

In the NPRM, PHMSA proposed to 

revise §§ 192.1003, 192.1005, and 

192.1015 to exempt master meter 

operators from DIMP requirements. A 

‘‘master meter system’’ is defined at 

§ 191.3 as a pipeline system for 

distributing gas where the operator 

purchases metered gas from an outside 

source for resale through a gas 

distribution pipeline system. Examples 

of master meter systems include owners 

of apartment complexes or mobile home 

parks who provide or sell gas to tenants. 

Unlike most gas distribution operators, 

delivering gas is typically not a master 

meter operator’s primary business. 

When DIMP requirements were first 

proposed in 2008,24 PHMSA recognized 

that master meter systems tend to be 

operated by small entities with simple 

systems compared to normal gas 

distribution operators. Section 192.1015 

was intended to provide a simplified set 

of DIMP requirements that master meter 

operators could easily implement and 

that would enhance safety. However, 

PHMSA has determined that Section 

192.1015 requirements are neither easily 

implemented nor do they enhance 

safety. Master meter operators have 

struggled to implement the relatively 

simple master meter systems DIMP 

requirements that were designed for 


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25The ‘‘Simple, Handy, Risk-based Integrity 

Management Plan’’ tool published by the APGA 

Security and Integrity Foundation. 

26PHMSA Gas Distribution Integrity Assessment 

Question Set, available at https://

www.phmsa.dot.gov/forms/phmsa-gas-distributionia-question-set-pdf. 

27TRB, Transportation Research Board Special 

Report 327: Safety Regulation for Small LPG 

Distribution Systems (2018), https://www.nap.edu/ 

catalog/25245/safety-regulation-for-small-lpgdistribution-systems. 

complex gas distribution systems. In 

addition, PHMSA determined that there 

is no safety benefit from applying even 

that limited set of DIMP requirements to 

master meter systems, as compliance 

with other applicable pipeline safety 

regulations in part 192 provides robust 

assurance of public safety. The 

applicable part 192 requirements that 

PHMSA considered include, but are not 

limited to, operations and maintenance 

requirements at subpart L and subpart 

M, continuing surveillance 

requirements at § 192.613, and the 

failure investigation requirement at 

§ 192.617. 

2. Summary of Public Comments 

Several commenters generally 

supported exempting master meter 

operators from the DIMP requirements 

in part 192. These commenters 

(including the National Propane Gas 

Association (NPGA), the National 

Association of Pipeline Safety 

Representatives (NAPSR), AmeriGas, 

and Superior Plus Propane (SPP)) 

agreed with PHMSA’s characterization 

of master meter systems as generally 

small, simple systems that see little 

benefit from DIMP compliance. These 

commenters agreed that compliance 

with existing subparts A through N of 

part 192 is sufficient to ensure the safety 

of small, simple master meter systems. 

They asserted that the current 

requirement of subpart P to create a 

DIMP, even using the SHRIMP tool,25

consumes significant additional time 

and resources with little or no safety 

benefit, noting that the result of the 

process for master meter systems is 

typically a determination that there is 

no need for additional mitigating 

actions on any portion of the pipeline 

system. As a result, the commenters 

stated that the time and resources 

expended to comply with the DIMP 

requirements have no meaningful safety 

benefits for such systems. The PST 

commented that they do not oppose this 

change, but urged PHMSA and its State 

partners to ensure that master meter 

operators are managing the integrity 

risks to their systems outside the 

context of a DIMP. 

PHMSA also received comments 

concerning similar DIMP requirements 

for small liquefied petroleum gas (LPG) 

distribution pipeline systems. A ‘‘small 

LPG operator’’ is defined in § 192.1001 

as a liquefied petroleum gas distribution 

system that serves fewer than 100 

customers from a single source. Small 

LPG operators are currently required to 

comply with the same DIMP 

requirements as master meter systems. 

Several commenters (including NPGA, 

NAPSR, AmeriGas, and SPP) 

commented that jurisdictional propane 

pipeline systems are like master meter 

systems and therefore small LPG 

operators should be exempt from the 

DIMP requirements as well. They 

commented that small LPG systems are 

comparable to master meter systems in 

size and application. Like master meter 

systems, the commenters claimed the 

majority of small LPG pipeline systems 

are single-property systems that occupy 

a small overall footprint in size, 

generally operate at a single operating 

pressure, and have no equipment other 

than pipe, meters, regulators, and 

valves. They commented that small LPG 

systems typically serve 25 customers or 

less, and facilities such as those at RV 

parks or strip malls can have as few as 

three customers; very few small LPG 

systems serve more than 100 customers. 

One anonymous commenter associated 

with an LPG system stated that the 

DIMP process is lengthy and 

unnecessary, and that in their 

experience, many of the prompts on the 

DIMP form 26 do not make sense given 

the layout of a small LPG utility. NAPSR 

stated that many of these smaller 

systems identify only third-party 

damage as a major threat to the system, 

and a DIMP requires a considerable 

amount of work for a very small amount 

of safety benefit. 

Commenters representing LPG 

suppliers (including AmeriGas, SPP, 

and NPGA) noted that with regard to the 

PSR, the regulated entity is the entity 

that owns the pipeline and receives the 

operator ID issued by PHMSA for that 

pipeline system. They stated that in 

many cases, the LPG supplier does not 

operate the pipeline and their primary 

business is to transport gas by delivery 

truck, not pipelines. They further stated 

that most are contractors to the entity 

that owns the pipeline and the pipeline 

operator ID for the system. They stated 

that many of these master meter 

operators use contractors for service, but 

those contractors are not the operators 

under part 192. These commenters 

agreed that the other part 192 

requirements continue to apply to 

provide adequate requirements for small 

LPG systems in the absence of DIMP 

requirements. They also stated that in 

addition to the requirements in part 192 

applicable to all gas distribution 

pipelines, § 192.11 requires LPG 

distribution systems to comply with a 

National Fire Protection Association 

(NFPA) standard, NFPA 58 (LP-Gas 

Code) or NFPA 59 (Utility LP-Gas Plant 

Code), which contains comparable and 

supplemental provisions that address 

safety. They asserted that the additional 

requirements of DIMP do not add a 

measure of safety beyond the provisions 

in part 192 and NFPA 58. 

AmeriGas and NPGA estimated that 

extending the NPRM’s proposed DIMP 

exemptions for master meters to small 

LPG systems could result in $1.12 

million in annualized cost savings; this 

estimate was calculated by applying the 

cost estimates in the RIA to an estimate 

of the number of small LPG operators in 

Safety Regulation for Small LPG 

Distribution Systems, a report published 

in 2018 by the Transportation Research 

Board (TRB).27 The commenters 

asserted that these additional savings 

would further PHMSA’s goal of 

reducing regulatory impact burdens. 

The commenters also stated that these 

estimated savings to the industry would 

allow small LPG operators to devote 

more of their resources in other areas of 

safety. 

NAPSR suggested that small 

distribution utilities with 100 or fewer 

customers should also be exempted 

from the DIMP requirements, stating 

that many master meter systems, small 

distribution systems and small LPG 

systems typically have no threats 

beyond the minimum threats listed in 

§ 192.1015(b)(2). 

The GPAC voted unanimously in 

favor of PHMSA’s proposed amendment 

with respect to the applicability of 

DIMP requirements to master meter 

systems. The GPAC did not recommend 

changes to DIMP requirements for small 

LPG systems or small distribution 

systems. 

3. PHMSA Response 

The final rule revises §§ 192.1003, 

192.1005, and 192.1015 to eliminate 

DIMP requirements for master meter 

systems as proposed in the NPRM. 

Through inspections, PHMSA and its 

State partners have seen that master 

meter operators have had significant 

difficulties implementing these 

simplified DIMP requirements 

effectively. PHMSA’s State-Federal 

DIMP team has noted that a significant 

amount of State inspection and operator 

maintenance effort was being used to 

improve DIMP compliance among 

master meter operators. Despite these 


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28 76 FR 5494. 

29 74 FR 63905. 

30 76 FR 5495. 

31 DOT Form PHMSA F 7100.1. 

32https://www.phmsa.dot.gov/pipeline/gasdistribution-integrity-management/dimpperformance-measures-data-analysis-procedurereport. 

efforts, inspection data voluntarily 

submitted by some States shows that 

approximately half of master meter 

operators inspected between 2014 and 

2017 did not have an acceptable DIMP 

in place before the compliance deadline 

of August 2, 2011, and for any given 

requirement 10–20% of master meter 

operators were not in compliance. 

PHMSA believes that this effort may be 

better used to implement other part 192 

safety requirements effectively that 

master meter system operators will 

remain obliged to follow. 

Even when properly implemented, 

DIMP principles that are effective for 

larger operators do not have the same 

value for comparatively simple master 

meter systems within a limited 

geographical area. The DIMP NPRM 

noted that master meter systems often 

include only one type of pipe, a single 

operating pressure, and no equipment 

other than pipe, meters, regulators, and 

valves. For these small and simple 

systems, a comprehensive management 

system like DIMP is not required to 

integrate data and information to 

identify risk mitigation strategies and 

actions. PHMSA’s experience indicates 

that the analysis and documentation 

requirements of DIMP have had little 

safety benefit for this type of operator. 

And, anecdotally, PHMSA and State 

enforcement personnel have advised 

that focusing on more fundamental risk 

mitigation activities (particularly those 

required by §§ 192.605 (Procedural 

manual for operations, maintenance, 

and emergencies), 192.613 (Continuing 

surveillance), and 192.617 

(Investigations of failures)) yields more 

safety benefits than implementing a 

DIMP for this class of operators. Due to 

the implementation issues identified by 

PHMSA and State inspectors, PHMSA 

expects that exempting master meter 

operators from subpart P would result in 

cost savings for master meter operators 

without negatively impacting safety. 

Considering the burden on finite State 

inspection resources, implementation 

difficulties, and the limited safety 

benefits of DIMP compliance for master 

meter systems described above, PHMSA 

believes there could even be potential 

safety benefits because operators and 

inspectors can prioritize more pertinent 

compliance activities specific to master 

meter systems. 

PHMSA appreciates the comments 

regarding the applicability of DIMP 

towards small LPG operators and 

acknowledges that many small LPG 

systems have configurations like master 

meter systems. However, PHMSA 

believes that the decision about whether 

to extend the DIMP exception to such 

facilities or to all distribution systems 

with fewer than 100 customers would 

benefit from additional safety analysis 

and notice and comment procedures 

prior to further consideration. In 2018, 

the TRB published a report on Federal 

safety standard for small LPG systems. 

The TRB’s recommendations focused on 

clarifying the definition of a ‘‘public 

place’’ and improving State inspection 

programs. While the TRB suggested that 

a PHMSA-supervised State waiver 

process could be appropriate, it did not 

recommend exempting all small LPG 

systems from DIMP or any other 

requirement. PHMSA will continue to 

evaluate the issue of DIMP requirements 

for small LPG systems and, if 

appropriate, propose changes in a future 

rulemaking giving due consideration to 

the public comments on the NPRM, the 

recommendations of the GPAC, and the 

TRB report. For similar reasons, PHMSA 

has also not adopted suggestions from 

commenters to exempt other 

distribution operators with fewer than 

100 customers. 

Reporting and Information Collections 

C. Mechanical Fitting Failure Reporting 

(Sections 191.12, 192.1009) 

1. PHMSA’s Proposal 

On February 1, 2011, PHMSA issued 

the final rule, ‘‘Pipeline Safety: 

Mechanical Fitting Failure Reporting 

Requirements’’ 28 adding §§ 191.12, 

192.1001, and 192.1009 to the PSR. 

Section 191.12 sets forth the 

requirement for operators to report 

mechanical fitting failures (MFFs) 

through DOT Form PHMSA F–7100.1– 

2 (MFF report form). Section 192.1001 

defines a ‘‘mechanical fitting.’’ Section 

192.1009 requires distribution pipeline 

operators to submit a MFF report to 

PHMSA almost every time there is a 

release from a mechanical joint, the 

majority of which are low-consequence 

or no-consequence events that do not 

meet the definition of an incident at 

§ 191.3. These requirements expanded 

an earlier requirement established in the 

December 4, 2009 DIMP final rule that 

was limited to mechanical couplings 

used to join plastic pipe.29 The DIMP 

final rule adopted the MFF report 

requirement as a result of investigations 

of incidents caused by poorly designed 

or improperly installed mechanical 

joints throughout the pipeline industry. 

PHMSA initially sought to collect these 

data in 2011 to determine the frequency 

of mechanical joint failures and identify 

the most common characteristics of 

those failures.30 The 2009 DIMP final 

rule was part of a broader effort by 

PHMSA and the gas distribution 

pipeline industry to identify potential 

safety issues with plastic gas pipelines. 

Like the Gas Distribution Incident 

Report form,31 the MFF report form 

requires operators submit information 

on the design and installation of the 

failed fitting and the apparent cause of 

the failure. The MFF report form also 

includes manufacturing information; 

however, this is generally not known by 

the operator and therefore is reported as 

‘‘unknown.’’ MFF reports are required 

for any failure of a mechanical joint 

other than those that result in a ‘‘nonhazardous leak,’’ as opposed to Gas 

Distribution Incident Reports, which are 

required only for events that meet the 

criteria for reportable ‘‘incidents’’ in 

§ 191.3. Operators report any 

‘‘hazardous leak’’ as that term is defined 

at § 192.1001. The criteria for a 

‘‘hazardous leak’’ does not depend on 

an outcome severity threshold. 

Approximately 15,000 MFF reports are 

submitted to PHMSA each year, 

compared to approximately 100 Gas 

Distribution Incident Reports due to all 

causes. PHMSA publishes a report on 

the information collected and its 

analysis of the information received 

annually, which is available online.32

PHMSA determined that further 

collection of MFF reports has limited 

value, and proposed to remove 

§§ 191.12 and 192.1009, eliminating the 

requirement for operators to submit 

MFF reports through DOT Form 

PHMSA F–7100.1–2. PHMSA 

understands from analyzing MFF report 

forms received over the last decade that 

the purposes of this reporting 

requirement have been realized: 

PHMSA’s analysis of data from MFF 

reports confirmed its expectations 

regarding MFF characteristics and 

causes, and pipeline operators have 

become much more sensitive to MFFs. 

PHMSA considered that operators 

would still be required to submit 

incident reports via a modified version 

of the Gas Distribution Incident Report 

form (which would include most of the 

information on the MFF report form) for 

releases from mechanical fittings that 

meet the definition of an incident at 

§ 191.3. Part G5–5 of the Gas 

Distribution Incident Report form 

currently requires operators to identify 

the MFF report number for incidents 

involving an MFF; PHMSA therefore 

proposed to replace this cross-reference 


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33 DOT Form PHMSA F 7100.1–1. 

with the fitting, manufacturer, and 

failure information that is currently 

collected on the MFF report form. 

PHMSA also proposed to revise the Gas 

Distribution Annual Report form 33 to 

include a count of hazardous leaks 

involving a mechanical joint failure. 

This issue was raised in comments 

submitted in response to the DOT 

Notification of Regulatory Review from 

the Associations, the Gas Piping 

Technology Committee (GPTC), and the 

West Virginia Oil and Natural Gas 

Association (WVONGA), which 

identified the MFF reporting 

requirement as an unnecessary and 

burdensome information collection. 

2. Summary of Public Comments 

Several commenters (including 

AmeriGas, NPGA, SPP, Dresser Natural 

Gas Solutions, the Norton McMurray 

Manufacturing Company (NORMAC), 

Oleksa and Associates, the Plastics Pipe 

Institute (PPI), and a private citizen) 

supported eliminating the MFF 

reporting requirement. Dresser 

contended that PHMSA has found these 

data do not provide meaningful trends 

related to risk of pipeline leaks. PPI 

stated that the removal of this regulatory 

reporting burden reduces the 

unnecessary focus on mechanical 

fittings as a potential source of 

incidents. NORMAC agreed that MFF 

reporting has not provided statistically 

significant trends or information upon 

which operators or regulators can act. 

Several commenters (including 

AmeriGas, SPP, and NPGA) expressed 

concerns regarding PHMSA’s proposal 

to modify the Gas Distribution Annual 

Report form to collect data on the 

number of mechanical joint failures. 

Those commenters opposed including a 

count of leaks involving mechanical 

joints on the Gas Distribution Annual 

Report form, noting that if limited value 

was derived from independent MFF 

reporting, it is reasonable to conclude 

that there would be limited value in 

tracking and reporting the number of 

MFFs on revised Gas Distribution 

Annual and Incident Report forms. 

NORMAC commented that part C of the 

current Gas Distribution Annual Report 

form requires each operator to report the 

total number of leaks and how many 

were classified as hazardous based upon 

the cause of the leak. The instructions 

provided for completion of part C 

describe each classification of cause in 

detail in terms of what is being 

requested of an operator. NORMAC 

noted that modifying the Gas 

Distribution Annual Report form as 

proposed will lead the user to jump to 

the conclusion that any leak involving 

a mechanical joint arises from the 

mechanical fitting being ‘‘faulty,’’ when 

the leak may be caused by improper 

installation by the operator and should 

therefore be coded as caused by 

‘‘Incorrect Operation.’’ GPTC 

commented that reporting leaks caused 

by mechanical joint failure would repeat 

reporting of leaks caused by ‘‘pipe, 

weld, or joint failure’’ and potentially be 

confusing for operators. They further 

commented that the leak information is 

intended to be general in nature and not 

intended to capture the ‘‘laboratory 

analysis’’ for eliminated leaks. 

Regarding the proposed changes to 

Gas Distribution Incident Report form, 

NORMAC expressed concerns with the 

NPRM’s proposal to incorporate existing 

data fields in the current MFF report 

within part G (Apparent Cause), subcause G5 (Pipe, Weld, or Joint Failure) 

of a revised Gas Distribution Incident 

Report form. NORMAC noted that the 

cause of a failure may not be due to 

Pipe, Weld, or Joint Failure. 

Specifically, they noted that fittings that 

fail due to improper installation are 

required to be categorized under the 

‘‘Incorrect Operation’’ cause. NORMAC 

also mentioned that Question 12 under 

sub-cause G5 (Pipe, Weld, or Joint 

Failure) duplicate what sub-cause G7 

(Incorrect Operation) is asking. 

NORMAC stated that requiring 

respondents to answer the same 

question under two categories will lead 

to confusion and make effective analysis 

of the resulting database difficult. 

NORMAC submitted text revisions to 

sub-cause G5 of the Gas Distribution 

Incident Report form and associated 

instructions. 

Dresser raised similar concerns with 

both the Gas Distribution Annual Report 

and the Gas Distribution Incident Report 

forms, in addition to noting that there 

could be confusion concerning the 

difference between a mechanical fitting 

and a mechanical joint. Dresser noted 

that the existing categories support the 

reporting of pipeline failures where 

mechanical fittings may be involved 

under the existing categories of ‘‘Weld 

Pipe or Joint Failure’’ or ‘‘Incorrect 

Operation’’ depending on the causal 

factors being a manufacturing or design 

defect for the former or a deficiency in 

the field installation practice or 

improper application for the latter. 

NORMAC also supported addressing the 

distinction between ‘‘mechanical 

fitting’’ and ‘‘joint’’ to ensure that the 

regulatory oversight activity focus on 

joints, the making of joints, and the 

qualifying of joining procedures. 

Theresa Pugh Consulting commented 

that PHMSA should revise the Gas 

Distribution Incident Report form to 

include whether industrial and power 

sector customers were notified of a 

curtailment in gas supply following an 

incident and the duration of such 

disruption. The commenter stated the 

form should allow the operator to state 

if gas supply was maintained by redirecting natural gas at full contracted 

capacity to the customer through reverse 

flow or through alternative parties. The 

commenter noted that the power and 

industrial customers would benefit from 

a way to determine during contract 

negotiations whether the company they 

wish to purchase gas from has a sound 

and reliable safety program, but 

acknowledged challenges with ensuring 

that such information is not in a format 

that could be used by competitors to 

reverse engineer operational 

information about industrial customers 

such as plastics manufacturing plants. 

The commenter recommended that 

PHMSA should expand rather than 

shrink the reporting measures on its 

reporting forms. 

NORMAC commented that burden on 

operators can be drastically reduced 

beyond what the proposed rulemaking 

proposes by also eliminating the portion 

of Plastic Pipe Database Collection 

(PPDC) reporting conducted by the 

American Gas Association that deals 

with mechanical joints. NORMAC 

commented that the PPDC is nearly 

identical to the MFF and has also not 

shown useful trends. NORMAC also 

asserted that recording and reporting 

mechanical joint leaks through PPDC is 

not as effective as addressing the 

problem directly within each operator’s 

IM program. NORMAC suggested that 

PHMSA propose the discontinuation of 

this reporting effort in its role as PPDC 

chair. 

PST opposed eliminating the MFF 

report requirement. They questioned 

whether this would prevent PHMSA 

from becoming aware of thousands of 

MFFs per year, many of which result in 

hazardous and potentially explosive 

leaks, others of which result in nonexplosive but hazardous leaks of 

methane into the atmosphere. The 

commenter stated these circumstances 

would also not typically be reported as 

a safety-related condition, because of 

the many exemptions and exceptions to 

the safety-related condition reports 

listed in § 191.23(b). PST asserted the 

detailed information on MFFs is 

currently gathered so that PHMSA can 

identify any patterns among those 

failures, either by geography or failure 

type or any other common parameter. 

Limiting the detailed reporting in the 

MFF report to reportable incidents 

eliminates another source of 


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2218 Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations 

34PHMSA, Analysis of Data from Required 

Reporting of Mechanical Fitting Failures that Result 

in a Hazardous Leak (§ 192.1009) at 47–48 (Jul. 4, 

2018), https://www.phmsa.dot.gov/sites/ 

phmsa.dot.gov/files/docs/technical-resources/ 

pipeline/gas-distribution-integrity-management/ 

66046/mffr-data-analysis-procedure-2017-datareport-final-07-04-2018.pdf. 

35PHMSA, Analysis of Data from Required 

Reporting of Mechanical Fitting Failures that Result 

in a Hazardous Leaks (§ 192.1009) (Oct. 15, 2016). 

36PHMSA makes such raw data available on its 

website at https://www.phmsa.dot.gov/data-andstatistics/pipeline/mechanical-fitting-failure-datagas-distribution-operators. 

information of leading indicators of 

problems common among operators, one 

that nets information on 15,000 fitting 

failures each year. 

The GPAC voted 13–2 in favor of 

PHMSA’s proposed amendment to 

eliminate the MFF reporting 

requirement. PST and the 

Environmental Defense Fund (EDF) 

voted against the proposed amendment. 

During the GPAC discussions, PST 

reiterated its reservations regarding 

reducing the availability to PHMSA and 

other safety regulators of information on 

hazardous leaks. PST also opined that 

eliminating MFF reporting may reduce 

operators’ incentives to improve 

mechanical fitting performance. EDF, 

meanwhile, contended that the MFF 

report data being eliminated could 

prove helpful to Federal and State 

environmental regulators and public 

service commissions in evaluating the 

significance of methane emissions from 

service line couplings. 

3. PHMSA Response 

In the final rule, PHMSA is adopting 

the amendments to MFF reporting 

requirements at §§ 191.12 and 192.1001 

as proposed in the NPRM. PHMSA is 

also retaining the proposed requirement 

to include a count of MFFs on the Gas 

Distribution Annual Report form and 

revision of the Gas Distribution Incident 

Report form to include information from 

the MFF report for incidents involving 

a failure of a mechanical joint. 

PHMSA’s 2018 analysis of MFF data 

reports obtained to date confirm 

PHMSA’s expectations regarding the 

frequency and characteristics (including 

material, type, location, and vintage of 

fittings) of MFFs when it began this 

information collection activity under 

the DIMP final rule.34 The 2018 analysis 

further notes that the MFF reports 

submitted in the preceding year show 

similar trends to the previous 5 years, 

and that all changes were within the 

expected variance. These findings 

mirror the conclusions of PHMSA’s 

earlier, 2016 analysis of the MFF reports 

submitted in the then-preceding 5 years 

(2011–2015).35 Because MFF report data 

reviewed in 2018 and 2016 confirmed 

PHMSA’s expectations regarding the 

frequency and characteristics of 

mechanical joint failure without 

yielding new statistically significant 

causal or predictive insights, PHMSA 

has determined that additional 

information collection via a dedicated 

MFF report form is unnecessary. 

PHMSA further notes improvements 

in fitting design, operator joining 

practices, and Federal safety 

requirements since the introduction of 

the MFF reporting requirement have 

improved the safety of mechanical 

fittings on newer installations. 

PHMSA’s 2018 analysis of MFF report 

data reached a similar conclusion, 

noting that many operator DIMPs are 

sensitive to the risk of MFF following 

the introduction of the MFF reporting 

requirement. However, PHMSA’s 2018 

analysis notes that the number of 

operators submitting MFF reports has 

stayed approximately the same for the 

last several years—suggesting that any 

action-forcing benefit hypothesized has 

been realized and that the benefits from 

continuing a dedicated MFF reporting 

requirement may be negligible. 

The modifications to other reports 

adopted in this final rule will help 

PHMSA ensure continued availability of 

information needed to provide effective 

regulatory oversight of MFFs. Leaks 

from mechanical joints are already 

aggregated within the broader categories 

on the existing Gas Distribution Annual 

Report form. The revised Gas 

Distribution Annual Report form 

requires reporting the number of leaks 

involving mechanical joint failures in 

addition to the existing, aggregated 

categories. This change is expected to 

provide sufficient information to track 

the safety performance of mechanical 

joints over time, among operators, or 

across the industry. These data are 

expected to provide operators, PHMSA, 

and State inspectors sufficient 

information to identify if action is 

needed under DIMP or other elements of 

operator programs for compliance with 

part 192 requirements. 

PHMSA is also revising the Gas 

Distribution Annual Report form to 

identify the number of leaks involving 

a mechanical joint failure as a separate 

line item from the count of leaks by 

cause. However, to address the potential 

confusion raised by commenters, 

PHMSA will revise the proposed part C 

of the Gas Distribution Annual Report 

form to clarify that operators should 

report the number of hazardous leaks 

‘‘involving’’ a mechanical joint failure, 

rather than ‘‘caused’’ by a mechanical 

joint failure. This aligns with the 

language in the current MFF report 

requirement and is clearer. PHMSA will 

further clarify in the form instructions 

that the count of leaks involving a 

mechanical joint failure is separate and 

in addition to the leaks by cause. 

Operators should continue to report all 

leaks by cause in the table in part C of 

the Gas Distribution Annual Report 

form as they have been doing 

previously, while the new count at the 

end of part C consists of a count of 

hazardous leaks involving the failure of 

a mechanical joint regardless of whether 

the leak was caused by equipment 

failure, incorrect operation/installation, 

or other causes. Likewise, on the Gas 

Distribution Incident Report form, 

operators should continue to report 

incidents involving a failure of a 

mechanical joint that was caused by 

improper installation under the 

‘‘incorrect operation’’ cause under 

section G7 of the Gas Distribution 

Incident Report form. The revised Gas 

Distribution Incident Report form will 

not require operators to submit design 

and manufacturing information about 

incidents involving mechanical joints 

that were caused by incorrect operation 

rather than material, weld, or equipment 

failure. 

PHMSA appreciates the concerns 

raised by commenters and members of 

the GPAC about reducing the data 

available to PHMSA and other 

stakeholders through changes in 

reporting requirements proposed in the 

NPRM and adopted in this final rule. 

PHMSA agrees that access to quality 

safety-related information is critical to 

implementation of an effective 

regulatory and enforcement program. 

However, these safety programs benefit 

from the flexibility both to create 

targeted information collection activities 

to address safety issues and to remove 

those information collection activities 

that are no longer necessary or have not 

proven useful. Here, PHMSA has 

determined that its original purpose for 

introducing a dedicated MFF reporting 

requirement has been satisfied. 

Although PHMSA could posit new 

justifications (e.g., use by environmental 

regulators and utility commissions in 

calibrating regulatory oversight of 

service line couplings) for this 

dedicated reporting requirement, it 

declines to do so in this rulemaking. 

Nevertheless, PHMSA submits that 

Federal and State regulators’ oversight 

activities may continue to benefit from 

nearly a decade of historical, granular 

data obtained from MFF reports,36 in 

addition to the operator-specific MFF 

data that PHMSA will collect in the Gas 


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37 49 FR 18960. 

38This analysis is based on the CPI for All Urban 

Consumers (CPI–U) from the Bureau of Labor 

Statistics, accessible at https://data.bls.gov/cgi-bin/ 

cpicalc.pl. 

39 85 FR 79130 (Dec. 9, 2020) (updating FRA’s 

monetary threshold for railroad incident reporting 

requirements by way of annual notices published 

on FRA’s website). 

Distribution Annual and Incident 

Report forms modified by this final rule. 

Replacing the full MFF report with a 

count of MFFs on the Gas Distribution 

Annual Report results in a reduction in 

reporting burden for each event but 

without a significant loss of useful 

information to operators and PHMSA. 

Although the revised requirements 

eliminate the detailed information on 

each mechanical fitting failure, this 

information has not yielded meaningful 

new causal or predictive insights 

regarding leaks involving mechanical 

joints. On the other hand, the general 

count of leaks involving a mechanical 

joint failure as required in the revised 

Gas Distribution Annual Report is not 

burdensome to compile yet provides 

information on the relative safety 

performance of mechanical joints in 

general. This information remains 

valuable to PHMSA and State agencies 

for safety performance monitoring and 

for prioritizing inspections. PHMSA has 

determined that incident reporting 

requirements via a revised Gas 

Distribution Incident Report form and 

the revision to the Gas Distribution 

Annual Report form to include a count 

of hazardous leaks involving a 

mechanical joint failure is sufficient to 

identify the total number of hazardous 

leaks involving mechanical joint failures 

and identify trends over time and 

among States or operators. 

Nor does this change absolve 

operators of other safety requirements 

that apply when leaks at MFFs are 

discovered. PHMSA requires that gas 

pipeline operators have procedures for 

investigating failures under § 192.617 to 

determine the causes of the failure and 

minimize the possibility of a recurrence. 

PHMSA also requires operators repair 

hazardous leaks promptly under 

§ 192.703. These requirements apply 

regardless of whether the failure results 

in a reportable leak or incident. Finally, 

operators are required to consider leak 

history under the continuing 

surveillance requirements at § 192.613 

and under their DIMP (§ 192.1007(b), 

(d), and (e)). PHMSA accordingly finds 

that the PSR change adopted in this 

final rule eliminates an unnecessary 

reporting burden without an adverse 

impact on safety. 

Many of the comments received 

pertained to related topics on the Gas 

Distribution Incident and Annual 

Report forms and are not directly related 

to the reporting of mechanical joint 

failures. PHMSA will consider these 

comments during periodic updates and 

renewals of these information 

collections pursuant to the Paperwork 

Reduction Act. PHMSA does not have 

authority over voluntary information 

collection organized by other, nongovernmental entities and therefore the 

comment related to data collected by the 

AGA through the PPDC is outside the 

scope of the NPRM. However, PHMSA 

will consider raising with other 

members of the PPDC whether its 

reporting protocols for MFFs should be 

modified. 

D. Monetary Threshold for Incident 

Reporting (Section 191.3, New 

Appendix A to Part 191) 

1. PHMSA’s Proposal 

On May 3, 1984, PHMSA’s 

predecessor agency, the Research and 

Special Programs Administration, added 

a definition for an ‘‘incident’’ at 

§ 191.3.37 The definition provides 

criteria that requires operators to report 

specific events to PHMSA. The 1984 

definition of an incident consists of a 

release of gas that, among other things, 

results in estimated property damage of 

$50,000 or more. That monetary 

threshold includes losses to the operator 

and third parties but excludes the cost 

of any lost gas. Today, over 30 years 

later, operators must still notify the 

National Response Center (§ 191.5) and 

submit an incident report to PHMSA 

(§§ 191.9 and 191.15) for any release 

that results in estimated property 

damage to the operator or third parties 

of $50,000 or more. 

Multiple comments submitted in 

response to the DOT Notification of 

Regulatory Review addressed the 

$50,000 monetary damage threshold for 

reporting gas pipeline incidents. The 

Associations, GPTC, and GPA 

Midstream submitted comments 

recommending an increase in the 

monetary damage threshold for 

reporting gas pipeline incidents. Based 

on the average annual Consumer Price 

Index (CPI) from the Bureau of Labor 

Statistics of the U.S. Department of 

Labor, $50,000 in 1984 is $122,000 in 

2019 dollars.38 The current damage 

threshold requires incidents that would 

not have been reported in 1984 to be 

reported to PHMSA due to inflation in 

property, equipment, and repair costs. 

PHMSA proposed in the NPRM to 

raise the reporting threshold for 

incidents that result in property damage 

to $122,000, consistent with inflation 

since 1984. The property damage 

criterion will continue to include losses 

to the operator and others but exclude 

the cost of lost gas. PHMSA did not 

propose any changes to the other criteria 

in the § 191.3 definition of an incident. 

The NPRM stated that PHMSA intended 

to base any finalized version of this 

provision on the price level at the time 

of publication of a final rule. PHMSA 

also requested comment on whether the 

level of safety information needed from 

property damage-only incident 

reporting should be updated to align 

with inflation, and the extent to which 

retaining a de facto annually-decreasing 

threshold after inflation would provide 

beneficial information on contributing 

risk factors and incident trends. 

The NPRM also stated that PHMSA 

intends to update the monetary damage 

threshold on a regular basis in the 

future, potentially biennially. Future 

updates would be based on the same 

formula used for this adjustment: 

Where Tn is the revised damage 

threshold, Tp is the previous damage 

threshold, CPIn is the average CPI–U for 

the preceding calendar year, and CPIp is 

the average CPI–U used for the previous 

damage threshold. PHMSA could 

subsequently update the monetary 

damage threshold in accordance with 

this formula either through notice and 

comment rulemaking, a direct final rule, 

notice on the PHMSA public website, or 

other means. This method is similar to 

the method that the Federal Railroad 

Administration (FRA) implemented to 

update the criteria for reporting 

accidents/incidents at 49 CFR 225.19 

and appendix B to part 225.39

2. Summary of Public Comments 

Several commenters (including AGA 

et al., AmeriGas, the Arkansas 

Independent Producers and Royalty 

Owners (AIPRO), GPA Midstream, 

NPGA, Paiute, the GPTC and SPP) 

expressed support for PHMSA’s 

proposal to update the threshold for 

property damage in the definition of an 

incident to account for inflation. AGA, 

API, APGA, GPA Midstream, and 

INGAA reiterated their support for this 

proposal in supplemental comments 

submitted after the GPAC meeting. AGA 

et al. also supported revising the initial 

property damage threshold to reflect 

inflation at the time of final rule 

publication. AGA et al. stated that the 

cost of repairing or remediating incident 

damage in today’s environment is far 

greater than it was in 1984, and that 

even with the inflation adjustment, 

more minor events will still be reported 


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as an incident than would have been in 

1984. They asserted that this results in 

a distorted view of pipeline safety 

performance, since reportable incidents 

are often used as a performance metric 

for the natural gas industry. AGA et al. 

also stated that the increase in the 

reporting threshold will reduce the 

number of calls made to the National 

Response Center (NRC) for minor events 

that are easily remediated by the 

operator, and reduce the potential of 

having to report minor incidents that 

unnecessarily tie up resources of both 

the producer and PHMSA. 

FreedomWorks stated that adjusting the 

threshold for inflation is simply good 

housekeeping, adding that it should 

have been indexed to inflation when the 

threshold was originally established. 

This commenter stated their support for 

including this amendment in the 

proposed rule while noting that 

eventually eliminating the property 

damage criterion entirely would be 

ideal. Paiute and Southwest also 

supported the proposed change, noting 

that it would directly reduce the 

regulatory burden on them. Southwest 

further stated that they analyzed the 

details of the § 191.3 reports their 

company has made since 2010 where 

the only reporting criteria met was 

exceeding the $50,000 estimated 

property damage threshold and 

determined that only 9 percent of this 

subset of reported incidents would have 

met the revised proposed estimated 

property damage threshold of $122,000. 

TC Energy supported changing the 

incident definition to adjust the amount 

of monetary damage to align with 

inflation, and recommended a monetary 

damage threshold of $250,000, which 

they stated would accurately reflect 

repair costs for minor incidents. They 

stated that while the proposed threshold 

of $122,000 may take inflation into 

account, it will continue to result in 

several minor incidents being 

considered reportable due to the cost to 

respond based on labor, repair 

materials, and permitting. 

AGA et al. also supported updating 

the reporting threshold every 2 years to 

account for inflation, noting that 

periodic updates will provide certainty 

and avoid a repeat of the current 

situation where the current threshold 

does not account for over 3 decades of 

inflation. AGA et al. further supported 

implementing the biennial periodic 

updates via notice on the PHMSA 

website, stating that conducting biennial 

rulemakings to update the threshold 

seems unnecessarily burdensome for 

both PHMSA and stakeholders. They 

asserted that the current NPRM provides 

adequate notice and opportunity for 

comment on the proposed method to 

update the threshold periodically. They 

recommended that PHMSA revise 

§ 191.3 to clarify in the final rule the 

agency’s intended process for 

periodically updating the threshold. 

FreedomWorks recommended that 

PHMSA mandate a biennial update in 

the final rule. NPGA agreed with 

periodic modifications to the threshold, 

suggesting annual updates by means of 

a direct final rule published in the 

Federal Register. TC Energy, on the 

other hand, commented that biennial 

updates may prove burdensome, but 

supported incorporating whatever 

process PHMSA settles on for 

periodically updating the property 

damage threshold into the PSR. 

NAPSR suggested that PHMSA use 

the language ‘‘$50,000 or more as 

measured in 1984 dollars adjusted for 

inflation,’’ which would prevent the 

need to amend the PSR every year. They 

further suggested that PHMSA could 

announce the reporting threshold 

annually as is done with random drug 

testing rates, and civil penalties as 

found in 49 CFR 190, or by simply 

updating the incident report forms and 

instructions every year to reflect the 

recalculated reporting threshold. 

However, NAPSR also noted that the 

historical data collected by PHMSA 

using the prior criteria may result in 

skewed statistical incident results until 

several years of collection using the new 

formula, if adopted, is completed. 

NAPSR suggested that PHMSA first 

study the effects of changing the 

reportable criteria dollar amount and 

how they plan to reconcile any new data 

to provide meaningful information to 

the State programs and to the public. 

They also suggested that PHMSA 

consider how such data will relate to 

any required cost benefit analysis 

related to future pipeline safety 

regulations and whether any change to 

the dollar reporting criteria could affect 

the ability to promulgate effective 

regulations. 

Two commenters opposed changing 

the monetary threshold for incident 

reporting from $50,000 to $122,000. PST 

commented that PHMSA should be 

seeking to obtain more information 

about pipeline failures, not less. They 

asserted that PHMSA can only make 

regulatory decisions about design, 

manufacture or operating conditions 

that they know cause problems, and if 

they are told about fewer problems, they 

will not be able to determine whether 

they need to regulate certain safety 

issues. They further stated that if 

PHMSA is determined to re-define the 

term ‘‘incident,’’ it should undertake a 

comprehensive look at that definition, 

and not merely adjust the property 

damage criteria. They asserted that 

making incremental, sequential 

adjustments to the definition will 

disrupt and frustrate trend analyses, 

recommending that PHMSA identify, 

analyze, and consider all potential 

changes at once. They stated that 

reducing the number of incidents 

reported provides PHMSA less safety 

data, and saves operators very little 

money, while potentially misleading the 

public about the improvement in the 

number of reported incidents that occur 

in future years. PST further stated that 

PHMSA and the industry have all 

committed to pursuing a goal of zero 

incidents, and that PHMSA should not 

facilitate that goal by defining reportable 

incidents away. 

Theresa Pugh Consulting also 

opposed changing the monetary 

threshold for incident reporting. They 

stated that since 1984, the United States 

has become more densely populated 

such that natural gas pipelines and 

compressor stations could cause ‘‘partial 

damage to $50,000 in property that 

merits reporting to PHMSA.’’ While the 

commenter recognized there is a 

regulatory cost associated with this 

reporting, they asserted that it is the cost 

of doing business in a critical, necessary 

and dangerous business. The 

commenter asserted that property 

damage is still important if it is valued 

at greater than $50,000, noting that a 

damaged or lost $50,000 structure or 

capital equipment can be a major 

business investment even if it might 

seem less significant to a multimilliondollar pipeline project. 

One commenter recommended that 

while PHMSA is addressing the 

monetary damage limits in the 

definition of incident in § 191.3, it 

should also address the issue of how 

operators determine what constitutes a 

‘‘significant event’’ under item (iii) of 

the definition. The commenter stated 

that the failure of an operator to 

evaluate their system and define what is 

significant for their personnel leads to 

confusion and can cause delayed 

reporting, or even non-reporting, of 

incidents. 

The GPAC voted 11–2 in favor of 

PHMSA’s proposed amendment to the 

definition of an incident provided that 

PHMSA adopted an updated property 

damage criterion commensurate with 

the CPI at the time of final rule 

publication. The GPAC further 

recommended regular administrative 

updates using procedures like those 

proposed by the Federal Railroad 


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40As noted earlier, FRA finalized that proposal in 

December 2020. 

41https://www.phmsa.dot.gov/data-andstatistics/pipeline/national-pipeline-performancemeasures. 

42https://www.phmsa.dot.gov/data-andstatistics/pipeline/pipeline-incident-20-year-trends. 

Administration for part 225.40 Two 

members voted against the proposed 

amendments. 

3. PHMSA Response 

PHMSA agrees with comments 

supporting the adoption of an up-to-date 

property damage threshold in the final 

rule. The most recent complete calendar 

year is 2019. Therefore, the property 

damage criterion following the effective 

date of this final rule is set to $122,000 

consistent with CPI inflation between 

1984 and 2019. 

PHMSA also agrees that it is 

appropriate to perform updates in the 

future to account for inflation via a preestablished formula. To this end, 

PHMSA has incorporated the formula 

described in the preamble to the NPRM 

into a new appendix A to part 191. In 

the future, annual updates to the 

property damage criterion will be 

calculated based on this formula and 

posted to PHMSA’s website such that 

they will become effective July 1 of each 

year. The revision to the incident 

definition has no direct safety impact, 

better reflects the intent of the original 

property damage criterion, and only 

impacts reports of releases without 

significant safety or environmental 

consequences. Whether a release is 

classified as an incident has no effect on 

an operator’s regulatory obligation to 

repair hazardous leaks promptly 

(§ 192.703) and establish and follow 

procedures for responding to gas 

pipeline emergencies (§ 192.615) and 

investigating failures (§ 192.617). None 

of the repair criteria in part 192 depend 

on whether a leak or defect results in a 

reportable incident. 

PHMSA disagrees that changing the 

property damage criterion adversely 

affects trend analysis. In fact, a static 

property damage threshold decreases in 

real value time. PHMSA already 

addresses this issue when performing 

and presenting trend analysis of 

‘‘significant’’ incidents. PHMSA’s 

analyses of ‘‘serious incidents’’ include 

only incidents that result in reported 

deaths or injuries and are not affected 

by inflation because the ‘‘serious’’ 

threshold criteria do not include a 

property damage criterion. In contrast, 

PHMSA uses the term ‘‘significant 

incidents’’ to mean those with (1) 

reported deaths or injuries, or (2) 

$50,000 or more in total costs, measured 

in 1984 dollars. Additional information 

on these trend analyses is available on 

PHMSA’s web pages for National 

Pipeline Performance Measures 41 and 

Pipeline Incidents, 20 Year Trends.42

PHMSA currently uses inflation data 

published by the Bureau of Economic 

Analysis, the Government Printing 

Office, and the Energy Information 

Administration in calculating inflation 

adjustments for ‘‘significant incidents.’’ 

Following the effective date of the final 

rule, PHMSA will no longer employ 

those tools in adjusting the ‘‘significant 

incident’’ property damage threshold for 

inflation, but will instead use the 

Bureau of Labor Statistics CPI. 

Regarding comments from Theresa 

Pugh Consulting, PHMSA did not 

propose to create a new incident 

definition criterion for releases or 

pressure drops that disrupt supply to 

downstream consumers and others 

indirectly impacted by gas pipeline 

failures, therefore these suggestions are 

outside the scope of the NPRM. PHMSA 

acknowledges that property damage 

exceeding $50,000 can have a 

significant effect on third parties 

affected by the release and notes that it 

understands that some States have 

lower incident reporting thresholds to 

address just that concern. 

PHMSA disagrees with comments 

from TC Energy and FreedomWorks 

suggesting more radical changes to the 

property damage criterion. PHMSA does 

not believe that an arbitrarily higher 

damage threshold or eliminating the 

reporting entirely would be appropriate. 

Even if repair costs may have risen 

faster than inflation, TC Energy has not 

provided a convincing rationale for why 

$250,000 represents current repair costs 

for incidents across the industry. In 

addition, while a simple inflation 

adjustment is consistent with how 

PHMSA currently uses incident data, a 

significant change to the incident 

definition beyond a simple inflation 

adjustment would affect the ability of 

PHMSA and other data users to track 

incident trends as alluded to by other 

commenters. 

PHMSA is deferring for a future 

rulemaking consideration of the other 

amendments to the incident reporting 

criteria at § 191.3 that were suggested by 

comments received in the rulemaking 

docket. Further evaluation of those 

proposals would be helpful. 

Corrosion Control 

Virtually all hazardous liquid and 

most natural gas transmission pipelines 

in service today are made of steel. 

Metallic pipelines, when not protected, 

react with the surrounding environment 

and can deteriorate over time due to 

corrosion. Under certain conditions, 

unprotected metal can corrode, causing 

gas leaks that can threaten public safety. 

To guard against this, subpart I of part 

192 of the PSR requires, with some 

exceptions, cathodic protection and 

protective coatings to mitigate corrosion 

risks on pipelines. Cathodic protection 

works like a battery, running an 

electrical current across the buried 

pipeline using devices called rectifiers. 

The electrical current prevents the metal 

surface of the pipe from reacting with its 

environment. If the current is sufficient, 

cathodic protection can control 

corrosion threats. 

Subpart I of part 192 establishes 

requirements for corrosion control and 

remediation for natural gas pipelines. 

This subpart also establishes inspection 

intervals for testing and repairing 

systems as necessary to bring them into 

compliance. PHMSA proposed two 

amendments related to corrosion 

control: first, to clarify that cathodic 

protection rectifiers can be inspected 

remotely and second, to revise the 

requirements for assessing atmospheric 

corrosion on distribution service 

pipelines. 

E. External Corrosion Control: 

Monitoring (Section 192.465) 

1. PHMSA’s Proposal 

In the NPRM, PHMSA proposed to 

revise § 192.465(b), ‘‘External corrosion 

control: Monitoring,’’ to clarify that 

operators may monitor rectifier stations 

remotely. Rectifiers are devices that 

direct an electrical current on a pipeline 

to prevent external corrosion. Section 

192.465(b) requires inspection of 

rectifiers on gas pipelines at intervals 

not exceeding two and a half months, to 

ensure that they are working correctly. 

Advances in technology make it 

possible to monitor the proper operation 

of these electrical systems remotely, but 

it is not clear in the regulations if this 

is permissible. PHMSA proposed to 

revise § 192.465(b) to clarify that 

operators may inspect rectifier stations 

directly onsite or by way of remote 

monitoring technologies. The NPRM 

also clarified that, at a minimum, such 

an inspection consists of recording 

amperage and voltage measurements. 

PHMSA also proposed to require 

operators physically inspect rectifier 

stations that are being monitored 

remotely whenever they conduct a 

cathodic protection test pursuant to 

§ 192.465(a). For pipelines, other than 

separately protected service lines or 

separately protected short sections of 

transmission lines or mains, 


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43See, e.g., PHMSA Pipeline Enforcement 

Guidance: Part 192 Corrosion Enforcement 

Guidance (2015), available at https://

www.phmsa.dot.gov/sites/phmsa.dot.gov/files/ 

docs/Corrosion_Enforcement_Guidance_Part192_

12_7_2015.pdf (citing PHMSA Interpretation #PI– 

ZZ–080 (Aug. 19, 1991)). 

44 1986 is the earliest year available in the 

‘‘Pipeline Incident Flagged Files’’ dataset. https://

www.phmsa.dot.gov/data-and-statistics/pipeline/ 

pipeline-incident-flagged-files. 

§ 192.465(a) requires physical 

inspection once each calendar year. 

2. Summary of Public Comments 

Several commenters (including AGA 

et al. and TC Energy) supported 

PHMSA’s proposal allowing remote 

inspection of impressed current 

cathodic protection sources. PST stated 

that they do not oppose allowing the 

remote inspection of rectifier stations 

provided the proposed addition of a 

requirement that remotely inspected 

rectifier stations be physically inspected 

once a year is retained. AGA et al. and 

TC Energy recommended that PHMSA 

clarify that operators must physically 

inspect remotely inspected rectifiers at 

the cathodic protection test frequency 

required in § 192.465(a) and that the 

rectifier inspection need not necessarily 

occur at the exact same time as the 

cathodic protection testing. They 

indicated that the currently-proposed 

wording of § 192.465(b)(2) could be 

interpreted to require a redundant 

physical inspection of the same rectifier 

every time each of the pipeline 

segments influenced by that rectifier is 

tested, or even multiple times per 

segment if the testing occurs over 

multiple days. AGA et al. suggested 

specific revisions to the proposed 

§ 192.465(b)(2). 

Four commenters (NPGA, AmeriGas, 

SPP, and a private citizen) suggested 

changes to the proposed physical 

inspection interval. They commented 

that if rectifier inspection can be done 

remotely and it is performed at intervals 

no greater than two and a half months, 

PHMSA should consider allowing an 

operator to extend the physical 

inspection interval for rectifiers on 

distribution lines beyond once per year, 

provided the results of remote 

inspections are properly documented. 

The commenters claimed that 

documentation of the results will 

indicate if, or when, physical inspection 

of the rectifiers is needed, but did not 

provide a specific timeline. 

One private citizen expressed 

opposition to the proposed amendment. 

The commenter requested more frequent 

inspection of rectifiers, and suggested 

that the proposed change does not align 

with industry policies. The commenter 

noted that corrosion is one of the main 

causes of pipeline failures and 

suggested that a physical inspection is 

already required within the rectifier 

checks required in § 192.465(b). Based 

on this interpretation of § 192.465(b), 

the commenter argued that PHMSA was 

effectively extending the required 

interval to perform physical inspections 

of rectifiers and other devices from six 

times a calendar year to once per 

calendar year. 

The GPAC voted unanimously in 

favor of PHMSA’s proposal with respect 

to external corrosion monitoring 

provided that PHMSA clarify that the 

physical inspection of a remotely 

inspected rectifier is expected to occur 

annually rather than exactly when 

cathodic protection surveys occur. 

3. PHMSA Response 

PHMSA has adopted the proposed 

amendments to § 192.465 with minor 

revisions to the physical inspection 

requirements. The amendments clarify 

that remote inspection is permitted by 

the PSR. PHMSA’s corrosion 

enforcement guidance contains 

numerous interpretations clarifying that 

§ 192.465(b) does not specify a 

particular technology, but rather permits 

any technology that provides reliable 

data, including ‘‘electronic data 

collection and the subsequent broadcast 

of this data to operators.’’ 43 PHMSA 

expects that the data obtained from 

remote inspection of rectifiers will not 

adversely affect the quality and quantity 

of information available on their 

function, and does not expect the PSR 

amendments to § 192.465(b) to have an 

adverse impact on safety. 

PHMSA agrees with comments to 

specify that the physical inspection 

should occur annually rather than 

exactly when a cathodic protection 

survey is performed under § 192.456(a). 

This change better reflects PHMSA’s 

intent for operators to perform an 

annual physical inspection. This change 

has no impact on the intended 

frequency of inspections, but provides 

more flexibility to operators and avoids 

situations where inspections would 

have been required more frequently 

than intended. 

PHMSA disagrees with the comment 

that § 192.465(b) already requires 

physical inspection during each rectifier 

inspection and that PHMSA’s proposal 

would lengthen the intervals for 

physical inspection. While some 

operators may conduct a physical 

inspection with each of their rectifier 

checks, § 192.465(b) currently does not 

require them to do so. 

PHMSA does not adopt a longer 

physical inspection interval for 

distribution pipelines as suggested in 

comments from LPG distribution system 

operators and suppliers. These 

comments did not present an alternative 

timeline that would have been 

appropriate for distribution operators, 

and PHMSA believes that operators 

have ample opportunities to perform an 

annual physical inspection during other 

inspection activities. 

F. Atmospheric Corrosion: Monitoring 

(Sections 192.481, 192.491, 192.1007, 

192.1015) 

1. PHMSA’s Proposal 

PHMSA proposed to revise § 192.481 

to establish a separate atmospheric 

corrosion inspection interval for gas 

distribution service pipelines. 

Currently, all onshore gas pipelines that 

are exposed to the atmosphere must be 

inspected for atmospheric corrosion 

once every 3 years, with intervals not to 

exceed 39 months. This includes 

facilities that are installed aboveground, 

in underground vaults, or inside 

buildings. PHMSA proposed a 

maximum inspection interval for service 

lines of once every 5 calendar years, 

with intervals not to exceed 63 months, 

unless atmospheric corrosion was 

identified on the last inspection. If an 

operator identifies atmospheric 

corrosion on a service line during an 

inspection, then the required interval 

for the subsequent inspection would 

remain once every 3 years, with 

intervals not to exceed 39 months. If no 

atmospheric corrosion is identified on a 

subsequent inspection, then operators 

would be permitted to return to using 

the 5-year inspection interval. PHMSA 

also proposed to revise §§ 192.1007(b) 

and 192.1015(b)(2) to clarify that 

consideration of corrosion risks under 

DIMP explicitly includes atmospheric 

corrosion. PHMSA did not propose any 

changes to the inspection requirement 

for other facilities, including 

distribution mains. PHMSA’s proposed 

change was informed by its 

understanding that there has not been a 

history of incidents caused by 

atmospheric corrosion on distribution 

service lines since at least 1986 44 and 

therefore does not anticipate a decrease 

in safety from these PSR revisions. 

2. Summary of Public Comments 

Several commenters (including 

Oleksa and Associates, FreedomWorks, 

and AGA et al.) expressed support for 

establishing a separate atmospheric 

corrosion inspection interval for gas 

distribution service pipelines. 

FreedomWorks stated that the changes 

would reduce the costs for both 


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45Additional information on these historical 

examples is available in the rulemaking docket and 

the docket for the South Dakota State waiver 

(PHMSA–2019–0052). 

operators and inspectors. AGA et al. 

supported revising § 192.481 to align the 

inspections intervals for atmospheric 

corrosion with those of leak surveys 

required by § 192.723. AGA et al. 

asserted that the NPRM’s proposed PSR 

revisions would reduce regulatory 

burdens while enhancing pipeline 

safety in that the resources saved from 

such alignment could be reallocated to 

other pipeline safety activities and asset 

improvement projects. 

Some commenters (including SPP, 

NPGA, and AmeriGas) supported the 

extension of the inspection interval to 5 

years for service lines, but 

recommended that if documented action 

were taken to remediate the coating as 

specified in § 192.479, then the 

inspection interval should remain at 5 

years. The commenters stated that there 

is not a need to drop down to 3 years 

if remediation occurs. 

AGA et al. and GPTC agreed that the 

existing 3-year interval when corrosion 

is identified is not necessary to manage 

atmospheric corrosion risks if the 

service line is replaced or remediated, 

especially considering existing DIMP 

requirements, and the proposed 

requirement to consider atmospheric 

corrosion risks under DIMP included in 

the NPRM. They agreed with PHMSA’s 

assessment that there is expectation for 

operators of service lines in highcorrosion environments to consider 

atmospheric corrosion in their 

evaluation of risks under DIMP and 

conduct atmospheric corrosion 

inspections more frequently than the 

minimum requirements in § 192.481. 

AGA et al., therefore, recommended a 

prescriptive remediation requirement in 

lieu of a shortened inspection cycle. 

They stated that by remediating through 

recoating or replacement, operators can 

continue to keep all service pipelines on 

a 5-year inspection cycle. They 

provided specific regulatory text 

revisions in their comment. AGA et al. 

also requested that PHMSA remove the 

word ‘‘evaluate’’ from § 192.481(a). 

They noted that PHMSA did not 

provide justification for adding the 

requirement to evaluate under 

§ 192.481(a). INGAA, AGA, APGA, API, 

and GPA Midstream submitted 

supplemental comments after the GPAC 

meeting arguing that the 3-year 

inspection interval when corrosion has 

been identified would negate any cost 

savings from the proposed revisions to 

§ 192.481. 

Similarly, NAPSR commented that if 

atmospheric corrosion is found that 

corrosion should be remediated rather 

than be subject to a shorter inspection 

interval. NAPSR argued this would be 

more reliable from a safety perspective 

than establishing a shorter inspection 

interval. Alternatively, NAPSR 

recommended that PHMSA consider 

revising both §§ 192.481 and 192.723 to 

require a shorter, perhaps 3- or 4-year, 

residential leak survey requirement and 

require that operators complete their 

atmospheric corrosion survey at the 

same interval. NAPSR argued this 

would provide for greater safety 

regarding leak surveys, while making it 

more practical to combine compliance 

intervals for two operation and 

maintenance categories. NAPSR further 

commented that any change to the 

atmospheric corrosion control 

inspection interval should be 

accompanied by a change to the record 

keeping requirements in § 192.491. 

NAPSR recommended that operators be 

required to retain records for the 

previous two inspection cycles. 

A2LA recommended that PHMSA 

implement a risk-based approach to 

determine permissible inspection 

intervals rather than the 3-year or 5-year 

intervals described in the NPRM. A2LA 

stated the risk-based approach can then 

account for considerations such as the 

age of the pipeline, climate, geologic 

conditions, use, and maintenance 

history. They agreed with the proposed 

rulemaking that the maximum 

inspection interval for service lines 

should be 5 calendar years, with 

intervals not to exceed 63 months. 

Two gas distribution operators and an 

industry organization commented that it 

is unclear whether, if corrosion was 

identified, a 3-year inspection interval 

would be required for the entirety of the 

distribution system or just at the 

location or address where the corrosion 

exists. They recommended that PHMSA 

consider clarifying that the 3-year 

inspection interval applies to ‘‘only 

such areas as corrosion was identified.’’ 

PST commented that they are unable 

to support changes in monitoring 

frequency because corrosion continues 

to cause many incidents. They 

commented that corrosion-related 

incidents indicate that more 

prescriptive corrosion monitoring 

regulations might be warranted. 

However, they noted that they do not 

strongly oppose this change, as PHMSA 

indicates it has no recent records of 

incidents caused by atmospheric 

corrosion on distribution service lines. 

The GPAC voted twice on this 

amendment. First, the GPAC voted 7–5 

in favor of the proposed rule with 

respect to atmospheric corrosion, 

provided that PHMSA amend 

§ 192.491(c) to clarify that an operator 

must retain records of the last two 

atmospheric corrosion inspections to 

use the 5-year inspection interval. This 

vote recommended retaining the 

proposed requirement to inspect lines 

where corrosion was identified on the 

last inspection within 3-years, and did 

not incorporate the remediation 

alternative to a 3-year inspection that 

was suggested by some commenters. 

Second, the GPAC voted 10–2 in favor 

of the proposed rule with respect to 

atmospheric corrosion if PHMSA 

adopted a 5-year cycle rather than a 3- 

year cycle when atmospheric corrosion 

is found, provided that the operator has 

evaluated and remediated the facility 

and there is no evidence of systemic 

atmospheric corrosion due to the 

environment or similar factors. 

3. PHMSA Response 

After considering the public 

comments and the GPAC 

recommendations, the final rule adopts 

the amendment with respect to 

atmospheric corrosion inspection of 

service lines as proposed with minor 

clarification to recordkeeping 

requirements in § 192.491(c). Alignment 

of atmospheric corrosion inspection 

intervals with those for leakage surveys 

in § 192.723 will allow greater 

scheduling flexibility for operators and 

decreased costs arising from less 

frequent atmospheric inspections. As 

stated in the NPRM, PHSMA is unaware 

of any pipeline incidents arising from 

atmospheric corrosion on a service line. 

In addition, PHMSA has approved State 

waivers in the past that have allowed 

certain operators to perform both 

atmospheric corrosion and leakage 

surveys on a 4-year interval outside of 

business districts and subject to certain 

conditions. The most recent of these 

was for North Western Energy in South 

Dakota, issued March 2, 2019.45 PHMSA 

has not observed an increase in leaks or 

incidents from this and other State 

waivers. For these reasons, PHMSA 

finds that a longer atmospheric 

corrosion inspection interval is 

supported in areas with low observed 

atmospheric corrosion risk. 

The final rule applies the new 5-year 

inspection interval to distribution 

service lines. Although PHMSA 

acknowledges that operators have 

reported atmospheric corrosion 

incidents on distribution mains, 

PHMSA understands the design and 

operational characteristics of service 

lines make them less susceptible to 

atmospheric corrosion induced failure. 

Compared to distribution mains, service 

lines tend to have smaller diameters, 


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2224 Federal Register / Vol. 86, No. 6 / Monday, January 11, 2021 / Rules and Regulations 

have lower flow rates, and are 

constructed with thicker walls relative 

to the outside diameter of the pipeline. 

They can therefore endure more 

atmospheric corrosion induced metal 

loss before operating stresses would 

compromise pipeline integrity. In 

addition, aboveground distribution 

facilities other than service lines (i.e. 

mains) must be inspected more 

frequently under part 192, providing 

ample opportunity for operators to note 

and correct any corrosion issues. 

PHMSA recognizes that not all 

environments face the same 

atmospheric corrosion risks. However, 

based on inspection results and field 

experience, PHMSA determined that 

establishing a maximum inspection 

interval is necessary to ensure that 

distribution facilities are adequately 

inspected for atmospheric corrosion 

sufficiently frequently so that it can be 

remediated before it leads to a failure. 

An open-ended reference to DIMP, as 

suggested in the Associations’ comment 

on the DOT Notification of Regulatory 

Reform, would not provide this 

safeguard. The proposed maximum 

interval of 5 years was supported in 

public comments and will allow 

operators of gas distribution pipelines 

with low atmospheric corrosion risks to 

realize cost savings from less-frequent 

inspections and the ability to schedule 

corrosion inspections and leakage 

surveys under § 192.723(b)(2) 

concurrently. PHMSA was not 

persuaded that there is significant 

benefit to allowing atmospheric 

corrosion inspection intervals longer 

than the maximum leakage survey 

interval as described by some 

commenters. Inspecting the 

aboveground portion of a service line is 

not a significant additional burden 

when operators are already walking the 

service line to perform leakage surveys. 

The proposed revisions to 

§§ 192.1007(b) and 192.1015(b)(2) to 

evaluate atmospheric corrosion risks 

under DIMP and the shorter inspection 

interval for pipelines with observed 

corrosion will also ensure that operators 

of service pipelines with atmospheric 

corrosion threats take appropriate action 

to maintain the integrity of those 

pipelines. 

Those revisions clarify that 

consideration of corrosion under DIMP 

must include consideration of 

atmospheric corrosion risks. When 

evaluating atmospheric corrosion risks 

under DIMP, PHMSA expects operators 

to evaluate environmental risk factors 

and the operating history of the service 

lines. Environmental risk factors for 

atmospheric corrosion include 

proximity to coasts, atmospheric 

moisture, salinity, and corrosive 

pollution. Relevant operational risks 

include a history of leaks, incidents, and 

evidence of atmospheric corrosion on 

previous inspections. PHMSA expects 

operators of distribution lines with 

higher risks due to atmospheric 

corrosion threats to take mitigative 

action, such as more frequent inspection 

or maintenance activities, as part of 

their DIMPs and accurately and 

completely document such actions. 

The final rule does not adopt 

proposals (by commenters and GPAC) 

for remediation as an alternative to the 

NPRM’s approach of shorter inspection 

intervals following observation of 

atmospheric corrosion. While 

commenters suggested a ‘‘prescriptive’’ 

remediation requirement, the regulatory 

language suggested in comments from 

the Associations neither defines what 

constitutes an adequate repair of 

atmospheric corrosion (other than 

replacement), nor how their proposal 

differs from existing part 192 

requirements for remediation and repair 

of atmospheric corrosion and other 

conditions that could reduce the 

pipeline’s integrity. Based on the GPAC 

discussion, remediation as discussed by 

commenters consists of removing 

corrosion with a wire brush and 

repainting the facility pursuant to the 

existing § 192.479 requirements. These 

actions are already required by existing 

§ 192.481, through reference to 

§ 192.479, which requires an operator to 

clean and suitably coat pipelines 

exposed to the atmosphere, and 

§ 192.703 requires operators to replace, 

repair, or remove pipeline segments that 

become unsafe and promptly repair all 

hazardous leaks. In addition, finding 

atmospheric corrosion is an indication 

that a corrosive environment may exist. 

Inspection of such service lines within 

3 years protects against this risk. Any 

remediation alternative requires careful 

consideration of what constitutes 

adequate remediation because corrosion 

has already been identified on the 

pipeline. 

PHMSA also declines to NAPSR’s 

alternative approach of aligning 

atmospheric corrosion inspection and 

leaky survey frequencies by revising 

§ 192.723 to require more frequent leak 

surveys. PHMSA is unaware of record 

evidence supporting a need for 

shortened leak survey intervals, even as 

PHMSA finds that the absence of 

incidents resulting from atmospheric 

corrosion support extending the 

inspection interval as provided by this 

final rule. In addition, more frequent 

leak inspection surveys under § 192.723 

will likely entail significant operator 

costs without record evidence of a 

corresponding safety benefit. 

PHMSA is not persuaded by 

arguments raised by GPAC members 

and comments submitted after the 

GPAC meeting that reverting to a 3-year 

inspection interval for a distribution 

service line after atmospheric corrosion 

has been observed makes the 

amendment technically impracticable or 

economically infeasible. A 3-year 

inspection interval is the current 

requirement that has been in place for 

decades. Based on cost estimates 

provided by industry comments, 

PHMSA determined in the RIA that 

significant cost savings for the NPRM’s 

proposed revisions to atmospheric 

corrosion monitoring requirements stem 

from reduced inspection frequency in 

the absence of observed atmospheric 

corrosion. If, however, the operator 

observes atmospheric corrosion and 

remediates it as required in part 192, 

then an operator should rarely observe 

atmospheric corrosion during the 3-year 

inspection following remediation, after 

which they may return to a 5-year 

inspection interval and continue to 

enjoy cost savings into the future. An 

operator can easily keep atmospheric 

corrosion and leakage surveys in sync 

by performing the next leakage survey 

within 3 years and then continuing 

every 5 years on subsequent inspections 

provided no corrosion is identified in 

the future. If the operator is unable to 

use the 5-year inspection interval 

effectively because they repeatedly 

observe atmospheric corrosion, then the 

rule is working as intended to protect 

the public in areas with high rates of 

atmospheric corrosion. 

Finally, consistent with the 

recommendations of the GPAC and 

comments received in the rulemaking 

docket, the final rule revises the 

corrosion control recordkeeping 

requirements in § 192.491(c) to clarify 

that an operator must retain records of 

the two most recent atmospheric 

corrosion inspections in order to use the 

5-year inspection interval for facility 

distribution service line. This change 

ensures that operators can provide 

adequate documentation that corrosion 

was not identified on a service line that 

is being inspected on a 5-year interval. 

ASTM and ASME Standards 

Incorporated by Reference 

G. Plastic Pipe (Sections 192.7, 192.121, 

192.281, 192.285, Appendix B to Part 

192) 

1. PHMSA’s Proposal 

The NPRM proposed to update 

§§ 192.7, 192.121 and appendix B to 

part 192 to incorporate by reference the 


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46ASTM International, ASTM D2513–18a— 

‘‘Standard Specification for Polyethylene (PE) Gas 

Pressure Pipe, Tubing, and Fittings’’ (Aug. 1, 2018). 

47 Docket Number PHMSA–2019–0200. https://

www.regulations.gov/docket?D=PHMSA-2019-0200. 

48 83 FR 58694. 

2018a edition of the ASTM International 

(ASTM, formerly the American Society 

for Testing and Materials) document, 

‘‘Standard Specification for 

Polyethylene (PE) Gas Pressure Pipe, 

Tubing, and Fittings’’ (ASTM D2513– 

18a).46 ASTM D2513 specifies the 

design requirements of Polyethylene 

(PE) pipe and fittings. These 

improvements include more specific 

testing requirements for measuring 

resistance to ultraviolet exposure and 

clarifying the applicability of the 

document to all PE fuel gas piping. 

Consistent with the updated ASTM 

standard, PHMSA also proposed to raise 

the diameter limit for using a design 

factor of 0.4 on PE pipe from 12 inches 

to 24 inches and add corresponding 

entries for those sizes to the PE 

minimum wall thickness table at 

§ 192.121(c)(2)(iv). PPI, representing 

manufacturers of plastic pipe and 

components, and a citizen commenter 

submitted comments in response to the 

DOT Notification of Regulatory Review 

addressing this issue. PHMSA reviewed 

ASTM D2513–18a and determined that 

PE pipe with diameters up to 24 inches 

that are manufactured in accordance 

with the standard and the design and 

construction requirements in part 192 

are acceptable for use in gas pipeline 

systems. PHMSA also determined that 

the other safety improvements since the 

2012ae1 edition merit incorporation by 

reference in the PSR as their 

incorporation would not have an 

adverse impact on safety, while 

improving regulatory clarity and 

alignment with consensus industry 

practices. 

Currently, PHMSA incorporates by 

reference ASTM D2513–12ae1 into item 

I, appendix B to part 192. While Table 

2 (Outside Diameters and Tolerances for 

Plastic Pipe) of ASTM D2513–12ae1 

includes outside diameter specifications 

for pipe sizes up to 24-inch nominal 

diameter, Table 4 (Wall Thicknesses and 

Tolerances for Plastic Pipe) only 

includes wall thickness specifications 

for pipe sizes up to 12-inch nominal 

diameter. Because ASTM D2513 is the 

listed specification for PE plastic pipe in 

appendix B to part 192, and 

§ 192.121(c)(2)(iv) mirrored the 

published wall thicknesses and 

tolerances in Table 4 of ASTM D2513– 

12ae, part 192 does not currently allow 

use of a 0.4 design factor for PE pipe 

diameters above 12 inches. Now that the 

ASTM D2513–18a includes in its Table 

4 wall thicknesses for diameters through 

24 inches, the corresponding table in 

§ 192.121(c)(2)(iv) can be updated as 

well. 

In the NPRM, PHMSA also proposed 

to modify requirements for joining 

procedures in §§ 192.281 and 192.285 to 

allow operators additional flexibility 

when developing such procedures and 

to improve safety. Specifically, PHMSA 

proposed to incorporate by reference the 

2019 edition of ASTM F2620, ‘‘Standard 

Practice for Heat Fusion Joining of 

Polyethylene Pipe and Fittings’’ and 

revise §§ 192.281 and 192.285 to clarify 

that procedures that are demonstrated to 

provide an equivalent or superior level 

of safety as ASTM F2620 are acceptable. 

This amendment addresses concerns 

raised by a petition for reconsideration 

submitted by AGA on August 23, 

2019 47 in response to the final rule 

entitled ‘‘Pipeline Safety: Plastic Pipe 

Rule’’ issued on November 20, 2018.48

In the Plastic Pipe Rule, PHMSA 

amended §§ 192.281 and 192.285 to 

require that PE heat-fusion joining 

procedures meet the requirements of the 

2012 edition of ASTM F2620. Heat 

fusion is a common method for joining 

plastic pipe and components. In heat 

fusion, a worker prepares the surfaces of 

the pipe or fittings being joined, heats 

the surfaces using a heating element, 

and then presses the pipe or fittings 

together with sufficient force for the 

molten material to mix and fuse as it 

cools. ASTM F2620 describes 

procedures for making socket fusion, 

butt fusion, and saddle fusion joints. 

The document contains requirements 

for the selection, preparation, and 

maintenance of joining equipment; 

preparing surfaces for joining; specified 

heating temperatures and times; joining 

forces; and cooling procedures. The 

standard also includes considerations 

for joining in cold weather and criteria 

for evaluating the quality of fusion 

joints. 

AGA raised concerns that §§ 192.281 

and 192.285 could be interpreted to 

require operators to requalify safe 

procedures that had been qualified in 

the past in accordance with § 192.283. 

AGA commented that many operators 

use heat fusion procedures published by 

PPI, such as PPI TR–33 and PPI TR–41. 

While PHMSA noted in the preamble of 

the Plastic Pipe Rule that PHMSA 

would find a joining method acceptable 

if ‘‘an operator can demonstrate the 

differences are sound and provide 

equivalent or better safety compared to 

ASTM F2620,’’ AGA raised concerns 

that the regulatory text itself does not 

necessarily provide this flexibility, and 

suggested PHMSA explicitly allow the 

use of other qualified procedures, such 

as PPI TR–33 and PPI TR–41. 

In the NPRM, PHMSA proposed to 

revise §§ 192.281 and 192.285 to 

achieve the flexibility sought in the 

Plastic Pipe Rule. Specifically, PHMSA 

proposed to revise § 192.281(c) to allow 

an alternative written procedure to 

ASTM F2620, provided that the 

operator can demonstrate that it 

provides an equivalent or superior level 

of safety and has been proven by test or 

experience to produce strong, gastight 

joints. In other words, the procedure 

produces joints that do not allow gas to 

leak, are at least as strong as the pipe 

being joined, are designed to handle the 

expected environment and the internal 

and external loads, and have been 

validated by formal testing in 

accordance with § 192.283 and 

applicable standards incorporated by 

reference or through several years of 

operational experience without leaks or 

failures. 

As described in the preamble to the 

Plastic Pipe Rule, for operators to 

demonstrate compliance, PHMSA 

expects operators to document the 

differences from ASTM F2620 and 

demonstrate how the alternate 

procedures provide an equivalent or 

superior level of safety. Similarly, 

PHMSA proposed to revise 

§ 192.285(b)(2)(i) to allow other written 

procedures that have been proven by 

test or experience to produce strong, 

gastight joints. If the operator’s 

procedures are found to be lacking in 

any way—such as changes to surface 

preparation, heating temperatures, 

fusion pressures, cooling times that lack 

a technical justification demonstrating 

an equivalent or superior level of 

safety—they would be unacceptable and 

would not comply with the PSR. 

PHMSA also proposed to incorporate 

by reference the 2019 edition of ASTM 

F2620. The updated edition of the 

standard clarifies the relationship 

between ASTM F2620 and the certain 

PPI documents referenced in AGA’s 

petition within a new Note 1 in section 

1.2. That Note identifies parameters and 

procedures in F2620 that were 

developed and validated using PPI TR– 

33 (butt fusion) PPI TR–41 (saddle 

fusion), thereby facilitating operators’ 

ability to referencing those PPI 

documents in developing their technical 

justification for use of an alternative 

procedures under § 192.285(b)(2)(i). In 

addition, the 2019 edition of ASTM 

F2620 includes several incremental 

improvements on the 2012 edition to 

safety and editorial clarity. These 

improvements include a new section 6.4 

that requires additional precautions 


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49National Transportation Safety Board, ‘‘Safety 

Through Reliable Fusion Joints,’’ SA–047 (June 

2015), https://www.ntsb.gov/safety/safety-alerts/ 

Documents/SA_047.pdf. 

50ASTM F2945–12a ‘‘Standard Specification for 

Polyamide 11 Gas Pressure Pipe, Tubing, and 

Fittings’’ (Nov. 27, 2012). 

51ASTM F2785–12, ‘‘Standard Specification for 

Polyamide 12 Gas Pressure Pipe, Tubing, and 

Fittings’’ (Aug. 1, 2012). 

during pipe cutting to prevent the 

introduction of contaminants that can 

weaken the joint and a new section X4.2 

that references the required test method 

for qualifying plastic pipe joiners in 

§ 192.285. Further, the 2019 edition 

revises the recommended precautions 

for preventing or removing 

contamination during pipe cutting in 

section X1.7.1 to clarify that any soap is 

a contaminant and that contamination 

may be introduced during cutting, and 

to require cleaning of the outer and 

inner surface of the pipe in addition to 

the end. These changes are expected to 

reduce potential issues caused by 

inadequate surface preparation, which 

has been a factor in past incidents.49

PHMSA also proposed to clarify 

§ 192.285 in response to questions 

PHMSA has received following 

publication of the Plastic Pipe Rule. 

First, PHMSA proposed to remove 

references to testing in relation to ASTM 

F2620 to clarify that only visual 

inspection in accordance with that 

standard is required. Several 

stakeholders asked what specific testing 

is required in ASTM F2620. While 

ASTM F2620 describes testing in a nonmandatory appendix of the standard, it 

does not require specific testing. 

Clarifying that operators must visually 

inspect specimen joints in accordance 

with ASTM F2620 avoids confusion 

about whether non-mandatory testing 

described in ASTM F2620 is required by 

§ 192.285(b)(2)(i). PHMSA also 

proposed to clarify that testing in 

accordance with § 192.283(a) is still 

required for PE heat fusion joints. The 

current text could be read to require 

only visual inspection in accordance 

with ASTM F2620 for PE heat fusion 

joints. The changes in this rule clarify 

PHMSA’s intent to require that such 

joints be tested in accordance with 

§ 192.283(a) and visually inspected in 

accordance with ASTM F2620. 

Additional testing in accordance with 

the appendix of ASTM F2620 is 

optional. 

In addition to the matters raised 

above, PHMSA proposed correcting 

amendments to address the following: 

Design Pressure for Plastic Pipe 

In § 192.121(a), PHMSA proposed the 

words ‘‘design formula’’ be replaced 

with the words ‘‘design pressure,’’ 

which is more accurate. 

Minimum Wall Thickness for 1′′ CTS 

Pipe 

In the minimum wall thickness tables 

for PE (§ 192.121(c)(2)(iv)), polyamide 

11 (PA–11) (§ 192.121(d)(2)(iv)), and 

polyamide 12 (PA–12) (§ 192.121(e)(4)) 

pipe, PHMSA proposed that the 

minimum wall thickness for standard 

dimension ratio (SDR) 11, 1′′ copper 

tubing size (CTS) pipe is corrected to be 

0.101 inches rather than 0.119 inches. 

The former, 0.101 inches, most closely 

corresponds to SDR 11, 1′′ CTS pipe in 

the standards incorporated by reference 

for the design of PE (ASTM D2513), PA– 

11 (ASTM F2945),50 and PA–12 (ASTM 

F2785) 51 plastic pipe and fittings. 

Qualifying Joining Procedures 

In § 192.283(a)(3), ‘‘no more than 25% 

elongation’’ is corrected to read ‘‘no less 

than 25% elongation.’’ PHMSA 

proposed to clarify that the test required 

by this section is a tensile test. Tensile 

testing is a measure of a material’s 

resistance to pulling forces. The 

revisions to § 192.283(a)(3) made in the 

Plastic Pipe Rule inadvertently removed 

the word ‘‘tensile,’’ though tensile 

strength was still alluded to implicitly 

because elongation is a measure of 

tensile strength. Reinserting the word 

tensile clarifies this relationship. 

Dates 

In § 192.121(c)(2) and (e), PHMSA 

proposed to clarify that PE pipe and 

PA–12 pipe respectively produced on or 

after January 22, 2019 may use a DF of 

0.40 rather than 0.32, subject to 

applicable restrictions in those 

paragraphs. 

Corrections to 192.7 

PHMSA proposed editorial 

amendments to § 192.7(a) to meet 

incorporation by reference requirements 

of the Office of the Federal Register and 

a revision to update the address for API. 

2. Summary of Public Comments 

ASTM D2513 and PE Pipe Diameter 

Several commenters provided their 

support, with no additional comments, 

for the proposed amendments in the 

NPRM. 

AIPRO submitted comments 

supporting the incorporation by 

reference of the 2018a edition of ASTM 

D2513 and conforming revisions to 

§ 192.121. Similarly, PPI stated their 

support to increase the allowable 

dimensions for PE pipe using a 0.40 

design factor up through 24 inches 

along with the corresponding minimum 

wall thicknesses in Table 1 to paragraph 

§ 192.121(c)(2)(iv). PPI stated that the 

revisions are consistent with 

dimensions provided in ASTM D2513– 

18a and enables the increased use of 

larger diameter PE in gas distribution, 

transmission, and gathering systems. 

PPI provided suggested regulatory text 

revisions for § 192.121(a) to permit an 

operator to allow an operator to operate 

a plastic pipe at a temperature up to 

180 °F, provided that the hydrostatic 

design basis (HDB) is established at that 

temperature. PPI noted that a survey of 

AGA members indicated that local 

distribution companies desire to use 

plastic pipe at higher operating 

temperatures providing them with more 

application options, and that use of 

these higher performance plastic 

materials results in increased long-term 

performance of the piping system and a 

safer gas system. 

GPA Midstream supported 

incorporating by reference updated 

editions of standards and believes that 

the latest editions should be adopted 

wherever possible. GPA Midstream 

stated that relying on obsolete or 

outdated editions of IBR standards 

creates unnecessary compliance 

burdens, discourages innovation, and 

adversely affects the standards 

development process. GPA Midstream 

noted that a significant number of the 

IBR standards have undergone multiple 

revisions without being updated to a 

newer or more recent edition. GPA 

Midstream requested that PHMSA place 

a renewed emphasis on the timeliness of 

the incorporation by reference process, 

particularly in cases where a prior 

edition of a standard is already 

incorporated by reference. In such cases, 

PHMSA should commit to adopting the 

latest edition of the standard or 

providing an explanation for not doing 

so within 1 year of publication. 

ASTM F2620 and Joining Requirements 

AGA et al. supported the changes 

proposed to §§ 192.281 and 192.285. 

They commented that the proposed 

revisions in the NPRM aligned with 

AGA’s petition for reconsideration of 

the Plastic Pipe Rule, and allow 

operators to use alternate procedures to 

join PE which are equivalent or more 

stringent than the heat fusion procedure 

detailed in the 2012 edition of ASTM 

F2620. 

PPI supported PHMSA’s proposed 

revision to §§ 192.281(c) and 192.285 

providing for alternative written heat 

fusion procedures that provide an 

equivalent or superior level of safety. 


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PPI also suggested incorporating PPI– 

TR–33, ‘‘Generic Butt Fusion Joining 

Procedure for Field Joining 

Polyethylene Pipe’’ and TR–41, 

‘‘Generic Saddle Fusion Joining 

Procedure for Polyethylene Gas Piping’’ 

into § 192.281(c) in addition to ASTM 

F2620. PPI explained that these 

additions would help clarify the 

language and account for proven 

procedures that have been successfully 

used in industry for many years. A2LA 

suggested that PHMSA also incorporate 

by reference ISO/IEC 17025, ‘‘General 

Requirements for the Competence of 

Testing and Calibration Laboratories’’ 

and require alternative written 

procedures be validated by laboratories 

certified in accordance with that 

document. A2LA commented that ISO/ 

IEC 17025 recommends that a testing 

laboratory uses consensus methods and 

has procedures for the selection of 

methods, and verify that a testing 

laboratory can properly perform 

methods by ensuring that it can achieve 

the required performance and maintain 

records of the verification. Regarding 

PHMSA expecting operators to 

document the differences from ASTM 

F2620 and demonstrate how the 

alternate procedures provide an 

equivalent or superior level of safety, 

A2LA recommended that the 

organizations conducting the 

inspections and testing be accredited, in 

accordance with the relevant ISO/IEC 

standards include requirements for 

impartiality. 

Southwest Gas Corporation 

(Southwest) raised concerns with the 

addition of the language ‘‘or superior’’ 

in the proposed language of both 

§§ 192.281 and 192.285. Southwest 

believes that this language ‘‘or superior’’ 

implies an increased performance 

standard not defined in either ASTM 

F2620 or part 192. Southwest requested 

that PHMSA consider removing the 

language ‘‘or superior’’ from the 

proposed revisions to both § 192.281(c) 

and § 192.285(b)(2)(i) and provided its 

preferred regulatory text. 

1-Inch CTS Pipe 

The Associations and NAPSR 

commented that operators commonly 

use 1-inch CTS pipe with a wall 

thickness of 0.099 inches, rather than 

0.101 inches in the proposed rule. Both 

wall thickness specifications are listed 

as options in Table 3 of ASTM D2513. 

NAPSR requested clarification of 

whether operators are required to use a 

design factor of 0.32 for PE pipe with a 

minimum wall thickness of 0.099-inch, 

and if thicker pipe is required to use a 

0.40 design factor. The Associations 

raised concerns about the impact to 

operators and manufacturers who have 

an inventory of 0.099-inch wall 

thickness PE pipe and suggested that 

PHMSA correct the proposed 

amendments to the minimum wall 

thickness table at § 192.121(c)(2)(iv) to 

reference 0.099-inch thick, 1-inch CTS 

pipe that is commonly in use. 

Qualifying Joining Procedures 

PPI supported correcting 

§ 192.283(a)(3), and allowing visual 

inspection in accordance with 

established written procedures in 

§ 192.285(b)(2)(i). 

GPAC Recommendation 

The GPAC voted unanimously in 

favor of PHMSA’s proposed amendment 

with respect to plastic pipe 

requirements, provided PHMSA correct 

the minimum wall thickness tables to 

specify a 0.099-inch wall thickness for 

1-inch CTS plastic pipe as 

recommended in the written comments 

from the Associations and NAPSR. 

3. PHMSA Response 

Based on the comments, the final rule 

adopts the plastic pipe amendments as 

proposed except for a change to the 

minimum wall thickness required to use 

plastic pipe with a size of 1-inch CTS 

with a design factor of 0.40 rather than 

0.32. The final rule incorporates the 

0.099-inch minimum wall thickness for 

1-inch CTS plastic pipe. 

PHMSA expects that the 

incorporation of updated industry 

standards pertaining to plastic pipe 

design will not adversely affect safety. 

The updated standards incorporated by 

reference in this final rule reflect the 

benefit of testing, lessons learned, and 

operational best practices from the 

increasingly widespread use of plastic 

pipe in gas transmission, distribution 

and gathering applications. 

Significantly, those updated industry 

standards reflect a greater comfort 

within industry regarding the safety of 

the use in those applications of largerdiameter plastic piping when subject to 

rigorous design standards. Based on its 

review of those standards and the 

administrative record in this 

rulemaking, PHMSA is similarly 

satisfied that their incorporation within 

the PSR will not have a detrimental 

impact on safety. PHMSA has provided 

a discussion of the changes in the 

updated editions of ASTM D2513 and 

ASTM F2620 in the summary of the 

proposed changes in section III.G.1 

above. 

ASTM D2513 and PE Pipe Diameter 

The final rule incorporates by 

reference the 2018a edition of ASTM 

D2513 and allows the use of a 0.40 

design factor for PE pipe produced on 

or after the effective date of the rule 

with a maximum diameter of 24 inches 

as proposed in the NPRM. PHMSA 

proposed no changes to the design 

pressure formula for PE pipe at 

§ 192.121(c)(2), and therefore declines to 

adopt the design factor change for PE 

piping suggested by PPI without the 

benefit of further technical evaluation 

and public comment. Similarly, PHMSA 

may consider allowing an operator to 

more directly establish a HDB rating at 

180 °F within the design pressure 

formula at § 192.121(a) in a future 

rulemaking after further review of the 

safety effects of such a change. PHMSA 

notes that § 192.121(a) allows an 

operator to interpolate the design 

pressure down from 180 °F, meaning 

they could use a pipe with an HDB 

rating at 180 °F but have to use a 

formula to determine the design 

pressure at a lower temperature listed in 

§ 192.121(a). PHMSA cautions users that 

not all PE compounds are rated at 

180 °F. 

Regarding the GPA Midstream 

comment concerning other documents 

that are currently incorporated into part 

192, PHMSA periodically issues rules 

updating the standards that are 

incorporated by reference, provided the 

2018 edition of ASTM D2513 has been 

evaluated and its incorporation 

determined consistent with PHMSA’s 

safety mission. More recent versions of 

this and other standards incorporated by 

reference, including those related to 

plastic pipe and components, that were 

not included in the NPRM may be 

considered for updates in other 

rulemaking proceedings. 

ASTM F2620 and Joining Requirements 

The final rule also adopts the 

clarifications to joining requirements as 

proposed with minor editorial revisions. 

PHMSA did not propose in the NPRM 

to incorporate by reference PPI TR–33, 

PPI TR–41, or ISO/IEC 17025, and 

therefore declines to incorporate them 

by reference without the benefit of 

additional public comment and 

technical evaluation. However, PHMSA 

understands that many of the 

procedures in TR–33 and TR–41 are 

similar or identical to the procedures 

specified in the 2019 edition of ASTM 

F2620. There are, however, still some 

differences such as heating 

temperatures. If an operator can 

demonstrate that their alternative 

procedure based on those documents 

provides an equivalent or superior level 

of safety compared with ASTM F2620, 

it would be acceptable under the 

amendments adopted in this final rule. 


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52ASME Boiler & Pressure Vessel Code, 2007 

edition (July 1, 2007). 

53Section 192.619(a)(2) requires a test pressure of 

at least 1.5 times the MAOP in a Class 3 or Class 

4 location for pipelines installed after November 11, 

1970. 

54 80 FR 12762 (Miscellaneous Rule). 

55 Docket No. PHMSA–2018–0046–0055. 

56MAWP is the design pressure in the ASME 

BPVC. The test factors in the ASME BPVC refer to 

the MAWP and are used to substantiate the design 

pressure of the vessel. Because the design pressure 

of a pressure vessel (the MAWP) must be equal to 

or greater than the MAOP of the pipeline, the PSR 

uses the more demanding MAOP metric. 

57PHMSA, ‘‘Pipeline Safety: Periodic Updates to 

Pipeline Safety Regulations,’’ 80 FR 12762 (June 14, 

2004). 

PHMSA disagrees with comments that 

including the phrase ‘‘or superior’’ 

imposes new requirements or adds 

uncertainty to the changes in §§ 192.281 

and 192.285. An operator need only 

demonstrate that their alternative 

procedure provides an equivalent level 

of safety; the addition of the term ‘‘or 

superior’’ exists to ensure that a 

procedure with requirements that may 

be more conservative than ASTM F2620 

is also acceptable. PHMSA has revised 

the regulatory language at § 192.281 

proposed in the NPRM to clarify that the 

operator need only demonstrate that the 

alternative procedure provides an 

equivalent or superior level of safety 

rather than demonstrate the alternative 

procedure is itself superior. 

1-Inch CTS Pipe 

PHMSA agrees with commenters that 

0.099 is an acceptable minimum wall 

thickness specification. While 0.101 

inches more closely corresponds to SDR 

11, both 0.099-inch and 0.101-inch wall 

thickness for 1-inch CTS pipe are 

technically SDR 11 specifications. In 

addition, the two specifications are 

within allowable tolerances of each 

other in the ASTM codes. Therefore, 

PHMSA does not have a safety concern 

with using a 0.40 design factor with 

0.099-inch wall thickness for 1-inch 

CTS plastic pipe and recognizes that it 

is in common use. 

H. Test Requirements for Pressure 

Vessels (Section 192.153) 

1. PHMSA’s Proposal 

Section 192.153 defines design 

requirements for prefabricated units and 

pressure vessels (hereafter referred to as 

pressure vessels) fabricated by welding. 

In particular, § 192.153(a) requires that 

operators establish the design pressure 

of components fabricated by welding 

whose strength cannot be determined to 

establish the design pressure of those 

components in accordance with section 

VIII, division 1 of the 2007 edition of 

the American Society of Mechanical 

Engineers (ASME) Boiler and Pressure 

Vessel Code (BPVC) which is 

incorporated by reference in § 192.7.52

Section 192.153(b) requires operators to 

design, construct, and test prefabricated 

units that use plate and longitudinal 

seams in accordance with either ASME 

BPVC section I, section VIII, division 1, 

or section VIII, division 2. In addition, 

§ 192.505(b) requires operators to 

pressure test compressor station, 

regulator station, and measuring stations 

to Class 3 location test requirements; for 

pipelines installed after November 11, 

1970, this represents a required test 

factor of at least 1.5 times the maximum 

allowable operating pressure (MAOP).53

On March 11, 2015, PHMSA 

published a final rule titled, ‘‘Pipeline 

Safety: Miscellaneous Changes to 

Pipeline Safety Regulations.’’ 54 The 

final rule created a new § 192.153(e), 

which clarified that pressure vessels 

subject to § 192.505(b) must be pressure 

tested to at least 1.5 times the MAOP of 

the pipeline. INGAA subsequently 

submitted a petition for reconsideration 

of the Miscellaneous Rule concerning 

the revision to § 192.153.55 The 

petitioner argued that PHMSA lacked 

technical justification for a 1.5 times 

MAOP test factor versus the 1.3 times 

the Maximum Allowable Working 

Pressure (MAWP) 56 test factor 

permitted in the ASME BPVC since the 

2001 edition and all subsequent editions 

of the standard. PHMSA had 

incorporated by reference the 2001 

edition of the ASME BPVC into part 192 

effective July 14, 2004, and the 

divergence between the required test 

factor in § 192.505(b) and section VIII, 

division 1 of ASME BPVC persisted 

until the Miscellaneous Rule became 

effective in 2015.57

PHMSA, meanwhile, had 

commissioned a report by the Oak Ridge 

National Laboratory (ORNL) on the 

safety equivalence between the 1992 

edition and the 2015 edition of the 

ASME BPVC. PHMSA understands that 

most pressure vessels in pipeline 

service are designed to ASME section 

VIII, division 1. For hydrostatic pressure 

tests, the 1992 edition of section VIII 

division 1 of the ASME BPVC provides 

for a hydrostatic pressure test factor of 

1.5 times MAWP, while the 2001 and all 

subsequent editions provide for a 

hydrostatic pressure test factor of 1.3 

times MAWP. The ORNL report found 

that these different editions of ASME 

BPVC section VIII, division 1 maintain 

safety through the design and 

fabrication of pressure vessels and 

hydrostatic pressure test, 

notwithstanding the difference in their 

hydrostatic pressure test factors of 1.3 

and 1.5. A copy of this report is 

available in the docket. 

In the NPRM, PHMSA proposed to 

revise the test requirements for the 

pressure vessels described in § 192.153. 

First, PHMSA proposed to revise 

§ 192.153(e) to require a pressure test 

factor of at least 1.3 times the MAOP for 

all pressure vessels installed since July 

14, 2004, provided the component has 

been tested in accordance with the 

ASME BPVC, as required by existing 

§ 192.153(b). Consistent with this 

change and the requirements in the 

ASME BPVC, PHMSA also proposed to 

exempt vessels installed after July 14, 

2004 from the strength testing 

requirement at §§ 192.505(b) and 

192.619(a)(2), which require a test factor 

of 1.5 times the MAOP. The test 

requirements for any pressure vessel 

with an MAOP established under the 

alternative MAOP requirements at 

§ 192.620 would remain unchanged. 

Second, PHMSA proposed a new 

§ 192.153(e)(2) that would exempt 

pressure vessels installed after July 14, 

2004 but before the effective date of the 

final rule from testing duration 

requirements at §§ 192.505(c), (d) and 

192.507. In contrast, pressure vessels 

installed on or after the effective date of 

the final rule would be subject to the 

long-standing pressure test duration 

requirements in subpart J. 

Third, PHMSA proposed 

§ 192.153(e)(3)(ii) to accept, subject to 

certain conditions, a pre-installation 

pressure test by the component 

manufacturer for pressure vessels 

installed after the effective date of the 

final rule but which have not previously 

been used in service. PHMSA proposed 

to accept those manufacturer pressure 

tests for the purposes of meeting the 

pressure testing and MAOP 

requirements in part 192 provided the 

operator conducts and documents an 

inspection certifying that the pressure 

vessel has not been damaged during 

transport and installation into the 

pipeline. If the inspection reveals that 

the pressure vessel has been damaged, 

the component would have to be 

remediated consistent with the ASME 

BPVC and part 192. A pressure vessel 

used prior to installation on a pipeline 

facility would have to be pressure tested 

again, consistent with the existing 

requirement at § 192.503(a). 

2. Summary of Public Comments 

AGA et al. generally supported the 

PSR amendments proposed in the 

NPRM but suggested substantive 

revisions to the requirements for 

accepting a manufacturer’s test of a 

pressure vessel. AGA et al. emphasized 

that the NPRM’s integration of ASME 


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BPVC requirements within its proposed 

PSR revisions leverages an 

internationally recognized standard of 

safety applied by several Federal 

regulators in their oversight activities. 

AGA et al. agreed with the NPRM’s 

approach of allowing operators to rely 

on a manufacturer’s pressure test 

accompanied by a visual inspection for 

newly-manufactured vessels, but 

requested PHMSA extend this 

authorization to relocations of existing 

components as well. 

AGA et al. noted that retesting ASME 

pressure vessels is not required by the 

ASME BPVC—but if an operator 

voluntarily undertook retesting, the 

ASME BPVC would require oversight by 

an authorized inspector. They 

concluded that retesting is therefore 

unnecessary and can lead to costs and 

operational disruptions because most 

operators do not have an authorized 

inspector on staff to oversee that 

retesting. They further commented that 

PHMSA should not require pressure 

vessels be pressure tested or inspected 

after installation or in situ, because in 

many cases it may be impracticable or 

unsafe to do so, especially for pressure 

vessels used in compressor stations. 

Finally, AGA et al. submitted comments 

opposing the NPRM’s proposed 

requirement that pressure vessels that 

have been used prior to being installed 

or relocated must be retested in place in 

accordance with Subpart J. They 

commented that retesting relocated 

vessels is not required by the ASME 

BPVC, and that inspection rather than 

pressure testing is the appropriate 

method to confirm the integrity of 

previously-used, relocated pressure 

vessels. 

PST opposed the proposed revisions 

to § 192.153, contending that PHMSA 

lacked sufficient technical justification 

for the proposed changes. PST argued 

that the ORNL report does not support 

PHMSA’s conclusion that safety would 

not be adversely affected by NPRM’s 

proposed reduction of the pressure test 

factor at § 192.153(e). PST asserted that 

the ORNL report did not conclude that 

components designed and fabricated 

under the 2015 edition of the ASME 

BPVC standards and tested to its lower 

(1.3 times MAWP) hydrostatic pressure 

test factor were necessarily as safe as 

those designed and fabricated to the 

higher hydrostatic pressure test factor 

(1.5 times MAWP) in the current text of 

§§ 192.153(e) and 192.505(b) (which 

were based on the test factors from the 

1998 and prior editions of the ASME 

BPVC). Rather, PST characterizes the 

hydrostatic pressure test factor as only 

‘‘one of [several] changes between [the] 

two editions’’ (1992 and 2015) 

compared by the ORNL report that 

would need to be evaluated to 

determine the safety impact of the 

NPRM’s revisions to § 192.153 

compared to the current PSR. PST also 

noted that the NPRM proposed applying 

the lower test factor in the 2015 ASME 

BPVC not only to components installed 

since the 2015 edition, but also 

components installed over the previous 

decade. Lastly, PST alleged that the 

NPRM’s proposed reduction in the test 

factor at § 192.153(e) violates the 

prohibition in 49 U.S.C. 60104(b) on 

retroactive application of design 

standards insofar as it purports to 

impose new design, installation, 

construction, and testing standards on 

previously-installed components. PST 

representatives reiterated their concerns 

in a conversation with PHMSA 

personnel after the GPAC meeting. 

The GPAC members voted 11–2 in 

favor of PHMSA’s proposed 

amendments with respect to test 

requirements for pressure vessels 

provided that PHMSA make the 

following changes: 

• Clarify in the NPRM’s 

§ 192.153(e)(3) that testing or inspection 

of a pressure vessel must take place after 

being placed on its supports at its 

installation location, but may occur 

prior to tie-in with station piping. 

• Clarify in the NPRM’s 

§ 192.153(e)(3) that relocated vessels 

must meet current design and 

construction requirements, be retested 

by the operator, and be inspected as 

described in the previous 

recommendation, to ensure there are no 

injurious defects. 

• Clarify in a new § 192.153(e)(4) that 

the retesting requirements applicable to 

pressure vessels do not apply to those 

pressure vessels that are used for 

temporary maintenance and repair 

activities, such as portable launcher or 

receivers, temporary odorant tanks, 

blow down equipment, and other 

similar equipment, but they must be 

inspected for safety and integrity prior 

to usage. 

Two GPAC members representing 

EDF and PST voted against the 

proposed amendments, expressing 

concern that the retroactivity 

prohibition at 49 U.S.C. 60104(b) 

prohibits PHMSA from applying a 

revised test factor to existing pressure 

vessels. During the meeting, PHMSA 

committed to the GPAC members that it 

would consider the application of 49 

U.S.C. 60104(b)’s prohibition to the 

changes proposed in the NPRM. 

INGAA, AGA, APGA, API, and GPA 

Midstream submitted joint 

supplemental comments after the GPAC 

Meeting supporting the GPAC 

recommendation and asserting that the 

proposed PSR amendments did not 

violate the 49 U.S.C. 60104(b) 

retroactivity prohibition. GPA 

Midstream separately submitted 

supplemental comments on that 

statutory retroactivity prohibition, 

explaining by reference to its legislative 

history, contemporaneous DOT 

interpretation of the relevant statutory 

language, and subsequent PHMSA 

interpretations of the same that 49 

U.S.C. 60104(b) prohibits only 

generically-applicable, retroactive 

standards imposing new compliance 

burdens on relevant pipelines. Here, in 

contrast, GPA Midstream contended the 

NPRM’s proposed revisions to 

§ 192.153(e) would relieve regulatory 

burdens and operators would have to 

take no action to be in full compliance 

with the amended § 192.153(e). 

3. PHMSA Response 

After considering the comments and 

the GPAC, PHMSA is adopting the 

proposed testing requirements for 

pressure vessels subject to certain 

amendments to the proposed rule with 

respect to test requirements for pressure 

vessels in § 192.153. The final rule 

adopts the revision to § 192.153(e)(1), 

which specifies that a prefabricated unit 

or pressure vessel that is installed after 

July 13, 2004 is not subject to the 

strength testing requirements at 

§§ 192.505(b) provided it has been 

tested in accordance with § 192.153(a) 

or (b) and with a test factor of at least 

1.3 times the intended MAOP, 

consistent with the hydrostatic pressure 

test factors in section VIII, division 1 of 

the ASME BPVC. The final rule also 

adds a footnote to table 1 to the 

§ 192.619(a)(2)(ii) MAOP requirements 

specifying that the factor for 

establishing the MAOP of a 

prefabricated unit or pressure vessel 

installed after July 14, 2004 is 1.3 times 

the MAOP. These changes ensure that 

an operator of a pressure vessel 

designed and hydrostatically tested in 

accordance with section VIII, division 1 

of the ASME BPVC since the 

incorporation by reference of the 2001 

edition of that document is compliant 

with the PSR. This allows an operator 

of a pressure vessel designed and 

hydrostatically tested in accordance 

with section VIII, division 1 of the 

ASME BPVC to operate it at an MAOP 

equal to its design pressure in most 

instances. PHMSA notes that if the 

pressure vessel is tested at factor lower 

than 1.3 times the MAWP under a 

pneumatic test or under section VIII 

division 2 of the ASME BPVC, the 

MAOP of the pipeline must be 


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58ORNL report at Table 9.2 (summarizing Section 

7.1.2.1 of the ORNL report on the safety 

contribution of hydrostatic test factors in different 

editions of ASME BPVC section VIII, division 1). 

established such that the test pressure is 

1.3 times the MAOP or greater. 

PHMSA understands the 

administrative record shows that this 

rulemaking’s revision of the pressure 

test factors at § 192.153 does not 

adversely affect the safety of pressure 

vessels designed, constructed, and 

tested in accordance with the 2001 and 

subsequent editions of the ASME BPVC, 

and designed, tested, constructed, and 

operated in accordance with the PSR. 

PHMSA therefore disagrees with PST’s 

assertion that the ORNL report does not 

contribute to the technical justification 

for that change. PST is correct to note 

that the ORNL report compares the 1992 

and 2015 editions of the ASME BPVC, 

and that other changes have taken place 

within the intervening editions of that 

standard (including the 2007 version 

currently incorporated by reference in 

the PSR). However, the ORNL report did 

not provide only a top-level statement of 

safety equivalence between the 1992 

and 2015 editions of the ASME BPVC; 

it also evaluated the contributions to 

that ultimate conclusion from each of 

the material elements of the 1992 and 

2015 editions ASME BPVC—including 

the effects of a reduction in the 

hydrostatic pressure test factor in ASME 

BPVC section VIII, division 1 from 1.5 

times the MAWP to 1.3 times the 

MAWP.58

The ORNL report predicated its toplevel conclusion of safety equivalence 

across the 1992 and 2015 editions of the 

BPVC section VIII, division 1, 

notwithstanding their different 

hydrostatic pressure test factors, in part 

on certain shared features. The most 

important of those features was that 

both editions’ hydrostatic pressure test 

factors yield hydrostatic pressure testing 

limits that ensure primary membrane 

stresses remain at or below plastic 

collapse stress limits for a pressure 

vessel, thereby reducing the risk of 

permanent distortion that would result 

in rejection of the pressure vessel at 

qualification. Other features shared 

between the 1992 and 2015 editions of 

BPVC section VIII, division 1 

contributing to ORNL’s safety 

equivalence finding include the 

following: Pressure testing by an 

authorized inspector at qualification 

verifying leak-tight integrity and the 

absence of gross deformations and 

anomalies indicative of design errors, 

material defects, or weld defects; 

pressure testing after fabrication 

verifying leak-tight integrity and the 

absence of gross deformations and 

anomalies indicative of design errors, 

material defects, or weld defects; and 

overpressure protection in the event of 

design basis heat exposure ensuring that 

maximum overpressure does not exceed 

1.3 MAWP. 

Each of the features listed above are 

also shared by the 2007 edition of the 

BPVC section VIII, section 1 

incorporated by reference in the PSR, 

notwithstanding any other differences 

between that edition and the 1992 and 

2015 editions evaluated in the ORNL 

report. Like the 1992 and 2015 editions, 

the various design requirements of the 

2007 edition of the ASME BPVC ensure 

that plastic stresses on a pressure vessel 

remain at or below plastic collapse 

stress limits to avoid permanent 

distortion. And like the 1992 and 2015 

editions, the 2007 edition backstops that 

design basis by qualified inspections to 

identify defects, post-fabrication 

pressure testing, and overpressure 

protection from a design basis heat 

exposure. Insofar as ORNL determined 

that these shared features contributed to 

its top-level conclusion of safety 

equivalence between the 1992 and 2015 

editions of the ASME BPVC, PHMSA 

understands them to support its 

conclusion in this final rule that that a 

lower (1.3) test factor will not adversely 

affect safety. 

PHMSA also submits that other 

elements of this final rule and the PSR’s 

comprehensive safety regime support 

the conclusion that lowering the test 

factor to 1.3 will not adversely affect 

safety. The applicability of the ASME 

BPVC in the PSR is limited to the 

design, testing and fabrication of 

pressure vessels. On the other hand, the 

PSR applies additional requirements 

throughout the lifecycle of a pressure 

vessel to ensure its continued integrity 

and safe operation. These requirements 

pertain to construction (subpart G), 

corrosion control (subpart I), testing 

(subpart J), operation (subpart L), 

maintenance (subpart M), and integrity 

management (subparts O and P) 

standards. Further, even with respect to 

design and installation standards that 

are the focus of ASME BPVC section 

VIII, division 1, PSR requirements 

provide additional assurance that 

stresses remain within safe limits. For 

example, § 192.201(a)(2)(i) requires 

overpressure protection devices be set to 

discharge at 1.1 times MAOP or at a 

pressure producing a hoop stress of 75 

percent of SMYS, whichever is lower— 

a requirement that is more conservative 

than analogous overpressure 

specifications in the ASME BPVC 

referenced in the ORNL report. 

Similarly, the ASME BPVC does not 

specify a minimum pressure test 

duration. In contrast, the PSR at subpart 

J requires a minimum pressure test 

durations of 8 hours (§ 192.505(c)), 4 

hours (§ 192.505(d)), 1 hour 

(§ 192.507(c)), or with a procedure 

sufficient to ensure discovery of all 

potentially hazardous leaks (§ 192.509). 

PHMSA further notes that exemption 

in this final rule from subpart J’s 

minimum pressure duration 

requirements are consistent with that 

conclusion. Prior to the changes 

adopted by this final rule, if an operator 

tested a pressure vessel to 1.3 times the 

MAOP consistent with section VIII, 

division 1 of the ASME BPVC rather 

than 1.5 times the MAOP, it would not 

comply with the PSR. An operator of 

such a vessel would need to reduce the 

MAOP of the pressure vessel such that 

the test pressure is 1.3 times the 

reduced MAOP, retest the vessel to 1.5 

times the MAOP, or replace the pressure 

vessel entirely. Likewise, a pressure 

vessel that was not tested for a duration 

specified in subpart J would need to be 

retested or replaced to remain in 

compliance. While retesting or replacing 

existing pressure vessels with a longer 

test duration or higher test factor could 

conceivably decrease the risk of an 

overpressure event causing a vessel 

failure on affected pipelines, PHMSA 

understands any such safety benefit 

could be speculative; incident reports 

indicate that pressure vessel failure has 

not been an issue on existing vessels inservice. 

This is further supported by the 

conclusions of the ORNL report with 

respect to the hydrostatic pressure 

testing limits described above. Further, 

any potential safety benefit from 

retesting or replacing pressure vessels 

already in service would need to be 

weighed against new safety risks that 

may emerge from such activity. And 

here PHMSA understands that re-testing 

and replacing in-service pressure 

vessels in pipeline facilities can entail 

its own safety hazards for operator 

personnel due to the mass, volume, and 

installation location of a typical 

pressure vessel compared with other 

types of pipeline facilities. Specifically, 

retesting or replacement of a pressure 

vessel requires purging of gas, 

disconnection from local piping, and 

likely removal from service and 

reinstallation. The pipeline facilities 

involved in such efforts may be very 

heavy and large, which increases 

hazards to operator personnel when the 

pressure vessel or other equipment is 

removed from its installation location 

and prepared for testing. The layout of 

compressor stations and other facilities 

may exacerbate these safety risks if there 


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is limited space to safely remove the 

pressure vessel or to maneuver lifting 

equipment. Each of these steps therefore 

introduces certain safety risks to 

operator personnel performing the work 

that PHMSA believes could outweigh 

any marginal, speculative safety benefit 

from re-testing and replacement of 

previously-installed pressure vessels. 

Lastly, as pointed out by multiple 

comments submitted on the NPRM, 

such re-testing and replacement of 

existing pipe could entail significant 

costs and operational disruptions that 

similarly militate in favor of the 

exemption in the final rule. 

Finally, PHMSA notes that the ASME 

BPVC does not specify minimum test 

duration requirements and part 192 

does not currently require postinstallation inspection of pressure 

vessels. The final rule’s PSR amendment 

clarifying that these requirements apply 

to new, replaced, relocated, or otherwise 

changed pressure vessels installed after 

the effective date of the final rule are 

expected to result in an increased level 

of safety. 

The final rule retains the proposed 

requirement to inspect pre-tested 

pressure vessels after being placed at the 

vessel’s installation location on its 

support structure in § 192.153(e)(3). 

However, consistent with the GPAC’s 

recommendations, the final rule clarifies 

that those inspections may occur prior 

to the pressure vessel tie-in on-site with 

the pipeline. PHMSA appreciates 

comments that testing vessels after they 

have been tied-in to station piping may 

be problematic depending on what or 

how it is being connected. But one of 

the risks of transporting pressure vessels 

and other large components is damage 

to the vessel including vessel outlets or 

its support structure while it is being 

moved within the facility itself. Many of 

the considerations raised by 

commenters that may complicate an 

inspection likewise raise the likelihood 

of potential damage during installation. 

For example, it would be unusual for a 

pressure vessel to be completely 

inaccessible in a typical compressor 

station configuration. In addition, since 

the § 192.153(e)(3) requirement applies 

to new, replaced, and relocated vessels, 

operators can ensure access during 

initial design, construction, and testing 

stages. The final rule also clarifies that 

operators must visually inspect the steel 

structure for damage including, at a 

minimum: Inlets, outlets, and lifting 

points. If damage is found, the pressure 

vessel must be non-destructively tested, 

re-pressure tested, or remediated in 

accordance with part 192 and ASME 

BPVC requirements. Test, inspection, 

and repair records must be kept for the 

operational life of the pressure vessel. 

These clarifying revisions to 

§ 192.153(e)(3) are designed to enhance 

safety, address the most significant 

concerns operators had with postinstallation inspection, and help ensure 

that damage incurred during movements 

within the facility are detected and 

remediated before the pressure vessel is 

put into service. 

PHMSA has also, consistent with the 

GPAC’s recommendations, clarified 

when testing and inspection under 

§ 192.153(e)(3) is required. The final 

rule clarifies that any pressure vessel 

that is temporarily or permanently 

installed in a pipeline facility must be 

inspected for damage as described above 

unless it has been pressure tested on its 

supports at its installation location. This 

includes pressure vessels that are 

pressure tested by the operator prior to 

installation when a post-installation 

pressure test is impracticable 

(§§ 192.505(d) and 192.507(d) in the 

final rule) and to pressure vessels where 

a manufacturer’s pressure test is used 

under § 192.153(e)(4) in the final rule. 

This change is consistent with 

pretesting authorizations under 

§ 192.507(d) in the final rule or 

§ 192.505(d) in existing part 192. It 

preserves the flexibility provided under 

those authorizations while the postinstallation inspection ensures that pretested components are not damaged 

after being tested by the manufacturer or 

the operator. 

The final rule also clarifies design, 

testing, and inspection requirements for 

pressure vessels that are relocated. 

Consistent with the GPAC’s 

recommendations, PHMSA is adding a 

new § 192.153(e)(6) that clarifies testing 

and inspection requirements for 

relocating an existing pressure vessel 

that has previously been used in service 

for permanent installation at a new 

location in a pipeline facility. An 

operator must have documentation that 

a relocated pressure vessel meets the 

design, construction, and testing 

requirements in place at the time of 

relocation and pressure test the pressure 

vessel. If a pre-installation pressure test 

is performed, the operator must inspect 

the pressure vessel after installation. 

The final rule does not adopt 

suggestions from commenters to accept 

a manufacturer’s initial pressure test for 

all relocated pressure vessels. PHMSA 

did not propose specific changes to the 

initial pressure testing requirements for 

relocated, existing pressure vessels. 

Rather, the requirements in the final 

rule for permanently relocated vessels 

complement existing part 192 

requirements for relocation of existing 

facilities with the addition of a new, 

general requirement in § 192.153(e)(3) to 

inspect pressure vessels that are not 

pressure tested in place. Using a 

manufacturer’s initial pressure test of an 

existing vessel raises safety concerns 

because the vessel could have been 

subject to corrosion, fatigue, external 

force damage, and other threats to the 

vessel’s integrity during its prior 

operational life or during transportation 

to the new facility. 

The GPAC’s discussion noted that 

operators commonly use such 

temporary devices for temporary 

launchers and receivers for integrity 

assessments and to reduce methane 

emissions during blowdowns (natural 

gas is predominately methane, a 

greenhouse gas). PHMSA did not intend 

to impair the use of pressure vessels that 

are relocated temporarily in order to 

perform maintenance, repair, or 

emergency-response-related tasks. To 

prevent this unintended result, PHMSA 

is incorporating a new § 192.153(e)(4)(ii) 

to allow the use of a manufacturer’s 

initial test of a pressure vessel 

temporarily installed in a pipeline 

facility to complete a testing, integrity 

assessment, repair, odorization, or 

emergency response-related task, 

including noise or pollution abatement. 

This revision addresses temporary and 

mobile pressure vessels that were 

discussed during the GPAC meeting, 

including portable launcher or 

receivers, temporary odorant tanks, 

mobile blow down equipment, and 

other similar equipment. This change 

reduces barriers to using temporary 

equipment to perform integrity 

assessment, maintenance, and pollution 

mitigation-related tasks (provided the 

equipment meets the MAOP, design, 

and inspection requirements in part 

192) and thereby is expected to result in 

greater efficiency for operators and 

safety and environmental benefits 

associated with encouraging inspections 

and repairs. These devices are subject to 

the new general requirement in 

§ 192.153(e)(3)(ii) to inspect pressure 

vessels that are not pressure tested in 

place after installation. Reducing 

regulatory burdens associated with 

performing maintenance, repair, 

emergency response, and pollution 

abatement tasks could result in safety 

and environmental benefits by making 

such actions more attractive to 

operators. 

To prevents misuse of this flexibility, 

a pressure vessel that is installed under 

§ 192.153(e)(4)(ii) must be removed 

when the task it is associated with is 

completed. Operators should define the 

procedures for employing temporary or 

mobile pressure vessels in their written 

procedure manuals. The final rule 


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59Available in docket No. PHMSA–2010–0026 

and the docket for this final rule. 60 Docket No. PHMSA–2014–0015. 

requires operators to submit a 

notification to PHMSA and applicable 

State pipeline safety authorities in 

accordance with § 192.18 if a temporary 

pressure vessel must be left in place for 

longer than 30 days; however, PHMSA 

does not reference this section in 

§ 192.18(c) and therefore the objection 

process and advance notice 

requirements do not apply. Likewise, 

§ 192.153(e)(5) clarifies that an operator 

is not required to pressure test a 

pressure vessel that is temporarily 

removed from a facility to perform a 

maintenance task and later re-installed 

at the same location. However, the reinstalled pressure vessel must be 

inspected in accordance with 

§ 192.153(e)(3)(ii) after it is re-installed. 

Generally, PHMSA does not consider 

small movements within the same 

location (e.g. within a compressor 

station) with no other operational 

changes as a relocation, however the 

operator should inspect the vessel for 

damage after installation. 

PHMSA has considered the comments 

by PST and members of the GPAC 

regarding the nonapplication 

requirement and finds the revisions to 

49 CFR 192.153(e) are not inconsistent 

with 49 U.S.C. 60104(b). Section 

60104(b) provides that a ‘‘design, 

installation, construction, initial 

inspection, or initial testing standard 

does not apply to a pipeline facility 

existing when the standard is adopted.’’ 

Under the revised § 192.153, operators 

of existing pressure vessels that meet 

minimum testing requirements will not 

be required to take any additional action 

to comply. While the revised section 

requires that components be pressure 

tested with a test factor of at least 1.3 

times MAOP, the current § 192.153(e) 

already required such testing at even 

higher pressures; in other words, a 

pressure vessel compliant with the 

existing § 192.153(e) would also be 

compliant with § 192.153(e) as revised 

by this final rule. The revisions to the 

PSR, therefore, cannot be said to impose 

a new standard on existing facilities in 

conflict with 49 U.S.C. 60104(b). 

In addition, as described in the 

preamble to the NPRM, the amendment 

to 49 CFR 192.153(e) responds to a 

petition for reconsideration of the 

Miscellaneous Rule.59 This final rule 

addresses the issues raised by the 

petition challenging the addition of 

§ 192.153(e) in the Miscellaneous Rule 

pursuant to the reconsideration 

procedures in part 190. The petition for 

reconsideration of the Miscellaneous 

Rule argues PHMSA’s modifications to 

§ 192.153 were not merely clarifications 

regarding the required testing standard 

for pressure vessels as PHMSA stated in 

the Miscellaneous Rule, but rather were 

departures from the testing standard for 

pressure vessels in the ASME BPVC 

standard that was incorporated in the 

regulations at the time. PHMSA 

maintains that the Miscellaneous Rule 

merely clarified the required testing 

standard for pressure vessels, but 

understands there was ambiguity in the 

regulations regarding the testing 

standard for pressure vessels before the 

Miscellaneous Rule was passed and that 

the Miscellaneous Rule codified a 

higher testing standard than many 

operators reasonably believed was 

compliant with the regulations at the 

time. Also, based on the discussion 

above, PHMSA was able to verify that 

the provisions in the final rule will not 

adversely affect safety. PHMSA is 

therefore allowing pressure vessels 

tested in accordance with the 1.3 test 

factor after 2004 to continue operating 

without retesting in order not to 

penalize conduct some operators 

believed complied with the PSR at the 

time. 

Lastly, because PHMSA understands 

the PSR revisions in this final rule 

obviate the need for its unpublished 

October 27, 2015 letter to INGAA 

announcing a stay of enforcement 

pertaining to certain pressure vessels in 

violation of §§ 192.153(e) and 

192.505(b), it withdraws that document 

as of the effective date of this final rule. 

This letter is also available in the docket 

for this final rule. 

I. Welding Process Requirement (Section 

192.229) 

1. PHMSA’s Proposal 

Section 192.229(b) currently bars 

welders from welding with a welding 

process if they have not engaged in 

welding with that same process within 

the previous six months. GPTC 

submitted a petition for rulemaking 

requesting PHMSA revise § 192.229(b) 

to allow welders to demonstrate they 

have engaged in welding with a welding 

process at least twice each calendar 

year, but at intervals not exceeding 71⁄2

months, provided the welds were tested 

and found acceptable in accordance 

with API Standard (Std) 1104.60 API Std 

1104 is the primary standard for 

welding steel piping and for testing 

welds on steel pipelines, and covers the 

requirements for welding and 

nondestructive testing of pipeline 

welds. API Std 1104 is used within part 

192 requirements for qualifying welders, 

welding procedures, and welding 

operators, and interpreting the results of 

non-destructive tests. 

GPTC also noted that the 6-month 

frequency requirement for the welding 

process requirement at § 192.229(b) is 

different than other requirements in 

§ 192.229(c)(1) and (d)(2) governing 

welder requalification frequency. Those 

welder requalification requirements 

demand requalification within the 

preceding 71⁄2 months, but at least twice 

each calendar year. GPTC pointed out 

that this discrepancy between welder 

process requirements and welder 

requalification requirements obliged 

operators either to maintain alternative 

recordkeeping procedures for the 

process requirement or perform welds to 

comply with both the process 

requirement and the requalification 

requirements on a 6-month interval. In 

other words, if a welder wishes to use 

the same weld to comply with both 

requirements, they are unable to benefit 

from the more flexible welder 

requalification requirements at 

§ 192.229(c)(1) and (d)(2). 

PHMSA proposed in the NPRM to 

revise § 192.229(b) to specify that 

welders or welding operators may not 

weld with a particular welding process 

unless they have engaged in welding 

with that process within the preceding 

71⁄2 months and the welds were tested 

and found acceptable in accordance 

with API Std 1104. This change would 

provide operators some flexibility in 

scheduling welding activities to 

maintain welder requalification. 

PHMSA agrees with GPTC that the 

proposed revision is more consistent 

with § 192.229(d)(2). This is potentially 

beneficial for welders who weld 

relatively infrequently. PHMSA does 

not anticipate a decrease in safety, as a 

71⁄2-month interval is already permitted 

for requalification under 

§ 192.229(d)(2)(i), and the change will 

only affect welders who are not welding 

throughout the year. 

2. Summary of Public Comments 

AmeriGas, AIPRO, FreedomWorks, 

NPGA, Oleksa and Associates, and SPP 

supported the proposed requalification 

scheduling for welders. Oleksa and 

Associates stated that there will be no 

negative impact on pipeline safety. 

FreedomWorks stated that the changes 

would allow welders, many of whom 

are self-employed freelancers, greater 

flexibility in their trade. AIPRO 

commented that the changes would 

establish regulatory expectations and 

create more scheduling opportunity for 

vendors to perform the welding tests 

and for companies to comply with the 

standard. The GPAC voted unanimously 


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61 ‘‘Pounds per square inch gauge’’ refers to 

internal pressure relative to outside atmospheric 

pressure. 

in favor of PHMSA’s proposed 

amendments regarding the welding 

process requirement. 

3. PHMSA Response 

Based on the comments and the GPAC 

recommendations, PHMSA has adopted 

this amendment as proposed. This 

change will streamline compliance and 

recordkeeping activities related to 

§ 192.229(b) and will not have a 

detrimental impact on safety. 

J. Pre-Test Applicability (Section 

192.507) 

1. PHMSA’s Proposal 

Section 192.505(d) permits operators 

to test fabricated units and short 

segments of pipe prior to installation on 

steel pipelines operated at a hoop stress 

of 30 percent or more of SMYS if a postinstallation test is not practicable. 

PHMSA proposed in the NPRM to add 

a new paragraph (d) to § 192.507 to 

extend this authorization to steel 

pipelines operated at a hoop stress less 

than 30 percent of SMYS and at or 

above 100 psig.61

The NPRM’s proposed revision is in 

response to a petition for rulemaking 

submitted by GPTC for PHMSA to 

relocate the pre-installation strength 

testing requirement at § 192.505(d) to 

the general test requirements in 

§ 192.503 to permit broader application 

of this authorization. GPTC argued this 

change would permit operators to use 

pre-tested pipe and fabricated units in 

applications outside of higher stress 

transmission pipelines. GPTC further 

asserted that as this provision is 

currently applicable only to higherstress pipelines operating at a hoop 

stress at or greater than 30 percent of 

SMYS, extending the broader pre-testing 

provision to lower-stress pipelines 

would not increase pipeline safety risks. 

Rather, GPTC predicted this proposed 

change will provide greater flexibility 

and efficiency for operators of lowerstress pipelines, especially during 

maintenance activities. 

Instead of adding pre-testing 

provisions to the general requirements 

at § 192.503 as suggested by the GPTC 

petition, PHMSA proposed in the NPRM 

to add § 192.507(d) to permit pre-testing 

on steel pipelines operating at a hoop 

stress less than 30 percent of SMYS and 

at or above 100 psig. The proposal did 

not extend pre-testing provisions to 

pipelines operating below 100 psig 

(§ 192.509), service lines (§ 192.511), or 

plastic pipelines (§ 192.513). Individual 

components, excluding short segments 

of pipe, may still be installed on those 

facilities with a pre-installation test 

pursuant to § 192.503(e). PHMSA 

requested comments on whether it is 

appropriate to extend pre-testing 

provisions to such facilities, and 

solicited proposed requirements that 

should apply if pre-testing provisions 

are extended to such facilities. 

2. Summary of Public Comments 

AmeriGas, NPGA, and SPP supported 

the proposed changes to § 192.507 to 

allow operators to extend the 

authorization for pre-testing fabricated 

assemblies to include steel pipelines 

that operate at a hoop stress less than 30 

percent of SMYS and at or above 100 

psig. Similarly, PST commented that 

they did not object to extending the pretesting provisions to lower stress 

pipelines as proposed in the NPRM. 

AGA et al., National Fuel, and Oleksa 

and Associates recommended that 

PHMSA consider extending the pretesting allowance to other pipelines that 

also pose less of a safety risk. 

Specifically, they recommended that 

PHMSA extend the allowance for pretested short segments of pipe and 

fabricated units to steel pipelines that 

operate at pressures less than 100 psig 

(§ 192.509), plastic pipelines 

(§ 192.511), and service lines (§ 192.513) 

to provide clarity and consistency 

within the regulations. These 

commenters suggested the addition of 

enabling regulatory text. Oleksa and 

Associates agreed with these 

commenters, stating that the rationale 

that applies to permitting pre-tested 

pipe on steel pipelines operating at a 

stress less than 30 percent of SMYS and 

at or above 100 psig applies in the same 

way to pipelines operating below 100 

psig, service lines, and plastic pipelines. 

They suggested that the simplest way to 

accomplish this is to modify the 

wording in § 192.503. 

Similarly, NAPSR opposed the 

proposed revision unless it is revised to 

allow the use of pre-tested pipe for main 

repairs under 100 psig. Specifically, 

NAPSR commented that it may be 

impracticable to pressure test Type B 

gathering lines and mains postinstallation. They commented that if 

pre-tested pipe is allowed for systems 

that operate above 100 psig and above 

30 percent SMYS, then pre-tested pipe 

should also be allowed for all pipe that 

operates below 100 psig and low stress 

pipe. NAPSR believes that most 

operators use pre-tested pipe for main 

and Type B gathering line repairs as a 

standard practice; that pipe is soap 

tested and visually inspected for leaks 

after installation. They stated that the 

proposed change in the NPRM could 

unnecessarily restrict operators from 

safely and quickly repairing damages, 

and that distribution operators could 

potentially experience prolonged 

outages (especially in cold weather) and 

increased repair times and cost if pretested pipe is not allowed. 

AGA et al. commented that in 2019, 

distribution system operators reported 

84,608 leaks caused by excavation 

damage on their Gas Distribution 

Annual Reports. Assuming each 

excavation damage related leak required 

a pressure test, and assuming a cost of 

$200 per post-installation pressure test, 

they stated that the cost would be nearly 

$17 million annually to pressure test 

pipe replaced due to excavation damage 

alone. National Fuel’s comment 

included a similar calculation and 

estimated $8.8 million in cost savings if 

pre-tested pipe is allowed for such 

repairs. These commenters asserted that 

the use of pre-tested pipe would 

significantly reduce these costs as 

operators could pre-test full joints or 

coils of pipe for use on multiple short 

segment replacements and repairs 

without compromising safety. 

National Fuel commented that 

extending pre-testing to distribution 

lines would allow the use of pre-tested 

pipe for short segment replacements for 

leak repairs, excavation damage repairs 

and replacement of visually 

questionable welds or plastic fusion 

joints. They noted that without this 

change operators are required to test 

short replacement segments in place, 

which is inefficient, time consuming, 

and often results in extended shutdown 

durations and inconvenience to 

customers. They further stated that 

based on current regulatory language, an 

excavation damage repair that involves 

replacement of two feet of plastic 

distribution main requires that the 

operator: (1) Fuse end caps on each end 

of the replacement segment, (2) pressure 

test the pipe in place for the required 

duration, (3) remove the end caps, (4) 

tie-in the replacement segment by 

electrofusion or coupling, and (5) purge, 

gas and soap test the joints. They stated 

that allowing the use of pre-tested pipe 

would significantly reduce the repair 

time and costs to complete the repair 

and would still result in a pipe segment 

that is both strength tested and leak 

tested to ensure an equal level of safety 

while limiting interruptions to 

customers. 

AGA et al. recommended that 

PHMSA remove the term ‘‘hydrostatic’’ 

from the test requirements for short 

segments of pipe and pre-fabricated 

units from § 192.507 because natural 

gas, inert gas, and air are also allowable 

test media for pipelines operating at a 


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62OMB, Circular A–119, ‘‘Federal Participation in 

the Development and Use of Voluntary Consensus 

Standards and in Conformity Assessment 

Activities’’ (Jan. 27, 2016). Circular A–119 and 

revisions thereto are available at https://

www.whitehouse.gov/omb/information-foragencies/circulars/. 63 79 FR 66278. 

hoop stress less than 30 percent of 

SMYS under § 192.503(c). 

The GPAC voted unanimously in 

favor of PHMSA’s proposed PSR 

amendments regarding the welding 

process requirement but recommended 

removing the word ‘‘hydrostatic’’ from 

the proposed § 192.507(d). 

3. PHMSA Response 

Based on the comments received and 

the recommendation of the GPAC, the 

final rule adopts the amendments 

related to pre-testing fabricated 

assemblies and short segments of pipe 

as proposed in the NPRM, except that 

PHMSA has removed the term 

‘‘hydrostatic’’ from the new 

§ 192.507(d). PHMSA agrees that 

removing the term ‘‘hydrostatic’’ is 

appropriate since other test media other 

than water are approved for use in that 

new section. 

The final rule does not extend the 

authorization in § 192.507 (as revised) 

for pre-tested segments of pipe and 

fabricated assemblies beyond steel pipe 

with an MAOP producing a hoop stress 

less than 30 percent of SMYS but at or 

above 100 psig. Operators must still 

perform leak tests after installing 

fabricated units and short segments of 

pipe installed on such pipelines. The 

remaining categories in subpart J 

(metallic pipe with an MAOP less than 

100 psig, plastic pipe, and service lines) 

generally represent distribution lines 

rather than transmission lines. It is not 

clear that there is adequate safety 

justification for extending the pretesting allowance to these categories of 

lines due to the proximity of such 

facilities to customers and the 

differences in design, construction, 

inspection, and testing requirements for 

such facilities compared with higherpressure transmission lines. For 

example, welds on higher-pressure 

metallic lines require inspection with 

non-destructive testing techniques 

under § 192.241, while plastic pipe 

joints and welds on lower-pressure 

metallic lines can be visually inspected 

instead. The leak tests required for 

lower-pressure lines in subpart J are, 

therefore, necessary to ensure the leaktight integrity of welds and joints on 

such lines. Commenters did not suggest 

alternative inspection requirements or 

other conditions for using pre-tested 

pipe and fabricated units on such 

pipelines. PHMSA therefore determined 

that additional analysis is necessary to 

consider the safety effects of extending 

the pre-testing allowance to such 

facilities, and what, if any, additional 

conditions may be necessary. The GPAC 

voted unanimously in favor of this 

recommended approach. PHMSA may 

consider this issue in future rulemaking. 

PHMSA notes that §§ 192.509, 

192.511, and 192.513 require only a leak 

test. NAPSR presented a scenario where, 

for a replacement repair, an operator 

installed pre-tested pipe and then 

performed a leak test after installation. 

The leak test described in this scenario 

meets the post-installation leak test 

requirement in § 192.509, provided that 

the operator’s test procedure ensures the 

discovery of all potentially hazardous 

leaks. 

IV. Availability of Standards 

Incorporated by Reference 

PHMSA currently incorporates by 

reference into 49 CFR parts 192, 193, 

and 195 all or parts of more than 80 

standards and specifications developed 

and published by standard development 

organizations (SDO). In general, SDOs 

update and revise their published 

standards every 2 to 5 years to reflect 

modern technology and best technical 

practices. 

The National Technology Transfer 

and Advancement Act of 1995 (Pub. L. 

104–113; NTTAA) directs Federal 

agencies to use standards developed by 

voluntary consensus standards bodies in 

lieu of government-written standards 

whenever possible. Voluntary 

consensus standards bodies develop, 

establish, or coordinate technical 

standards using agreed-upon 

procedures. In addition, the Office of 

Management and Budget (OMB) issued 

Circular A–119 62 to implement section 

12(d) of the NTTAA relative to the 

utilization of consensus technical 

standards by Federal agencies. This 

circular provides guidance for agencies 

participating in voluntary consensus 

standards bodies and describes 

procedures for satisfying the reporting 

requirements in the NTTAA. 

Accordingly, PHMSA is responsible 

for determining, via petitions or 

otherwise, which currently referenced 

standards should be updated, revised, or 

removed, and which standards should 

be added to the PSR. Pursuant to 49 

U.S.C. 60102(p), PHMSA may not issue 

a regulation that incorporates by 

reference any documents or portions 

thereof unless the documents or 

portions thereof are made available to 

the public, free of charge. Revisions to 

materials incorporated by reference in 

the PSR are handled via the rulemaking 

process, which allows for the public and 

regulated entities to provide input. 

During the rulemaking process, PHMSA 

must also obtain approval from the 

Office of the Federal Register to 

incorporate by reference any new 

materials. The Office of the Federal 

Register issued a rulemaking on 

November 7, 2014, that revised 1 CFR 

51.5 to require that agencies detail in 

the preamble of an NPRM the ways the 

materials it proposes to incorporate by 

reference are reasonably available to 

interested parties, or how the agency 

worked to make those materials 

reasonably available to interested 

parties.63

To meet these obligations for this 

rulemaking, PHMSA negotiated 

agreements with API and ASTM to 

provide viewable copies of standards 

incorporated by reference in the 

pipeline safety regulations available to 

the public at no cost. API Std 1104 is 

available at https://www.api.org/ 

products-and-services/standards/rightsand-usage-policy#tab-ibr-reading-room 

and is discussed in greater detail in 

section I.1 of this preamble. The ASTM 

standards are available at https://

www.astm.org/READINGLIBRARY/ and 

are discussed in greater detail in section 

G.1 of this preamble. PHMSA will also 

provide individual members of the 

public temporary access to any standard 

that is incorporated by reference. 

Requests for access can be sent to the 

following email address: 

phmsaphpstandards@dot.gov. PHMSA 

also notes that standards incorporated 

by reference in the PSR can be obtained 

from the organization developing each 

standard. Section 192.7 provides the 

contact information for each of those 

standard-developing organizations. 

V. Regulatory Analyses and Notices 

A. Legal Authority for This Rulemaking 

This rule is published under the 

authority of the Federal Pipeline Safety 

Law (49 U.S.C. 60101, et seq.). Section 

60102(a) authorizes the Secretary of 

Transportation to issue regulations 

governing the design, installation, 

inspection, emergency plans and 

procedures, testing, construction, 

extension, operation, replacement, and 

maintenance of pipeline facilities. 

Further, § 60102(l) of the Federal 

Pipeline Safety Law states that the 

Secretary shall, to the extent appropriate 

and practicable, update incorporated 

industry standards that have been 

adopted as a part of the pipeline safety 

regulations. The Secretary has delegated 

the authority in § 60102 to the 


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64 58 FR 51735; Oct. 4, 1993. 

65 82 FR 9339 (Feb. 3, 2017). 

66 64 FR 43255 (Aug. 10, 1999). 

67 65 FR 67249 (Nov. 6, 2000). 68 66 FR 28355 (May 22, 2001). 

Administrator of PHMSA in 49 CFR 

1.97. 

B. Executive Order 12866 and DOT 

Rulemaking Procedures 

E.O. 12866, ‘‘Regulatory Planning and 

Review,’’ 64 requires agencies to regulate 

in the ‘‘most cost-effective manner,’’ to 

make a ‘‘reasoned determination that 

the benefits of the intended regulation 

justify its costs,’’ and to develop 

regulations that ‘‘impose the least 

burden on society.’’ E.O. 12866 and 

DOT regulations governing rulemaking 

procedures at 49 CFR part 5 require that 

PHMSA submit ‘‘significant regulatory 

actions’’ to OMB for review. This rule is 

considered significant under § 3(f) of 

E.O. 12866, and was reviewed by OMB. 

It is also significant under the DOT’s 

rulemaking procedures at 49 CFR part 5. 

Similarly, DOT regulations at § 5.5(f)- 

(g) require that regulations issued by 

PHMSA and other DOT Operating 

Administrations ‘‘should be designed to 

minimize burdens and reduce barriers 

to market entry whenever possible, 

consistent with the effective promotion 

of safety’’ and should generally ‘‘not be 

issued unless their benefits are expected 

to exceed their costs.’’ 

E.O. 12866 and DOT implementing 

regulations at 49 CFR 5.5(i) 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 PSR and the 

preliminary cost and cost savings 

analyses in the Preliminary RIA, as well 

as any information that could assist in 

quantifying the benefits of this 

rulemaking. Those comments are 

addressed in this final rule, and 

additional discussion about the 

economic impacts of the final rule are 

provided within the final RIA posted in 

the rulemaking docket. 

PHMSA estimated that this final rule 

would have economic benefits to the 

public and the regulated community by 

reducing unnecessary cost burdens 

without increasing risks to public safety 

or the environment. PHMSA estimates 

that the final rule will result in 

annualized cost savings of 

approximately $129.8 million per year, 

based on a 7 percent discount rate. Most 

of the quantified cost savings in the 

final rule are from the revisions to farm 

tap requirements and the revised 

atmospheric corrosion reassessment 

interval for distribution service lines. 

The final RIA in the rulemaking docket 

analyzes these economic impacts in 

detail. 

C. Executive Order 13771, ‘‘Reducing 

Regulation and Controlling Regulatory 

Cost’’ 

This final rule is an E.O. 13771 65

deregulatory action. Details on the 

estimated cost savings of this final rule 

can be found in the rule’s economic 

analysis within the RIA in the 

rulemaking docket. 

D. Executive Order 13132— 

‘‘Federalism’’ 

PHMSA analyzed this final rule in 

accordance with E.O. 13132.66 E.O. 

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.’’ 

This final rule does not impose a 

substantial direct effect on the States, 

the relationship between the national 

government and the States, or the 

distribution of power and 

responsibilities among the various 

levels of government. This final rule 

also does not impose substantial direct 

compliance costs on State and local 

governments. 

The final rule could have preemptive 

effect because the Federal Pipeline 

Safety Law, specifically 49 U.S.C. 

60104(c), prohibits certain State safety 

regulation of interstate pipelines. Under 

the Federal Pipeline Safety Law, States 

may 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 PHMSA does 

not regulate. In this instance, the 

preemptive effect of the final rule is 

limited to the minimum level necessary 

to achieve the objectives of the Federal 

Pipeline Safety Law under which the 

final rule is promulgated. Therefore, the 

consultation and funding requirements 

of E.O. 13132 do not apply. 

E. Executive Order 13175— 

‘‘Consultation and Coordination With 

Indian Tribal Governments’’ 

PHMSA analyzed this final rule in 

accordance with the principles and 

criteria in E.O. 13175 67 and DOT Order 

5301.1, ‘‘Department of Transportation 

Programs, Polices, and Procedures 

Affecting American Indians, Alaska 

Natives, and Tribes.’’ E.O. 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 final rule on Indian Tribal 

communities and determined that it 

would not significantly or uniquely 

affect Tribal communities or Indian 

Tribal governments. Therefore, the 

funding and consultation requirements 

of E.O. 13175 do not apply. PHMSA 

received no comments to the effect that 

this rulemaking would have Tribal 

implications. 

F. Executive Order 13211—‘‘Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’ 

E.O. 13211 68 requires Federal 

agencies to prepare a Statement of 

Energy Effects for any ‘‘significant 

energy action.’’ Under E.O. 13211, a 

‘‘significant energy action’’ is defined 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 (including a notice of 

inquiry, ANPRM, and NPRM) that: (1)(i) 

Is a significant regulatory action under 

E.O. 12866 or any successor order, and 

(ii) is likely to have a significant adverse 

effect on the supply, distribution, or use 

of energy; or (2) is designated by the 

Administrator of the Office of 

Information and Regulatory Affairs as a 

significant energy action. 

This final rule is not a ‘‘significant 

energy action’’ under E.O. 13211. It is 

not likely to have a significant adverse 

effect on supply, distribution, or energy 

use; rather, it is expected to reduce 

regulatory burdens on the natural gas 

pipeline sector without adversely 

affecting safety. Further, the Office of 

Information and Regulatory Affairs has 

not designated this final rule as a 

significant energy action. 

G. Regulatory Flexibility Act and 

Executive Order 13272 

The Regulatory Flexibility Act (5 

U.S.C. 601 et seq.), as implemented by 

E.O. 13272, ‘‘Proper Consideration of 

Small Entities in Agency 


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69 68 FR 7990 (Feb. 19, 2003). 

Rulemaking,’’ 69 and § 5.13(f) of DOT 

regulations, requires Federal regulatory 

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. 

PHMSA has determined that the costsavings in the final rule may result in 

significant economic impacts on a 

substantial number of small entities. 

These impacts on regulated entities are 

beneficial. PHMSA has included a 

FRFA within the final RIA posted in the 

docket for this rulemaking. 

H. Paperwork Reduction Act of 1995 

The Paperwork Reduction Act of 1995 

(44 U.S.C. 3501 et seq.) establishes 

policies and procedures for controlling 

paperwork burdens imposed by Federal 

agencies on the public. 

Pursuant to 44 U.S.C. 3506(c)(2)(B) 

and 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 expects 

this final rule to impact the information 

collections described below. 

PHMSA will submit an information 

collection revision request to OMB for 

approval based on the requirements in 

this final rule. The information 

collections are contained in the PSR. 

The following information is provided 

for each information collection: (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 burden for the following 

information collections are estimated to 

be revised as follows: 

1. Title: Incident Reports for Gas 

Pipeline Operators. 

OMB Control Number: 2137–0635. 

Current Expiration Date: 01/31/2023. 

Abstract: This information collection 

covers the collection of information 

from gas pipeline operators for incident 

reporting. PHMSA estimates that due to 

the revised monetary damage threshold 

for reporting incidents operators will 

submit 28 fewer gas distribution 

incident reports, and 14 fewer gas 

transmission reports. Operators 

currently spend 12 hours completing 

each incident report. Therefore, PHMSA 

expects to eliminate 42 responses and 

504 hours from this information 

collection per year as a result of the 

provisions in the proposed rule. 

PHMSA is also revising PHMSA F 

7100.1, the Gas Distribution Incident 

Report, to collect data on mechanical 

joint failures that arise to the level of an 

incident as stipulated in 49 CFR 191.3. 

PHMSA does not expect operators to 

incur additional burden due to this 

change. 

Affected Public: All gas pipeline 

operators. 

Annual Reporting and Recordkeeping 

Burden: 

Total Annual Responses: 259. 

Total Annual Burden Hours: 3,108. 

Frequency of Collection: On Occasion. 

2. Title: Annual and Incident Reports 

for Gas Pipeline Operators. 

OMB Control Number: 2137–0522. 

Current Expiration Date: 01/31/2023. 

Abstract: This information collection 

covers the collection of information 

from gas pipeline operators for 

immediate notice of incidents and 

Annual reports. Based on the proposals 

in this rule, PHMSA plans to eliminate 

the MFF report form under this OMB 

Control Number and have operators 

submit the annual total of mechanical 

joint failures on the Gas Distribution 

Annual Report under OMB Control 

Number 2137–0629. In the currentlyapproved information collection, it is 

estimated that PHMSA currently 

receives, on average, 8,300 MFF reports 

each year with each operator spending, 

on average, 1 hour to complete each 

report. By eliminating this report, 

PHMSA plans to reduce the burden for 

this information collection by 8,300 

responses and 8,300 burden hours. 

Affected Public: All gas pipeline 

operators. 

Annual Reporting and Recordkeeping 

Burden: 

Total Annual Responses: 2,247. 

Total Annual Burden Hours: 71,801. 

Frequency of Collection: Regular. 

3. Title: Pipeline Safety: Integrity 

Management Program for Gas 

Distribution Pipelines. 

OMB Control Number: 2137–0625. 

Current Expiration Date: 06/30/2022. 

Abstract: The PSR require operators of 

gas distribution pipelines to develop 

and implement IM programs. 

PHMSA proposed to eliminate this 

requirement for master meter operators. 

Based on the currently approved 

information collection, PHMSA 

estimates that, on average, 5,461 master 

meter operators spend 26 hours, 

annually, developing new IM plans and/ 

or updating their existing IM plans. 

Eliminating this requirement for master 

meter operators will eliminate 

recordkeeping burdens attributable to 

these 5,461 existing master meter 

operators, saving 141,986 hours of 

burden annually. 

Affected Public: Natural Gas Pipeline 

Operators. 

Annual Reporting and Recordkeeping 

Burden: 

Total Annual Responses: 3,882. 

Total Annual Burden Hours: 723,192. 

Frequency of Collection: On occasion. 

4. Title: Gas Distribution Annual 

Report. 

OMB Control Number: 2137–0629. 

Current Expiration Date: 10/31/2021. 

Abstract: The PSR require distribution 

operators to prepare and submit annual 

reports with summary information on 

their pipeline infrastructure. PHMSA 

proposed to shift the mechanical fitting 

failure form requirements to a count of 

hazardous leaks involving a failure of a 

mechanical joint on the distribution 

annual report form. PHMSA estimates 

that it will take gas distribution 

operators approximately 30 minutes (0.5 

hours; calculated as 13,075 mechanical 

joint failures divided by 1,446 operators 

times 3 minutes per mechanical joint 

failure) to add this information to the 

annual report. As a result, the burden 

for this information collection will 

increase by approximately 723 hours. 

This addition will have no effect on the 

total number of reports submitted. 

Affected Public: Natural Gas 

Distribution Pipeline Operators. 

Annual Reporting and Recordkeeping 

Burden: 

Total Annual Responses: 1,446. 

Total Annual Burden Hours: 25,305. 

Frequency of Collection: Annually. 

I. Unfunded Mandates Reform Act of 

1995 

Unfunded Mandates Reform Act (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 of $100 

million or more in 1996 dollars in any 

given year, the agency must prepare, 

amongst other things, a written 

statement that qualitatively and 

quantitatively assesses the costs and 

benefits of the Federal mandate. 

PHMSA prepared a final RIA and 

determined that this final rule does not 

impose enforceable duties on State, 

local, or Tribal governments or on the 

private sector of $164 million in 2019 

dollars or more in any one year. A copy 

of the final RIA is available for review 

in the docket of this rulemaking. 


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J. National Environmental Policy Act 

The National Environmental Policy 

Act (NEPA) (42 U.S.C. 4321 et. seq.) 

requires Federal agencies to prepare a 

detailed statement on major Federal 

actions significantly affecting the 

quality of the human environment. 

PHMSA analyzed this rule in 

accordance with NEPA, NEPA 

implementing regulations (40 CFR parts 

1500–1508), and DOT Order 5610.1C. 

PHMSA prepared a draft environmental 

assessment (EA) for the NPRM and 

posted it in the rulemaking docket; 

PHMSA received no comments on the 

draft EA. For this final rule, PHMSA has 

prepared a Final Environmental 

Assessment (EA) and has determined 

that this final rule will not significantly 

affect the quality of the human 

environment. The final EA for this final 

rule is available in the docket. 

K. Regulation Identifier Number (RIN) 

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 the spring and fall of each 

year. The RIN number contained in the 

heading of this document is a crossreference for this action to the Unified 

Agenda. 

List of Subjects 

49 CFR Part 191 

Pipeline reporting requirements, 

Integrity management, Pipeline safety, 

Gas gathering. 

49 CFR Part 192 

Incorporation by reference, Pipeline 

safety, Fire prevention, Security 

measures. 

In consideration of the forgoing, 

PHMSA is amending 49 CFR parts 191 

and 192 as follows: 

PART 191—TRANSPORTATION OF 

NATURAL AND OTHER GAS BY 

PIPELINE; ANNUAL REPORTS, 

INCIDENT REPORTS, AND SAFETYRELATED CONDITION REPORTS 

■ 1. The authority citation for 49 CFR 

part 191 continues to read as follows: 

Authority: 30 U.S.C. 185(w)(3), 49 U.S.C. 

5121, 60101 et seq., and 49 CFR 1.97 

■ 2. In § 191.3, in the definition of 

‘‘Incident’’ revise paragraph (1)(ii) to 

read as follows: 

§ 191.3 Definitions. 

* * * * * 

Incident means any of the following 

events: 

(1) * * * 

(ii) Estimated property damage of 

$122,000 or more, including loss to the 

operator and others, or both, but 

excluding the cost of gas lost. For 

adjustments for inflation observed in 

calendar year 2021 onwards, changes to 

the reporting threshold will be posted 

on PHMSA’s website. These changes 

will be determined in accordance with 

the procedures in appendix A to part 

191. 

* * * * * 

■ 3. In § 191.11, revise paragraph (b) to 

read as follows: 

§ 191.11 Distribution system: Annual 

Report. 

* * * * * 

(b) Not required. The annual report 

requirement in this section does not 

apply to a master meter system, a 

petroleum gas system that serves fewer 

than 100 customers from a single 

source, or an individual service line 

directly connected to a production 

pipeline or a gathering line other than 

a regulated gathering line as determined 

in § 192.8. 

§ 191.12 [Removed and Reserved] 

■ 4. Remove and reserve § 191.12. 

■ 5. Appendix A to part 191 is added to 

read as follows: 

Appendix A to Part 191—Procedure for 

Determining Reporting Threshold 

I. Property Damage Threshold Formula 

Each year after calendar year 2021, the 

Administrator will publish a notice on 

PHMSA’s website announcing the updates to 

the property damage threshold criterion that 

will take effect on July 1 of that year and will 

remain in effect until the June 30 of the next 

year. The property damage threshold used in 

the definition of an Incident at § 191.3 shall 

be determined in accordance with the 

following formula: 

Where: 

Tr is the revised damage threshold, 

Tp is the previous damage threshold, 

CPIr is the average Consumer Price Indices 

for all Urban Consumers (CPI–U) 

published by the Bureau of Labor 

Statistics each month during the most 

recent complete calendar year, and 

CPIp is the average CPI–U for the calendar 

year used to establish the previous 

property damage criteria. 

PART 192—TRANSPORTATION OF 

NATURAL GAS AND OTHER GAS BY 

PIPELINE: MINIMUM FEDERAL 

SAFETY STANDARDS 

■ 5. The authority citation for 49 CFR 

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. 

■ 6. In § 192.7: 

■ a. Revise paragraph (a), paragraph (b) 

introductory text, and paragraph (b)(9); 

■ b. Remove and reserve paragraph 

(c)(7); and 

■ c. Revise paragraph (e) introductory 

text and paragraphs (e)(11) and (20). 

The revisions read as follows: 

§ 192.7 What documents are incorporated 

by reference partly or wholly in this part? 

(a) Certain material is incorporated by 

reference into this part with the 

approval of the Director of the Federal 

Register under 5 U.S.C. 552(a) and 1 

CFR part 51. The materials listed in this 

section have the full force of law. All 

approved material is available for 

inspection at Office of Pipeline Safety, 

Pipeline and Hazardous Materials Safety 

Administration, 1200 New Jersey 

Avenue SE, Washington, DC 20590, 

202–366–4046 https://

www.phmsa.dot.gov/pipeline/regs, and 

is available from the sources listed in 

the remaining paragraphs of this 

section. It is also available for 

inspection at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, email fedreg.legal@

nara.gov or go to www.archives.gov/ 

federal-register/cfr/ibr-locations.html. 

(b) American Petroleum Institute 

(API), 200 Massachusetts Ave. NW, 

Suite 1100, Washington, DC 20001, and 

phone: 202–682–8000, website: https:// 

www.api.org/. 

* * * * * 

(9) API Standard 1104, ‘‘Welding of 

Pipelines and Related Facilities,’’ 20th 

edition, October 2005, including errata/ 

addendum (July 2007) and errata 2 

(2008), (API Std 1104), IBR approved for 

§§ 192.225(a); 192.227(a); 192.229(b) 

and (c); 192.241(c); and Item II, 

Appendix B. 

* * * * * 

(e) ASTM International (formerly 

American Society for Testing and 

Materials), 100 Barr Harbor Drive, PO 

Box C700, West Conshohocken, PA 

19428, phone: (610) 832–9585, website: 

http://astm.org. 

* * * * * 

(11) ASTM D2513–18a, ‘‘Standard 

Specification for Polyethylene (PE) Gas 

Pressure Pipe, Tubing, and Fittings,’’ 

approved August 1, 2018, (ASTM 

D2513), IBR approved for Item I, 

Appendix B to Part 192. 

* * * * * 

(20) ASTM F2620–19, ‘‘Standard 

Practice for Heat Fusion Joining of 

Polyethylene Pipe and Fittings,’’ 

approved February 1, 2019, (ASTM 


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F2620), IBR approved for §§ 192.281(c) 

and 192.285(b). 

* * * * * 

■ 7. In § 192.121: 

■ a. In the first sentence of paragraph 

(a), remove the words ‘‘Design formula. 

Design formulas for plastic pipe are’’ 

and add in their place the words 

‘‘Design pressure. The design pressure 

for plastic pipe is’’; 

■ b. In paragraph (c)(2) introductory text 

add the words ‘‘on or’’ after the word 

‘‘produced’’; 

■ c. Revise paragraphs (c)(2)(iii) and 

(iv), and (d)(2)(iv); 

■ d. In paragraph (e) introductory text 

add the words ‘‘on or’’ after the word 

‘‘produced’’; and 

■ e. Revise paragraph (e)(4). 

The revisions read as follows: 

§ 192.121 Design of plastic pipe. 

* * * * * 

(c) * * * 

(2) * * * 

(iii) The pipe has a nominal size (IPS 

or CTS) of 24 inches or less; and 

(iv) The wall thickness for a given 

outside diameter is not less than that 

listed in table 1 to this paragraph 

(c)(2)(iv). 

TABLE 1 TO PARAGRAPH (c)(2)(iv) 

PE pipe: minimum wall thickness and SDR values 

Pipe size 

(inches) 

Minimum wall 

thickness 

(inches) 

Corresponding 

SDR 

(values) 

1⁄2′′ CTS ................................................................................................................................................................... 0.090 7 1⁄2′′ IPS ..................................................................................................................................................................... 0.090 9.3 3⁄4′′ CTS ................................................................................................................................................................... 0.090 9.7 3⁄4′′ IPS ..................................................................................................................................................................... 0.095 11 

1′′ CTS ..................................................................................................................................................................... 0.099 11 

1′′ IPS ...................................................................................................................................................................... 0.119 11 

11⁄4′′ IPS ................................................................................................................................................................... 0.151 11 

11⁄2′′ IPS ................................................................................................................................................................... 0.173 11 

2′′ ............................................................................................................................................................................. 0.216 11 

3′′ ............................................................................................................................................................................. 0.259 13.5 

4′′ ............................................................................................................................................................................. 0.265 17 

6′′ ............................................................................................................................................................................. 0.315 21 

8′′ ............................................................................................................................................................................. 0.411 21 

10′′ ........................................................................................................................................................................... 0.512 21 

12′′ ........................................................................................................................................................................... 0.607 21 

16′′ ........................................................................................................................................................................... 0.762 21 

18′′ ........................................................................................................................................................................... 0.857 21 

20′′ ........................................................................................................................................................................... 0.952 21 

22′′ ........................................................................................................................................................................... 1.048 21 

24′′ ........................................................................................................................................................................... 1.143 21 

(d) * * * 

(2) * * * 

(iv) The minimum wall thickness for 

a given outside diameter is not less than 

that listed in table 2 to paragraph 

(d)(2)(iv): 

TABLE 2 TO PARAGRAPH (d)(2)(iv) 

PA–11 pipe: minimum wall thickness and SDR values 

Pipe size 

(inches) 

Minimum wall 

thickness 

(inches) 

Corresponding 

SDR 

(values) 

1⁄2′′ CTS ................................................................................................................................................................... 0.090 7.0 1⁄2′′ IPS ..................................................................................................................................................................... 0.090 9.3 3⁄4′′ CTS ................................................................................................................................................................... 0.090 9.7 3⁄4′′ IPS ..................................................................................................................................................................... 0.095 11 

1′′ CTS ..................................................................................................................................................................... 0.099 11 

1′′ IPS ...................................................................................................................................................................... 0.119 11 

11⁄4 IPS .................................................................................................................................................................... 0.151 11 

11⁄2′′ IPS ................................................................................................................................................................... 0.173 11 

2′′ IPS ...................................................................................................................................................................... 0.216 11 

3′′ IPS ...................................................................................................................................................................... 0.259 13.5 

4′′ IPS ...................................................................................................................................................................... 0.333 13.5 

6′′ IPS ...................................................................................................................................................................... 0.491 13.5 

(e) * * * (4) The minimum wall thickness for a 

given outside diameter is not less than 

that listed in table 3 to paragraph (e)(4). 


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TABLE 3 TO PARAGRAPH (e)(4) 

PA–12 pipe: minimum wall thickness and SDR values 

Pipe size 

(inches) 

Minimum wall 

thickness 

(inches) 

Corresponding 

SDR 

(values) 

1⁄2′′ CTS ................................................................................................................................................................... 0.090 7 1⁄2′′ IPS ..................................................................................................................................................................... 0.090 9.3 3⁄4′′ CTS ................................................................................................................................................................... 0.090 9.7 3⁄4′′ IPS ..................................................................................................................................................................... 0.095 11 

1′′ CTS ..................................................................................................................................................................... 0.099 11 

1′′ IPS ...................................................................................................................................................................... 0.119 11 

11⁄4′′ IPS ................................................................................................................................................................... 0.151 11 

11⁄2′′ IPS ................................................................................................................................................................... 0.173 11 

2′′ IPS ...................................................................................................................................................................... 0.216 11 

3′′ IPS ...................................................................................................................................................................... 0.259 13.5 

4′′ IPS ...................................................................................................................................................................... 0.333 13.5 

6′′ IPS ...................................................................................................................................................................... 0.491 13.5 

* * * * * 

■ 8. In § 192.153 revise paragraphs (b) 

and paragraph (e) to read as follows: 

§ 192.153 Components fabricated by 

welding. 

* * * * * 

(b) Each prefabricated unit that uses 

plate and longitudinal seams must be 

designed, constructed, and tested in 

accordance with the ASME BPVC (Rules 

for Construction of Pressure Vessels as 

defined in either Section VIII, Division 

1 or Section VIII, Division 2; 

incorporated by reference, see § 192.7), 

except for the following: 

(1) Regularly manufactured buttwelding fittings. 

(2) Pipe that has been produced and 

tested under a specification listed in 

appendix B to this part. 

(3) Partial assemblies such as split 

rings or collars. 

(4) Prefabricated units that the 

manufacturer certifies have been tested 

to at least twice the maximum pressure 

to which they will be subjected under 

the anticipated operating conditions. 

* * * * * 

(e) The test requirements for a 

prefabricated unit or pressure vessel, 

defined for this paragraph as 

components with a design pressure 

established in accordance with 

paragraph (a) or paragraph (b) of this 

section are as follows. 

(1) A prefabricated unit or pressure 

vessel installed after July 14, 2004 is not 

subject to the strength testing 

requirements at § 192.505(b) provided 

the component has been tested in 

accordance with paragraph (a) or 

paragraph (b) of this section and with a 

test factor of at least 1.3 times MAOP. 

(2) A prefabricated unit or pressure 

vessel must be tested for a duration 

specified as follows: 

(i) A prefabricated unit or pressure 

vessel installed after July 14, 2004, but 

before October 1, 2021 is exempt from 

§§ 192.505(c) and (d) and 192.507(c) 

provided it has been tested for a 

duration consistent with the ASME 

BPVC requirements referenced in 

paragraph (a) or (b) of this section. 

(ii) A prefabricated unit or pressure 

vessel installed on or after October 1, 

2021 must be tested for the duration 

specified in either § 192.505(c) or (d), 

§ 192.507(c), or § 192.509(a), whichever 

is applicable for the pipeline in which 

the component is being installed. 

(3) For any prefabricated unit or 

pressure vessel permanently or 

temporarily installed on a pipeline 

facility, an operator must either: 

(i) Test the prefabricated unit or 

pressure vessel in accordance with this 

section and Subpart J of this part after 

it has been placed on its support 

structure at its final installation 

location. The test may be performed 

before or after it has been tied-in to the 

pipeline. Test records that meet 

§ 192.517(a) must be kept for the 

operational life of the prefabricated unit 

or pressure vessel; or 

(ii) For a prefabricated unit or 

pressure vessel that is pressure tested 

prior to installation or where a 

manufacturer’s pressure test is used in 

accordance with paragraph (e) of this 

section, inspect the prefabricated unit or 

pressure vessel after it has been placed 

on its support structure at its final 

installation location and confirm that 

the prefabricated unit or pressure vessel 

was not damaged during any prior 

operation, transportation, or installation 

into the pipeline. The inspection 

procedure and documented inspection 

must include visual inspection for 

vessel damage, including, at a 

minimum, inlets, outlets, and lifting 

locations. Injurious defects that are an 

integrity threat may include dents, 

gouges, bending, corrosion, and 

cracking. This inspection must be 

performed prior to operation but may be 

performed either before or after it has 

been tied-in to the pipeline. If injurious 

defects that are an integrity threat are 

found, the prefabricated unit or pressure 

vessel must be either non-destructively 

tested, re-pressure tested, or remediated 

in accordance with applicable part 192 

requirements for a fabricated unit or 

with the applicable ASME BPVC 

requirements referenced in paragraphs 

(a) or (b) of this section. Test, 

inspection, and repair records for the 

fabricated unit or pressure vessel must 

be kept for the operational life of the 

component. Test records must meet the 

requirements in § 192.517(a). 

(4) An initial pressure test from the 

prefabricated unit or pressure vessel 

manufacturer may be used to meet the 

requirements of this section with the 

following conditions: 

(i) The prefabricated unit or pressure 

vessel is newly-manufactured and 

installed on or after October 1, 2021, 

except as provided in paragraph 

(e)(4)(ii) of this section. 

(ii) An initial pressure test from the 

fabricated unit or pressure vessel 

manufacturer or other prior test of a new 

or existing prefabricated unit or 

pressure vessel may be used for a 

component that is temporarily installed 

in a pipeline facility in order to 

complete a testing, integrity assessment, 

repair, odorization, or emergency 

response-related task, including noise or 

pollution abatement. The temporary 

component must be promptly removed 

after that task is completed. If 

operational and environmental 

constraints require leaving a temporary 

prefabricated unit or pressure vessel 

under this paragraph in place for longer 

than 30 days, the operator must notify 

PHMSA and State or local pipeline 


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safety authorities, as applicable, in 

accordance with § 192.18. 

(iii) The manufacturer’s pressure test 

must meet the minimum requirements 

of this part; and 

(iv) The operator inspects and 

remediates the prefabricated unit or 

pressure vessel after installation in 

accordance with paragraph (e)(3)(ii) of 

this section. 

(5) An existing prefabricated unit or 

pressure vessel that is temporarily 

removed from a pipeline facility to 

complete a testing, integrity assessment, 

repair, odorization, or emergency 

response-related task, including noise or 

pollution abatement, and then reinstalled at the same location must be 

inspected in accordance with paragraph 

(e)(3)(ii) of this section; however, a new 

pressure test is not required provided no 

damage or threats to the operational 

integrity of the prefabricated unit or 

pressure vessel were identified during 

the inspection and the MAOP of the 

pipeline is not increased. 

(6) Except as provided in paragraphs 

(e)(4)(ii) and (5) of this section, on or 

after October 1, 2021, an existing 

prefabricated unit or pressure vessel 

relocated and operated at a different 

location must meet the requirements of 

this part and the following: 

(i) The prefabricated unit or pressure 

vessel must be designed and 

constructed in accordance with the 

requirements of this part at the time the 

vessel is returned to operational service 

at the new location; and 

(ii) The prefabricated unit or pressure 

vessel must be pressure tested by the 

operator in accordance with the testing 

and inspection requirements of this part 

applicable to newly installed 

prefabricated units and pressure vessels. 

■ 9. In § 192.229, revise paragraph (b) to 

read as follows: 

§ 192.229 Limitations on welders and 

welding operators. 

* * * * * 

(b) A welder or welding operator may 

not weld with a particular welding 

process unless, within the preceding 6 

calendar months, the welder or welding 

operator was engaged in welding with 

that process. Alternatively, welders or 

welding operators may demonstrate 

they have engaged in a specific welding 

process if they have performed a weld 

with that process that was tested and 

found acceptable under section 6, 9, 12, 

or Appendix A of API Std 1104 

(incorporated by reference, see § 192.7) 

within the preceding 71⁄2 months. 

* * * * * 

■ 10. In § 192.281, revise paragraph (c) 

to read as follow: 

§ 192.281 Plastic Pipe. 

* * * * * 

(c) Heat-fusion joints. Each heat 

fusion joint on a PE pipe or component, 

except for electrofusion joints, must 

comply with ASTM F2620 

(incorporated by reference in § 192.7), or 

an alternative written procedure that 

has been demonstrated to provide an 

equivalent or superior level of safety 

and has been proven by test or 

experience to produce strong gastight 

joints, and the following: 

* * * * * 

■ 11. In § 192.283 revise paragraph 

(a)(3) to read as follows: 

§ 192.283 Plastic pipe: Qualifying joining 

procedures. 

(a) * * * 

(3) For procedures intended for nonlateral pipe connections, perform tensile 

testing in accordance with a listed 

specification. If the test specimen 

elongates no less than 25% or failure 

initiates outside the joint area, the 

procedure qualifies for use. 

* * * * * 

■ 12. In § 192.285, revise paragraph (b) 

to read as follows 

§ 192.285 Plastic pipe: Qualifying persons 

to make joints. 

* * * * * 

(b) The specimen joint must be: 

(1) Visually examined during and 

after assembly or joining and found to 

have the same appearance as a joint or 

photographs of a joint that is acceptable 

under the procedure; and 

(2) In the case of a heat fusion, solvent 

cement, or adhesive joint: 

(i) Tested under any one of the test 

methods listed under § 192.283(a), and 

for PE heat fusion joints (except for 

electrofusion joints) visually inspected 

in accordance with ASTM F2620 

(incorporated by reference, see § 192.7), 

or a written procedure that has been 

demonstrated to provide an equivalent 

or superior level of safety, applicable to 

the type of joint and material being 

tested; 

(ii) Examined by ultrasonic inspection 

and found not to contain flaws that 

would cause failure; or 

(iii) Cut into at least 3 longitudinal 

straps, each of which is: 

(A) Visually examined and found not 

to contain voids or discontinuities on 

the cut surfaces of the joint area; and 

(B) Deformed by bending, torque, or 

impact, and if failure occurs, it must not 

initiate in the joint area. 

* * * * * 

■ 13. In § 192.465, revise paragraph (b) 

to read as follows: 

§ 192.465 External corrosion control: 

Monitoring. 

* * * * * 

(b) Cathodic protection rectifiers and 

impressed current power sources must 

be periodically inspected as follows: 

(1) Each cathodic protection rectifier 

or impressed current power source must 

be inspected six times each calendar 

year, but with intervals not exceeding 

21⁄2 months between inspections, to 

ensure adequate amperage and voltage 

levels needed to provide cathodic 

protection are maintained. This may be 

done either through remote 

measurement or through an onsite 

inspection of the rectifier. 

(2) After January 1, 2022, each 

remotely inspected rectifier must be 

physically inspected for continued safe 

and reliable operation at least once each 

calendar year, but with intervals not 

exceeding 15 months. 

* * * * * 

■ 14. In § 192.481, revise paragraph (a) 

and add paragraph (d) to read as 

follows: 

§ 192.481 Atmospheric corrosion control: 

Monitoring. 

(a) Each operator must inspect and 

evaluate each pipeline or portion of the 

pipeline that is exposed to the 

atmosphere for evidence of atmospheric 

corrosion, as follows: 

Pipeline type: Then the frequency of inspection is: 

(1) Onshore other than a Service Line .................................................... At least once every 3 calendar years, but with intervals not exceeding 

39 months. 

(2) Onshore Service Line ......................................................................... At least once every 5 calendar years, but with intervals not exceeding 

63 months, except as provided in paragraph (d) of this section. 

(3) Offshore .............................................................................................. At least once each calendar year, but with intervals not exceeding 15 

months. 


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* * * * * 

(d) If atmospheric corrosion is found 

on a service line during the most recent 

inspection, then the next inspection of 

that pipeline or portion of pipeline must 

be within 3 calendar years, but with 

intervals not exceeding 39 months. 

■ 15. In 192.491, revise paragraph (c) to 

read as follows: 

§ 192.491 Corrosion control records. 

* * * * * 

(c) Each operator shall maintain a 

record of each test, survey, or inspection 

required by this subpart in sufficient 

detail to demonstrate the adequacy of 

corrosion control measures or that a 

corrosive condition does not exist. 

These records must be retained for at 

least 5 years with the following 

exceptions: 

(1) Operators must retain records 

related to §§ 192.465(a) and (e) and 

192.475(b) for as long as the pipeline 

remains in service. 

(2) Operators must retain records of 

the two most recent atmospheric 

corrosion inspections for each 

distribution service line that is being 

inspected under the interval in 

§ 192.481(a)(2). 

■ 16. In § 192.505, revise paragraph (c) 

to read as follows 

§ 192.505 Strength test requirements for 

steel pipelines to operate at a hoop stress 

of 30 percent or more of SMYS. 

* * * * * 

(c) Except as provided in paragraph 

(d) of this section, the strength test must 

be conducted by mai ntaining the 

pressure at or above the test pressure for 

at least 8 hours. 

* * * * * 

■ 17. In § 192.507, add paragraph (d) to 

read as follows: 

§ 192.507 Test requirements for pipelines 

to operate at a hoop stress less than 30 

percent of SMYS and at or above 100 p.s.i. 

(689 kPa) gage. 

* * * * * 

(d) For fabricated units and short 

sections of pipe, for which a post 

installation test is impractical, a preinstallation hydrostatic pressure test 

must be conducted in accordance with 

the requirements of this section. 

■ 18. In § 192.619, revise Table 1 to 

paragraph (a)(2)(ii) to read as follows: 

§ 192.619 Maximum allowable operating 

pressure: Steel or plastic pipelines. 

* * * * * 

(a) * * * 

(2) * * * 

(ii) * * * 

TABLE 1 TO PARAGRAPH (a)(2)(ii) 

Class location Installed before 

(Nov. 12, 1970) 

Factors,1 2 segment— 

Installed after 

(Nov. 11, 1970) 

and before 

July 1, 2020 

Installed on or 

after July 1, 2020 

Converted under 

§ 192.14 

1 ....................................................................................................... 1.1 1.1 1.25 1.25 

2 ....................................................................................................... 1.25 1.25 1.25 1.25 

3 ....................................................................................................... 1.4 1.5 1.5 1.5 

4 ....................................................................................................... 1.4 1.5 1.5 1.5 

1For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 

1.25. For pipeline segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland 

navigable waters, including a pipe riser, the factor is 1.5. 2For a component with a design pressure established in accordance with § 192.153(a) or (b) installed after July 14, 2004, the factor is 1.3. 

■ 19. In § 192.740, revise the section 

heading, paragraph (a) and paragraph (c) 

to read as follows: 

§ 192.740 Pressure regulating, limiting, 

and overpressure protection—Individual 

service lines directly connected to 

regulated gathering or transmission 

pipelines. 

(a) This section applies, except as 

provided in paragraph (c) of this 

section, to any service line directly 

connected to a transmission pipeline or 

regulated gathering pipeline as 

determined in § 192.8 that is not 

operated as part of a distribution 

system. 

* * * * * 

(c) This section does not apply to 

equipment installed on: 

(1) A service line that only serves 

engines that power irrigation pumps; 

(2) A service line included in a 

distribution integrity management plan 

meeting the requirements of subpart P of 

this part; or 

(3) A service line directly connected 

to either a production or gathering 

pipeline other than a regulated 

gathering line as determined in § 192.8 

of this part. 

■ 20. Revise § 192.1003 to read as 

follows: 

§ 192.1003 What do the regulations in this 

subpart cover? 

(a) General. Unless exempted in 

paragraph (b) of this section, this 

subpart prescribes minimum 

requirements for an IM program for any 

gas distribution pipeline covered under 

this part, including liquefied petroleum 

gas systems. A gas distribution operator 

must follow the requirements in this 

subpart. 

(b) Exceptions. This subpart does not 

apply to: 

(1) Individual service lines directly 

connected to a production line or a 

gathering line other than a regulated 

onshore gathering line as determined in 

§ 192.8; 

(2) Individual service lines directly 

connected to either a transmission or 

regulated gathering pipeline and 

maintained in accordance with 

§ 192.740(a) and (b); and 

(3) Master meter systems. 

■ 21. In § 192.1005, revise the section 

heading to read as follows: 

§ 192.1005 What must a gas distribution 

operator (other than a small LPG operator) 

do to implement this subpart? 

* * * * * 

■ 22. In § 192.1007, revise paragraph (b) 

to read as follows: 

§ 192.1007 What are the required elements 

of an integrity management plan? 

* * * * * 

(b) Identify threats. The operator must 

consider the following categories of 

threats to each gas distribution pipeline: 

Corrosion (including atmospheric 

corrosion), natural forces, excavation 

damage, other outside force damage, 

material or welds, equipment failure, 

incorrect operations, and other issues 

that could threaten the integrity of its 

pipeline. An operator must consider 

reasonably available information to 

identify existing and potential threats. 


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Sources of data may include incident 

and leak history, corrosion control 

records (including atmospheric 

corrosion records), continuing 

surveillance records, patrolling records, 

maintenance history, and excavation 

damage experience. 

* * * * * 

§ 192.1009 [Removed and Reserved] 

■ 23. Remove and reserve § 192.1009. 

■ 24. In § 192.1015, revise the section 

heading, and paragraphs (a) and (b) to 

read as follows: 

§ 192.1015 What must a small LPG 

operator do to implement this subpart? 

(a) General. No later than August 2, 

2011, a small LPG operator must 

develop and implement an IM program 

that includes a written IM plan as 

specified in paragraph (b) of this 

section. The IM program for these 

pipelines should reflect the relative 

simplicity of these types of pipelines. 

(b) Elements. A written integrity 

management plan must address, at a 

minimum, the following elements: 

(1) Knowledge. The operator must 

demonstrate knowledge of its pipeline, 

which, to the extent known, should 

include the approximate location and 

material of its pipeline. The operator 

must identify additional information 

needed and provide a plan for gaining 

knowledge over time through normal 

activities conducted on the pipeline (for 

example, design, construction, 

operations or maintenance activities). 

(2) Identify threats. The operator must 

consider, at minimum, the following 

categories of threats (existing and 

potential): Corrosion (including 

atmospheric corrosion), natural forces, 

excavation damage, other outside force 

damage, material or weld failure, 

equipment failure, and incorrect 

operation. 

(3) Rank risks. The operator must 

evaluate the risks to its pipeline and 

estimate the relative importance of each 

identified threat. 

(4) Identify and implement measures 

to mitigate risks. The operator must 

determine and implement measures 

designed to reduce the risks from failure 

of its pipeline. 

(5) Measure performance, monitor 

results, and evaluate effectiveness. The 

operator must monitor, as a performance 

measure, the number of leaks eliminated 

or repaired on its pipeline and their 

causes. 

(6) Periodic evaluation and 

improvement. The operator must 

determine the appropriate period for 

conducting IM program evaluations 

based on the complexity of its pipeline 

and changes in factors affecting the risk 

of failure. An operator must re-evaluate 

its entire program at least every 5 years. 

The operator must consider the results 

of the performance monitoring in these 

evaluations. 

* * * * * 

Appendix B to Part 192 [Amended] 

■ 25. Amend Appendix B to part 192 as 

follows: 

■ a. In section I.A., remove the entry for 

‘‘ASTM D2513–12ae1’’ and add in its 

place a new entry for ‘‘ASTM D2513’’, 

and 

■ b. In Section I.B., remove the entry for 

‘‘ASTM D2513–12ae1’’ and add in its 

place a new entry for ‘‘ASTM D2513’’. 

Issued in Washington, DC, on January 1, 

2021, under authority delegated in 49 CFR 

1.97. 

Howard R. Elliott, 

Administrator. 

[FR Doc. 2021–00208 Filed 1–8–21; 8:45 am] 

BILLING CODE 4910–60–P 


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