Document ID: PHMSA-2011-0023-0634
Agency: phmsa
Document Type: Rule
Title: Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments
Posted Date: 2022-08-24T04:00Z

[Federal Register Volume 87, Number 163 (Wednesday, August 24, 2022)]
[Rules and Regulations]
[Pages 52224-52279]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-17031]

[[Page 52223]]

Vol. 87

Wednesday,

No. 163

August 24, 2022

Part IV

 Department of Transportation

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Pipeline and Hazardous Materials Safety Administration

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49 CFR Part 192

Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, 
Integrity Management Improvements, Cathodic Protection, Management of 
Change, and Other Related Amendments; Final Rule

  Federal Register / Vol. 87 , No. 163 / Wednesday, August 24, 2022 / 
Rules and Regulations  

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DEPARTMENT OF TRANSPORTATION

Pipeline and Hazardous Materials Safety Administration

49 CFR Part 192

[Docket No. PHMSA-2011-0023; Amdt. No. 192-132]
RIN 2137-AF39

Pipeline Safety: Safety of Gas Transmission Pipelines: Repair 
Criteria, Integrity Management Improvements, Cathodic Protection, 
Management of Change, and Other Related Amendments

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

ACTION: Final rule.

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SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to 
improve the safety of onshore gas transmission pipelines. This final 
rule addresses several lessons learned following the Pacific Gas and 
Electric Company incident that occurred in San Bruno, CA, on September 
9, 2010, and responds to public input received as part of the 
rulemaking process. The amendments in this final rule clarify certain 
integrity management provisions, codify a management of change process, 
update and bolster gas transmission pipeline corrosion control 
requirements, require operators to inspect pipelines following extreme 
weather events, strengthen integrity management assessment 
requirements, adjust the repair criteria for high-consequence areas, 
create new repair criteria for non-high consequence areas, and revise 
or create specific definitions related to the above amendments.

DATES: The final rule is effective May 24, 2023. The incorporation by 
reference of certain publications listed in the rule is approved by the 
Director of the Federal Register as of May 24, 2023. The incorporation 
by reference of other publications listed in this rule was approved by 
the Director of the Federal Register on July 1, 2020.

FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, 
Senior Technical Advisor, by telephone at 713-272-2855. General 
information: Robert Jagger, Senior Transportation Specialist, by 
telephone at 202-366-4361.

SUPPLEMENTARY INFORMATION:
I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Final Rule
    C. Costs and Benefits
II. Background
    A. Overview
    B. Advance Notice of Proposed Rulemaking
    C. Notice of Proposed Rulemaking and Subsequent Final Rule
III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee 
Recommendations, and PHMSA Response
    A. IM Clarifications--Sec. Sec.  192.917(a)-(d), 192.935(a)
    i. Threat Identification, Data Collection, and Integration--
Sec.  192.917(a) & (b)
    ii. Risk Assessment Functional Requirements--Sec.  192.917(c)
    iii. Threat Assessment for Plastic Pipe--Sec.  192.917(d)
    iv. Preventive and Mitigative Measures--Sec.  192.935(a)
    B. Management of Change--Sec. Sec.  192.13 & 192.911
    C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 
192.473, 192.478, and 192.935 and Appendix D
    i. Applicability
    ii. Installation of Pipe in the Ditch and Coating Surveys--
Sec. Sec.  192.319 & 192.461
    iii. Interference Surveys--Sec.  192.473
    iv. Internal Corrosion--Sec.  192.478
    v. Cathodic Protection--Sec.  192.465 & Appendix D
    vi. P&M Measures--Sec.  192.935(f) & (g)
    D. Inspections Following Extreme Weather Events--Sec.  192.613
    E. Strengthening Requirements for Assessment Methods--Sec. Sec.  
192.923, 192.927, 192.929
    i. Internal Corrosion Direct Assessment--Sec. Sec.  192.923, 
192.927
    ii. Stress Corrosion Cracking Direct Assessment--Sec. Sec.  
192.923(c), 192.929
    F. Repair Criteria--Sec. Sec.  192.714, 192.933
    i. Repair Criteria in HCAs--Sec.  192.933
    ii. Repair Criteria in non-HCAs--Sec.  192.714
    iii. Cracking Criteria--Sec. Sec.  192.714 & 192.933
    iv. Dent Criteria--Sec. Sec.  192.714 & 192.933
    v. Corrosion Metal Loss Criteria--Sec. Sec.  192.714 & 192.933
    vi. General Discussion
    G. Definitions--Sec.  192.3
    i. Close Interval Survey
    ii. Distribution Center
    iii. Dry Gas or Dry Natural Gas
    iv. Electrical Survey
    v. Hard Spot
    vi. ILI and In-Line Inspection Tool or Instrumented Internal 
Inspection Device
    vii. Transmission Line
    viii. Wrinkle Bend
IV. Section-by-Section Analysis
V. Standards Incorporated by Reference
VI. Regulatory Analysis and Notices

I. Executive Summary

A. Purpose of the Regulatory Action

    This final rule concludes a decade-long effort by PHMSA to amend 
its regulations governing onshore natural gas transmission pipelines in 
response to the tragic September 9, 2010, incident at a Pacific Gas and 
Electric Company (PG&E) gas transmission pipeline in San Bruno, CA, 
which resulted in the death of 8 people, injuries to more than 60 other 
people, and the destruction or damage of over 100 homes. PHMSA expects 
the new requirements in this final rule will reduce the frequency and 
consequences of failures and incidents from onshore natural gas 
transmission pipelines through earlier detection of threats to pipeline 
integrity, including those from corrosion or following extreme weather 
events. The safety enhancements in this final rule, therefore, are 
expected to improve public safety, reduce threats to the environment 
(including, but not limited to, reduction of greenhouse gas emissions 
released during natural gas pipeline incidents), and promote 
environmental justice for minority populations, low-income populations, 
and other underserved and disadvantaged communities that are located 
near interstate gas transmission pipelines.
    Although the Federal Pipeline Safety Regulations (49 Code of 
Federal Regulations (CFR) parts 190 through 199; PSR) applicable to gas 
transmission and gathering pipeline systems set forth in parts 191 and 
192 have increased the level of safety associated with the 
transportation of gas, serious safety incidents continue to occur on 
gas transmission and gathering pipeline systems, resulting in serious 
risks to life and property. In its investigation of the 2010 PG&E 
incident, the National Transportation Safety Board (NTSB) found among 
several causal factors that PG&E had an inadequate integrity management 
(IM) program that failed to detect and repair or remove a defective 
pipe section on its gas transmission line.\1\ PG&E based its IM program 
on incomplete and inaccurate pipeline information, which led to, among 
other issues, faulty risk assessments, improper assessment method 
selections, and internal assessments of the program that were 
superficial and resulted in no meaningful improvement.\2\
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    \1\ NTSB, NTSB/PAR-11-01, ``Pipeline Accident Report: Pacific 
Gas and Electric Company, Natural Gas Transmission Pipeline Rupture 
and Fire, San Bruno, California, September 9, 2010'' (2011) (NTSB 
Incident Report on San Bruno).
    \2\ NTSB Incident Report on San Bruno at 107-115.
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    Prior to the PG&E incident, PHMSA had initiated an advance notice 
of proposed rulemaking (ANPRM) to seek comment on whether the IM 
requirements in part 192 should be changed and whether other issues 
related to pipeline system integrity should be addressed by 
strengthening or expanding non-IM requirements.

[[Page 52225]]

PHMSA published the ANPRM on August 25, 2011.\3\
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    \3\ ``Safety of Gas Transmission Pipelines,'' 76 FR 53086 (Aug. 
25, 2011).
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    Based on the comments on the ANPRM, PHMSA published a notice of 
proposed rulemaking (NPRM) on April 8, 2016, to seek public comments on 
proposed changes to the PSR governing transmission and gathering 
lines.\4\ A summary of those proposed changes pertaining to this 
rulemaking, corresponding stakeholder feedback, and PHMSA's responses 
to stakeholder feedback on the individual provisions, is provided below 
in section III of this document (Discussion of NPRM Comments, GPAC 
Recommendations, and PHMSA Response).
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    \4\ ``Safety of Gas Transmission and Gathering Pipelines,'' 81 
FR 20722 (Apr. 8, 2016).
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    PHMSA determined that the most efficient way to manage the 
proposals in the NPRM was to divide them into three separate final rule 
actions. The first of these final rules was published on October 1, 
2019, and addressed topics primarily relating to congressional mandates 
and safety recommendations, including maximum allowable operating 
pressure (MAOP) reconfirmation and material properties verification, 
the expansion of integrity assessments beyond high-consequence areas 
(HCA), the consideration of seismicity, in-line inspection (ILI) 
launcher and receiver safety, MAOP exceedance reporting, and 
strengthened requirements for assessment methods (2019 Gas Transmission 
Rule).\5\ Provisions related to gas gathering pipelines were addressed 
in a separate rulemaking.\6\ This rulemaking finalizes the remaining 
provisions from the NPRM as outlined below.
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    \5\ ``Safety of Gas Transmission Pipelines: MAOP Reconfirmation, 
Expansion of Assessment Requirements, and Other Related 
Amendments,'' 84 FR 52180 (Oct. 1, 2019).
    \6\ ``Safety of Gas Gathering Pipelines: Extension of Reporting 
Requirements, Regulations of Large, High-Pressure Lines, and Other 
Related Amendments,'' 86 FR 63266 (Nov. 15, 2021) (Gas Gathering 
Final Rule).
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B. Summary of the Major Provisions of the Final Rule

    To reduce the risks of pipeline incidents, PHMSA is amending the 
PSR applicable to gas transmission pipelines to improve the protection 
of the public, property, and the environment; close regulatory gaps; 
and adopt additional safety measures to improve safety inside and 
outside of HCAs. Specifically, PHMSA is making changes to clarify the 
IM requirements; improve the management of change (MOC) process; 
strengthen corrosion control requirements; provide parameters for 
inspections following extreme weather events; strengthen requirements 
related to the IM assessment methods; and improve the repair criteria 
for pipeline anomalies. PHMSA is also amending certain definitions in 
part 192 in support of these provisions.
    PHMSA is modifying the IM regulations by adding specificity to the 
data integration language. The final rule establishes several pipeline 
attributes that must be included in an operator's risk analysis when an 
operator determines what threats are applicable to a pipeline segment. 
PHMSA is also explicitly requiring that operators integrate analyzed 
information into their IM programs and is requiring that data be 
verified and validated. Additionally, PHMSA is issuing requirements for 
applying knowledge gained through an operator's IM program, including 
provisions for analyzing interacting threats, potential failures, and 
worst-case incident scenarios from the initial failure to incident 
termination. Several of these items were proposed in response to NTSB 
findings following the PG&E incident that suggested pipeline operators 
were often not conducting data analysis, data integration, threat 
identification, and risk assessment in the manner originally intended 
and specified in subpart O of part 192.
    Similarly, following the PG&E incident, PHMSA, informed by (inter 
alia) the NTSB's evaluation of the incident and ANPRM comments, 
determined that the existing MOC requirements and industry practices 
were not sufficient \7\ and looked to align the regulatory requirements 
with the standards outlined in American Society of Mechanical 
Engineers/American National Standards Institute (ASME/ANSI) B31.8S.\8\ 
Specifically, this final rule requires each operator of an onshore gas 
transmission pipeline to develop and follow a MOC process, as outlined 
in ASME/ANSI B31.8S, section 11, that addresses technical, design, 
physical, environmental, procedural, operational, maintenance, and 
organizational changes to the pipeline or processes, whether permanent 
or temporary.
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    \7\ See 81 FR 20796; NTSB Incident Report on San Bruno at 95-97 
(concluding that the probable cause of the PG&E incident was PG&E's 
inadequate quality assurance and quality control in 1956 during its 
Line 132 relocation project, and noting that PG&E had poor quality 
control during a pipe installation project that later failed in 2008 
in Rancho Cordova, CA).
    \8\ ASME/ANSI ``B31.8S-2004: Supplement to B31.8 on Managing 
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
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    This final rule also improves and updates the corrosion control 
requirements for gas transmission pipeline operators. Based on lessons 
PHMSA has learned following several pipeline failures, and following 
PHMSA's workshop on pipeline construction in Fort Worth, TX, on April 
23, 2009,\9\ PHMSA determined that construction practices, including 
the installation of pipe in-ditch, can result in damaged coating that 
can compromise corrosion control. Therefore, this rule requires that 
operators perform assessments to identify suspected damage promptly 
after backfilling and then remediate any coating damage found. Further, 
PHMSA has noted that the existing regulations were not always effective 
at eliminating deficiencies in cathodic protection \10\ corrosion 
control or at preventing incidents from internal corrosion. Therefore, 
this rule strengthens the requirements for internal and external 
corrosion controls related to monitoring requirements and surveys. 
PHMSA also determined that additional prescriptive preventive and 
mitigative (P&M) measures are needed for managing electrical 
interference currents.
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    \9\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=58.
    \10\ Cathodic protection is a technique used to control 
corrosion by making the metal pipe a cathode of an electrochemical 
cell. Essentially, the pipeline is connected to a more easily 
corroded metal that acts as an anode. That ``sacrificial anode'' 
metal corrodes instead of the metal that is being protected. For 
pipelines, passive galvanic cathodic protection is often not 
adequate, and an external direct current (DC) electrical power 
source is used to provide sufficient current.
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    Extreme weather has been a contributing factor in several pipeline 
failures. PHMSA issued Advisory Bulletins in 2015, 2016, and 2019 to 
communicate the potential for damage to pipeline facilities caused by 
severe flooding, including actions that operators should consider 
taking to ensure the integrity of pipelines in the event of flooding, 
river scour, river channel migration, and earth movement.\11\ As PHMSA 
has noted in another series of Advisory Bulletins, hurricanes are also 
capable of causing extensive damage to both offshore and inland 
pipelines.\12\
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    \11\ ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by Flooding, River Scour, and River Channel 
Migration,'' 80 FR 19114 (Apr. 9, 2015); ``Pipeline Safety: 
Potential for Damage to Pipeline Facilities Caused by Flooding, 
River Scour, and River Channel Migration,'' 81 FR 2943 (Jan. 19, 
2016); ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by Earth Movement and Other Geological Hazards,'' 
84 FR 18919 (May 2, 2019).
    \12\ ``Potential for Damage to Pipeline Facilities Caused by the 
Passage of Hurricane Ivan,'' 69 FR 57135 (Sept. 23, 2004); 
``Pipeline Safety Advisory: Potential for Damage to Pipeline 
Facilities Caused by the Passage of Hurricane Katrina,'' 70 FR 53272 
(Sept. 7, 2005); ``Pipeline Safety: Potential for Damage to Pipeline 
Facilities Caused by the Passage of Hurricanes,'' 76 FR 54531 (Sept. 
1, 2011) (alerting operators to the potential for damage from 
Hurricane Ivan).

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[[Page 52226]]

    Because of the frequency and severe consequences of these 
events,\13\ operators must protect the public from pipeline risks in 
the event of a natural disaster or extreme weather. While many prudent 
operators might voluntarily perform inspections following such events, 
the potential risk to public safety and environment merits codification 
of those practices in regulatory requirements. Therefore, PHMSA is 
amending the PSR to require that operators commence inspection of their 
potentially affected facilities within 72 hours after the operator 
determines the affected area can be safely accessed following the 
cessation of an extreme weather event such as a hurricane, landslide, 
flood; a natural disaster, such as an earthquake; or another similar 
event that has the likelihood to damage infrastructure. If an operator 
finds an adverse condition during the inspection, the operator must 
take appropriate remedial action to ensure the safe operation of the 
pipeline.\14\
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    \13\ For the impacts of climate change on precipitation; 
droughts, floods, and wildfire; and extreme storms, see U.S. Global 
Change Research Program, ``Climate Science Special Report: Fourth 
National Climate Assessment, Volume 1,'' at ch. 7-9 (2017).
    \14\ PHMSA notes that these part 192 amendments are consistent 
with similar provisions adopted for part 195 for hazardous liquid 
pipelines. See ``Pipeline Safety: Safety of Hazardous Liquid 
Pipelines,'' 84 FR 52260 (Oct. 1, 2019).
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    PHMSA is also strengthening the standards for performing pipeline 
assessments by incorporating by reference certain consensus standards 
for both stress corrosion cracking (NACE International Standard 
Practice 0204-2008, ``Stress Corrosion Cracking Direct Assessment 
Methodology'' (2008) (NACE 0204-2008)) and internal corrosion direct 
assessments (NACE International Standard Practice 0206-2006, ``Internal 
Corrosion Direct Assessment Methodology for Pipelines Carrying Normally 
Dry Natural Gas'' (2006) (NACE SP0206-2006)). Operators are already 
required to assess the condition of gas transmission pipelines in HCAs 
and certain non-HCAs periodically in accordance with Sec. Sec.  
192.710, 192.921, and 192.937. When the initial IM regulations creating 
subpart O were issued in 2003 (2003 IM rule), industry standards did 
not exist for these types of assessments.\15\ By incorporating by 
reference the standards subsequently published by NACE 
International,\16\ PHMSA is ensuring greater consistency, accuracy, and 
quality when operators perform these assessments.
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    \15\ ``Pipeline Safety: Pipeline Integrity Management in High 
Consequence Areas (Gas Transmission Pipelines): Final Rule,'' 68 FR 
69778 (Dec. 15, 2003).
    \16\ In 2021, NACE International merged with the Society for 
Protective Coatings, becoming the Association for Materials 
Protection and Performance (AMPP). They will continue to be referred 
to as NACE International throughout this document.
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    This final rule also updates the existing repair criteria for HCAs 
by incorporating criteria for additional anomaly types such as crack 
anomalies, certain corrosion metal loss defects, and certain mechanical 
damage defects. Such revisions will provide greater assurance that 
operators will repair injurious anomalies and defects before those 
defects grow to a size that causes a leak or rupture. PHMSA also is 
finalizing explicit repair criteria for non-HCAs. Prior to this final 
rule, there were only general requirements in the regulations for 
operators to perform repairs in non-HCAs. The content of the non-HCA 
repair criteria being finalized in this rule is consistent with the 
criteria for HCAs; however, PHMSA has provided longer timeframes for 
the remediation of conditions that are not categorized as ``immediate'' 
conditions to provide operators the ability to prioritize remediating 
anomalous conditions in HCAs where consequences of a pipeline failure 
may be greater.
    The various changes in this rule have also prompted additions and 
changes to certain definitions in part 192. PHMSA has created or made 
changes to the following terms: ``close interval survey,'' 
``distribution center,'' ``dry gas or dry natural gas,'' ``hard spot,'' 
``in-line inspection (ILI),'' ``in-line inspection tool or instrumented 
internal inspection device,'' ``transmission line,'' and ``wrinkle 
bend.''

C. Costs and Benefits

    PHMSA has prepared an assessment of the benefits and costs of the 
final rule as well as reasonable alternatives. PHMSA estimates the 
annual costs of the rule to be approximately $17 million, calculated 
using a 7 percent discount rate. The costs reflect improvements made to 
the MOC process, additional corrosion control requirements, the 
provisions related to inspections following extreme weather events, and 
the changes made to the repair criteria. PHMSA finds that the other 
final rule requirements will not result in incremental costs.
    PHMSA is posting the Regulatory Impact Analysis (RIA) for this rule 
in the public docket. PHMSA has determined that the regulatory 
amendments adopted in this final rule will improve public safety, 
reduce threats to the environment (including, but not limited to, 
reduction of methane emissions contributing to the climate crisis), and 
promote environmental justice for minority populations, low-income 
populations, and other underserved and disadvantaged communities. PHMSA 
finds the regulatory amendments adopted in this final rule are 
technically feasible, reasonable, cost-effective, and practicable 
because the public safety, environmental, and equity benefits of its 
regulatory amendments described herein and within its supporting 
documents (including the RIA and environmental assessment, each 
available in the docket for this rulemaking) will justify any 
associated costs and demonstrate and the superiority of the final rule 
compared to alternatives.

II. Background

A. Overview

    On September 9, 2010, a 30-inch-diameter natural gas transmission 
pipeline, owned and operated by PG&E, ruptured in a residential 
neighborhood in San Bruno, CA. The rupture produced a crater 
approximately 72 feet long by 26 feet wide. The segment of pipe that 
ruptured weighed approximately 3,000 pounds, was 28 feet long, and was 
found 100 feet south of the crater. When the escaping gas ignited, the 
resulting fire killed 8 people, injured approximately 60 more, 
destroyed or damaged 108 homes, and caused the evacuation of over 300 
people. In its pipeline accident report for the incident, the NTSB 
determined that the probable cause of the incident was PG&E's 
inadequate quality control and assurance when it relocated the line in 
1956 and its inadequate IM program. The NTSB determined that PG&E's IM 
program was deficient and ineffective because it was based on 
incomplete and inaccurate pipeline information, did not consider how 
the pipeline's design and materials contributed to the risk of a 
pipeline failure, and failed to consider the presence of previously 
identified welded seam cracks as part of its risk assessment. These 
deficiencies resulted in the selection of an assessment method that 
could not detect welded seam defects and led to internal assessments of 
PG&E's IM program that were superficial and resulted in no 
improvements. Ultimately, this inadequate IM program failed to detect 
and repair or replace the defective pipe section.

[[Page 52227]]

    In response to this incident, Congress, the NTSB, and the 
Government Accountability Office (GAO) called for PHMSA to improve IM 
and address other weaknesses and gaps in the PSR. As described in more 
detail in the sections that follow, this is the second of three planned 
rulemakings that are the culmination of this rulemaking initiative.

B. Advance Notice of Proposed Rulemaking

    On August 25, 2011, PHMSA published an ANPRM to seek public 
comments regarding potential revisions to the PSR pertaining to the 
safety of gas transmission and gathering pipelines. PHMSA requested 
comments on 122 questions spread across 15 broad issues involving IM 
and non-IM requirements. The issues related to IM requirements included 
whether the definition of an HCA should be revised and whether 
additional restrictions should be placed on the use of certain pipeline 
assessment methods. The issues related to non-IM requirements included 
whether revised requirements were needed for mainline valve spacing and 
actuation, whether requirements for corrosion control should be 
strengthened, and whether new regulations were needed to govern the 
safety of gas gathering lines and underground natural gas storage 
facilities. Based on the comments received on several of the ANPRM 
topics, PHMSA developed specific proposals for some of those topics in 
an NPRM that was the basis for this final rule.

C. Notice of Proposed Rulemaking and Subsequent Final Rule

    On April 8, 2016, PHMSA published an NPRM seeking public comments 
on proposed revisions to the PSR pertaining to the safety of onshore 
gas transmission pipelines and gas gathering pipelines. PHMSA 
considered the comments it received from the ANPRM and proposed new 
pipeline safety requirements and revisions of existing requirements in 
several major topic areas. A summary of the NPRM proposals and topics 
pertinent to this rulemaking, the comments received on those specific 
proposals, and PHMSA's response to the comments received, is provided 
under section III (Discussion of NPRM Comments, GPAC Recommendations, 
and PHMSA Response).
    On October 1, 2019, PHMSA promulgated a subset of the rules 
proposed in the NPRM by issuing the first of three planned final rules. 
In that rule, PHMSA addressed gas transmission pipelines and 
established minimum Federal safety standards for MAOP reconfirmation, 
pipeline physical material properties verification, the expansion of 
integrity assessments beyond HCAs, the consideration of seismicity in 
an operator's risk assessment and P&M measures, ILI tool launcher and 
receiver safety, MAOP exceedance reporting, and strengthened 
requirements for IM assessment methods.
    This final rule, the second of three planned rules, finalizes 
several proposed amendments in the NPRM related to gas transmission 
pipelines, including provisions related addressing repair criteria, IM 
improvements, cathodic protection, MOC processes, and other related 
amendments. A separate rulemaking, dealing with the safety of onshore 
gas gathering pipelines, was the subject of a final rule published on 
November 15, 2021, and extended reporting and safety requirements to 
certain gathering pipelines that were formerly not subject to Federal 
safety oversight. PHMSA estimated in that Gas Gathering Final Rule that 
there were over 400,000 miles of gas gathering pipelines that were not 
subject to minimum Federal pipeline safety standards, including basic 
incident and mileage reporting. The Gas Gathering Final Rule extended 
annual and incident reporting requirements to all gathering pipelines 
and defined a new category of ``Type C'' gathering pipelines to address 
the safety of larger-diameter, higher-pressure onshore gathering 
pipelines that were formerly unregulated. The scope of the requirements 
for Type C gas gathering pipelines are risk-based; basic damage 
prevention provisions apply to all Type C gas gathering pipelines while 
other safety requirements apply to larger-diameter Type C gas gathering 
pipelines or those Type C gas gathering pipelines that are located near 
buildings intended for human occupancy.

III. Discussion of NPRM Comments, Gas Pipeline Advisory Committee 
Recommendations, and PHMSA Response

    The comment period for the NPRM ended on July 7, 2016. PHMSA 
received approximately 300 submissions to the docket containing 
thousands of comments on the NPRM. Submissions were received from the 
NTSB; groups representing the regulated pipeline industry; groups 
representing public interests, including environmental groups; State 
utility commissions and regulators; members of Congress; individual 
pipeline operators; and private citizens. PHMSA also received late-
filed comments to this rulemaking from the major industry trade 
associations and others following advisory committee meetings as 
discussed below. Consistent with DOT Order 2100.6 and 190.323, PHMSA 
considered all comments, including those that were filed late, given 
their relevance to the rulemaking and the absence of additional expense 
or delay resulting from considering these comments.
    Some of the comments PHMSA received in response to the NPRM were 
considered in finalizing the 2019 Gas Transmission Rule targeted at 
statutory mandates, while other comments were considered in response to 
the third final rule on gas gathering pipelines (under RIN 2137-AE38). 
In this final rule, PHMSA considers those comments that are relevant to 
repair criteria, IM improvements, cathodic protection, MOC, and other 
related amendments. PHMSA does not address the comments on pipeline 
safety issues that were beyond the scope of the NPRM and, therefore, 
beyond the scope of this final rule. However, that does not mean that 
PHMSA determined the comments lack merit or do not support additional 
rules or amendments. Such issues may be the subject of other existing 
rulemaking proceedings or may be addressed in future rulemaking 
proceedings. The remaining comments reflect a wide variety of views on 
the merits of particular sections of the proposed regulations.
    The Technical Pipeline Safety Standards Committee, commonly known 
as the Gas Pipeline Advisory Committee (GPAC or ``the committee''), is 
a statutorily mandated advisory committee that advises and comments on 
PHMSA's proposed safety standards, risk assessments, and safety 
policies for natural gas pipelines prior to their final adoption. The 
GPAC is one of two pipeline advisory committees focused on technical 
safety standards that were established under the Federal Advisory 
Committee Act (Pub. L. 92-463) and section 60115 of the Federal 
Pipeline Safety Statutes (49 U.S.C. 60101 et seq.). Each committee 
consists of approximately 15 members, with membership equally divided 
among Federal and State agencies, regulated industry, and the public. 
The committees consider the ``technical feasibility, reasonableness, 
cost-effectiveness, and practicability'' of each proposed pipeline 
safety standard and provide PHMSA with recommended actions pertaining 
to those proposals.
    Due to the size and technical detail of the NPRM, the GPAC met 5 
times in 2017 and 2018 to discuss the proposed

[[Page 52228]]

regulations applicable to gas transmission pipelines. The GPAC convened 
one time in 2019 to discuss the provisions related specifically to gas 
gathering pipelines.\17\ During those meetings, the GPAC considered the 
specific regulatory proposals of the NPRM and discussed various 
comments made on the NPRM's proposal by stakeholders, including the 
pipeline industry at large, public interest groups, and government 
entities. To assist the GPAC in its deliberations, PHMSA presented a 
description and summary of the major proposals in the NPRM and the 
comments received on those issues. Stakeholders could comment on the 
proposals during the meeting prior to the committee discussion. PHMSA 
assisted the committee in fostering discussion and developing 
recommendations by providing direction on which issues were most 
pressing.
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    \17\ Specifically, the committee met on January 11-12, 2017; 
June 6-7, 2017; December 14-15, 2017; March 2, 2018; March 26-28, 
2018; and June 25-26, 2019. Information on these meetings can be 
found at regulations.gov under docket no. PHMSA-2011-0023 and at 
PHMSA's public meeting page: https://primis.phmsa.dot.gov/meetings/.
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    For the proposals addressed in this final rule, the committee came 
to consensus when voting on the technical feasibility, reasonableness, 
cost-effectiveness, and practicability of the NPRM's provisions. In 
many instances, the committee recommended changes to certain proposals 
that the committee found would make the rule more feasible, reasonable, 
cost-effective, or practicable.
    This section discusses the substantive comments on the NPRM that 
were submitted to the docket, as well as the GPAC's recommendations. 
They are organized by topic and include PHMSA's response to, and 
resolution of, those comments.

A. IM Clarifications--Sec. Sec.  192.917(a)-(d), 192.935(a)

i. Threat Identification, Data Collection, and Integration--Sec.  
192.917(a) and (b)
1. Summary of PHMSA's Proposal
    Subpart O of 49 CFR part 192 prescribes requirements for managing 
pipeline integrity in HCAs and requires that operators identify and 
evaluate all potential threats to each covered pipeline segment. 
Operators are required to identify threats to which the pipeline is 
susceptible, collect data for analysis, and perform a risk assessment 
that informs the operator's baseline assessment schedule and 
reassessment intervals as well as any additional P&M measures that may 
be needed for the covered segment. The regulations also require 
operators to address particular threats, such as third-party damage and 
manufacturing and construction defects. For these requirements, the 
regulations reference, through incorporation, ASME/ANSI B31.8S.
    For threat identification, the regulations in Sec.  192.917 specify 
that the potential threats operators must consider include, but are not 
limited to, the threats listed in section 2 of ASME/ANSI B31.8S. Those 
threats are grouped into time-dependent threats, static or resident 
threats, time-independent threats, and human error. In performing data 
gathering and integration, operators must follow the requirements in 
ASME/ANSI B31.8S, section 4. At a minimum, operators must gather and 
evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, 
which are the year of installation; pipe inspection reports; leak 
history; wall thickness; diameter; past hydrostatic test information; 
gas, liquid, or solid analysis; bacteria culture test results; 
corrosion detection devices; operating parameters; and operating stress 
level. An operator must also conduct a risk assessment that follows 
ASME/ANSI B31.8S section 5.
    In a risk-based IM approach, data collection and integration is the 
backbone of an effective IM program. The PG&E incident exposed several 
problems in the way operators collect and manage pipeline condition 
data, showing that some operators have inadequate records regarding the 
physical and operational characteristics of their pipelines. The use of 
erroneous information leads to insufficient understanding of pipeline 
risks and incorrect integrity-related decision making. PG&E's IM 
program was missing or misidentified data elements that were necessary 
to characterize risk correctly and establish and validate MAOP, which 
is critically important for providing an appropriate margin of safety 
to the public.
    Threat identification, data collection, and data integration are 
basic pillars on which IM was founded with the issuance of the 2003 IM 
rule. As specified in Sec.  192.907(a), operators were to start with a 
framework, evolve that framework into a more detailed and comprehensive 
program, and continually improve their IM programs.\18\ Operators would 
accomplish this constant improvement, in part, through learning about 
the IM process itself and learning more about the physical condition of 
their pipelines via IM assessments and the development of that data.
---------------------------------------------------------------------------

    \18\ See 68 FR 69789.
---------------------------------------------------------------------------

    Data collection for new pipeline construction is relatively simple. 
However, collecting missing material property records for pipeline 
segments that have been in the ground for years can be challenging, as 
such data collection must be completed through integrity assessments or 
excavations. Operators are required to identify missing data and apply 
conservative assumptions, but incomplete data presents issues for risk 
assessment. The over-application of assumptions in the absence of real 
data, even if those assumptions are conservative, can lead to skewed or 
otherwise inaccurate risk analysis results.
    In the NPRM, PHMSA proposed to revise Sec.  192.917 to include 
specific requirements for collecting, validating, and integrating 
pipeline data. These requirements would add further specificity to the 
data integration regulations, list specific pipeline attributes that 
must be included in these analyses, explicitly require that operators 
integrate analyzed information, and require that data be verified and 
validated. PHMSA also proposed to require that operators use validated, 
objective data to the maximum extent practical. To the degree that 
subjective data from subject matter experts (SME) must be used, PHMSA 
would require that operator programs include specific features to 
compensate for SME bias, including training SMEs to recognize or avoid 
bias, and using outside technical experts or independent expert reviews 
to assess SME judgment and logic. Further, in Sec.  192.917(b)(3), 
PHMSA proposed to require operators to identify and analyze spatial 
relationships among anomalous information (e.g., corrosion coincident 
with foreign line crossings and evidence of pipeline damage where 
overhead imaging shows evidence of encroachment), stating that storing 
or recording the information in a common location, including a 
geographic information system (GIS) alone, is not sufficient.
2. Summary of Public Comment
    Many stakeholders agreed with PHMSA that verified and validated 
data is important for data integration and threat analysis. The NTSB 
expressed support for the proposed additions to the IM analysis 
requirements and commented that expanded pipeline record and data 
requirements are a significant safety improvement in the management of 
pipelines through their service lifecycle. However, certain

[[Page 52229]]

stakeholders had concerns with PHMSA's specific proposed changes.
    PHMSA also received comments from the industry on the feasibility 
of threat identification, data gathering, and integration. The American 
Petroleum Institute (API) stated that while the totality of attributes 
listed in proposed Sec.  192.917 should not pose a major burden on the 
industry, some specific attributes listed may not be feasible to obtain 
in practice. Enterprise Products stated that including just four or 
five attributes that point to a specific conclusion would be more 
useful than the lengthy list of attributes in the proposed provisions. 
A few commenters requested PHMSA clarify what they meant by ``data 
integration, verification, and validation,'' as these terms were not 
clear.
    The Interstate Natural Gas Association of America (INGAA) and the 
Texas Pipeline Association (TPA) expressed concern that the proposed 
provisions are more prescriptive than the ASME/ANSI standard that is 
referenced in the current IM requirements. INGAA also commented that 
PHMSA's proposed inclusion of specific attributes from ASME/ANSI B31.8S 
in the regulatory text alongside the existing incorporation by 
reference of that standard could cause confusion. INGAA further stated 
that PHMSA should retain the current regulatory language requiring 
operators to ``consider'' the relevant data for covered segments and 
similar non-covered segments, instead of adopting the proposed 
provisions that would require data evaluation for non-covered segments. 
INGAA also stated that many of the data elements required by ASME/ANSI 
B31.8S are not available for older pipelines, which can include non-
covered segments. INGAA and other commenters also asserted that PHMSA 
should provide sufficient time for operators to comply with the 
proposed data validation and integration requirements given the 
expansion of Sec.  192.917(b)(1) to non-covered segments.
    Several commenters provided input on PHMSA's proposed requirements 
to address SME bias. INGAA suggested PHMSA should delete the references 
to SME bias listed in Sec.  192.917(b)(2) and replace the text with 
more general language to include peer reviews and external SME 
verification, citing this alternative as more consistent and clearer 
than what PHMSA proposed. National Fuel stated that using outside 
technical experts for bias control would be unnecessarily costly to 
pipeline operators. The American Gas Association (AGA) asserted that 
using outside technical subject matter experts for bias control is 
already standard practice within the industry and that it is not 
necessary to codify it into regulation. PG&E also suggested 
improvements to the section, stating that there is not an existing 
industry standard to provide guidance on what constitutes an outside 
technical expert to perform this specific function, and PHMSA should 
provide further guidance on this topic.
    Several industry trade groups provided input on the proposed 
language in Sec.  192.917(b)(3) that would require operators to 
identify and analyze the spatial relationship among anomalous 
information (e.g., corrosion coincident with foreign line crossings and 
evidence of pipeline damage where overhead imaging shows evidence of 
encroachment). TPA stated that it disagreed with PHMSA's proposal in 
this paragraph and commented that this requirement would impose a 
financial burden on smaller operators. PG&E asserted that the proposed 
language in Sec.  192.917(b)(3) should be removed entirely since it was 
not clear how to comply with these requirements.
    At the GPAC meeting on June 7, 2017, the committee noted that the 
NPRM's proposed revisions to Sec.  192.917 do not include a way for 
operators to address the lack of availability of some data sets. The 
committee suggested that operators could assume the pipeline segment is 
susceptible to the threat associated with the missing data. The 
committee also questioned the purpose for the extensive, prescriptive 
data list, with some members believing it would turn into a compliance 
paperwork exercise without safety benefit. This, in turn, led to a 
discussion of how an operator demonstrates to a regulator that it is 
performing an effective risk analysis and whether that is a checklist 
of items or performing actions to generate better safety outcomes. Some 
committee members suggested PHMSA clarify that operators should only 
collect the pertinent data for operations and maintenance (O&M) tasks.
    Committee members representing the industry noted the rule has no 
timeframe for the implementation of data collection and challenged the 
conclusion in the preliminary regulatory impact assessment (PRIA) that 
the data collection elements had a cost of zero, as databases may need 
to be upgraded to implement the listed attributes. Members representing 
the industry also requested PHMSA remove the proposed requirement to 
address SME bias; however, other committee members representing the 
public noted that SME bias in risk analysis is recognized across 
different disciplines and reflects a need to address how humans think 
about risk. Certain committee members representing the industry were 
also concerned that the requirements mandated the use of a GIS, which 
might be impractical for small operators.
    Following the discussion, the committee voted 11-0 that the 
proposed rule, as published in the Federal Register, with regard to the 
provisions for IM clarifications regarding threat identification, data 
collection, and data integration, were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA revised the list 
of pipeline attributes in the section to be more consistent with the 
existing regulations and the ASME/ANSI B31.8S standard, and if PHMSA 
also added language requiring operators to collect data that is 
pertinent and that a prudent operator would collect. The committee also 
recommended PHMSA require operators to have implementation procedures 
in place 1 year after the effective date of the rule, with full 
incorporation of all listed attributes by 3 years after the effective 
date of the rule, and strike requirements for operators to use a GIS in 
complying with these provisions. Finally, the committee recommended 
that PHMSA address SME bias by considering some of the specific 
suggestions made by committee members at the meeting, including 
striking or revising the last sentence of the provisions.
3. PHMSA Response
    The current regulations at Sec.  192.917(b) explicitly require 
that, at a minimum, an operator must gather and evaluate the set of 
data specified in Appendix A to ASME/ANSI B31.8S. Operators may not 
ignore that requirement to collect the minimum set of data needed for a 
robust threat evaluation and risk assessment. PHMSA agrees that some 
assumptions regarding threat applicability based upon pipe type, 
operating parameters, and operating environment (i.e., weld seam type, 
manufacturing date, coating type, operating pressure versus percentage 
specified minimum yield strength (SMYS), operating temperature, lack of 
cathodic protection (CP) or the time when CP was placed on the system, 
and location) can be made even if the pertinent data is missing. For 
example, a lack of CP on a pipeline system would mean that the pipeline 
is more prone to external corrosion, no matter what type of external 
coating is on the pipe. High operating temperatures, pressures, and a 
lack of quality pipe coating can also be risk factors for cracking.
    Regarding INGAA's comment on retaining the current regulatory

[[Page 52230]]

language requiring operators to ``consider'' the relevant data for 
covered segments and similar non-covered segments rather than adopting 
the proposed provisions that would require data evaluation for non-
covered segments, PHMSA reminds operators that the current requirement 
states that operators must gather and integrate existing data and 
information on the entire pipeline that could be relevant to the 
covered segment. At a minimum, operators must gather and evaluate the 
set of data specified in Appendix A to ASME/ANSI B31.8S and consider 
both on the covered segment and similar non-covered segments the data 
and conditions specific to each pipeline. PHMSA's clarification in this 
final rule that operators must ``analyze'' the information that they 
are already required to collect, integrate, and consider, is consistent 
with the existing requirement, as performing those actions is, 
essentially, an analysis. Nevertheless, PHMSA is changing ``consider'' 
to ``analyze'' to reinforce that operators must have documentation 
demonstrating that they have reviewed the data for similar vintage pipe 
to determine whether they have threats or not that should be 
remediated.
    PHMSA further disagrees that it is appropriate to allow industry to 
continue to ``consider'' data elements selectively or that only 
specifying a few required data elements is the best approach. While 
some pipelines without associated data may not pose a risk, some may 
pose a significant risk. Comprehensive data is the best way to ensure 
an appropriate assessment and, in turn, reduction of risk. The addition 
of the specific data elements in the regulatory text clarifies PHMSA's 
expectations of data collection. PHMSA agrees, however, that some data 
elements may not be pertinent to all pipeline segments. Therefore, in 
this final rule, PHMSA is revising the proposed requirement to specify 
that the operator must collect ``pertinent'' data ``about pipeline 
attributes to assure safe operation and pipeline integrity, including 
information derived from operations and maintenance activities,'' as 
recommended by the GPAC. Regarding the cost of this data collection, 
all the proposed elements were listed in ASME/ANSI B31.8S. As that 
standard has been incorporated by reference since 2004 for covered 
segments (i.e., HCAs), collecting the listed data should not be a new 
or an extensive exercise for any prudent operator with appropriate 
processes in place. While specifying the list of data elements in the 
regulatory text is new, the elements listed have been incorporated by 
reference since the promulgation of subpart O and are not more 
prescriptive than the current regulations. Further, PHMSA disagrees 
that continuing to incorporate by reference ASME/ANSI B31.8S as well as 
specifying individual data elements will confuse operators.
    Additionally, in response to comments and the GPAC recommendation, 
PHMSA is revising the listing of data elements to be more consistent 
with ASME/ANSI B31.8S. In some cases, PHMSA has clarified the meaning 
of generic terms in the data collection list found in ASME/ANSI B31.8S 
within this final rule. For example, where the ASME/ANSI standard lists 
``material properties,'' PHMSA has elaborated by specifying these are 
``material properties including, but not limited to, grade, SMYS, and 
ultimate tensile strength.'' In another example, where the standard 
lists ``pipe inspection reports,'' PHMSA has itemized, in this final 
rule, the pipe inspections required by part 192 and that are commonly 
performed by operators.
    PHMSA agrees with commenters that sufficient time should be 
allotted for operators to comply with the data integration 
requirements. However, PHMSA also agrees with the comments made that 
operators should have been collecting and accounting for the pertinent 
items of this data set since the publication of the original IM rule 
almost 20 years ago. Therefore, in this final rule, PHMSA is providing 
a phased-in timeframe. The GPAC recommended that the implementation 
timeframe should begin in year 1, with full incorporation by 3 years. 
Given the existing requirements for collecting and using the data 
elements from ASME/ANSI B31.8S, and given the discussion at the GPAC 
meetings and the public comments received, PHMSA has revised this final 
rule to require that an operator must begin data integration on the 
effective date of the rule and integrate all attributes within 18 
months of this rule's publication date.
    Regarding comments calling for clarification of what ``data 
integration, verification, and validation'' meant, PHMSA notes that, at 
a minimum, an operator should consider the same set of data on a 
periodic basis and analyze changes and trends that would indicate the 
need for additional integrity evaluations.
    Regarding SME bias, PHMSA believes that it is important for 
operators to address SME bias in data collection and risk assessment to 
account for the reality of how humans think about risk. Operators 
should take this into consideration when incorporating SME opinion as 
fact or when treating input from all SMEs as equivalent. While some 
operators may effectively account for SME bias, PHMSA has not observed 
this to be universal practice in the industry. To the point commenters 
made that using outside technical experts for bias control is 
unnecessarily costly, PHMSA notes that the use of outside technical 
experts would be optional: this final rule contemplates that operators 
could also employ training to ensure information provided by their own 
SMEs is consistent and accurate. While commenters also correctly noted 
that there is not an existing industry standard as to what constitutes 
an outside technical expert or an independent technical expert for SME 
bias control, an operator is ultimately responsible for determining the 
appropriateness and conductors of such a review. As a part of such a 
review, should an operator decide to have another SME review input from 
another SME, the operator must use a qualified SME--e.g., an individual 
with formal or on-the-job technical training in the technical or 
operational area being analyzed, evaluated, or assessed. Operators 
would be required to document that the SME is appropriately 
knowledgeable and experienced in the subject being assessed.
    PHMSA was persuaded, consistent with a GPAC recommendation, that 
some adjustments to the rule language are appropriate for clarity, or 
to eliminate redundant language, within the non-exhaustive list of 
specific types of data to be collected at Sec.  192.179(a) and (b). 
Specific changes adopted in this final rule include the following:
     Section 192.917(a)(2): deleted a redundant reference to 
``or equipment defects;''
     Section 192.917(b)(1)(iii): deleted explicit material 
properties (e.g., hardness, chemical composition) from a non-exhaustive 
list of material properties;
     Section 192.917(b)(1)(xxiv): added ``seam cracking'' 
within the list of pipe operational and maintenance inspection reports 
to be reviewed;
     Section 192.917(b)(1)(xxv): deleted a redundant reference 
to ``outer/inner diameter corrosion monitoring;''
     Section 192.917(b)(1)(xxviii): eliminated specific 
examples of ``encroachments;'' and
     Section 192.917(b)(1)(xxxvi): deleted a redundant savings 
clause for ``other pertinent information'' when the lead-in to the 
section noted that the information listed was non-exhaustive.

[[Page 52231]]

    PHMSA has also, consistent with a recommendation by the GPAC 
revised the rule by (1) requiring that operators employ adequate 
control measures for SME input to ensure consistent and accurate 
information rather than ``correct'' SME ``bias;'' and (2) requiring 
that operators document the names and qualifications of individuals who 
approve SME input rather than document the names of the SMEs and the 
information provided.
    Concerning the use of a GIS, the NPRM's proposed revisions to Sec.  
192.917 were not intended to imply that all operators were required to 
implement a GIS system but were meant to clarify that data integration 
is not achieved solely by maintaining spatially located data in a GIS 
system. Accordingly, PHMSA has revised this final rule as recommended 
by the GPAC to delete reference to the use of a GIS system and maintain 
the core requirement to identify and analyze spatial relationships 
among anomalous information.

A. IM Clarifications--Sec. Sec.  192.917(a)-(d), 192.935(a)

ii. Risk Assessment Functional Requirements--Sec.  192.917(c)
1. Summary of PHMSA's Proposal
    Section 192.917(c) requires operators to perform a risk assessment 
as part of an effective IM program. A risk assessment is an important 
element of a good IM plan. PHMSA analyzed the issues related to risk 
assessments that the NTSB identified in its investigation and held a 
workshop on July 21, 2011, to address perceived shortcomings in the 
implementation of IM risk assessments. PHMSA also sought input from 
stakeholders on these issues in the ANPRM. Based on the input received 
from both the ANPRM and the workshop, PHMSA determined that additional 
clarification was needed to emphasize the functions that risk 
assessments must accomplish and to elaborate on effective processes for 
risk management, both of which are critical to effective IM.
    To address these issues, PHMSA proposed to clarify the risk 
assessment aspects of the IM regulations at subpart O by including the 
following functional requirements for risk assessments that operators 
should perform to assure pipeline integrity:
     Evaluate the effects of interacting threats;
     Ensure validity of the methods used to conduct the risk 
assessment;
     Determine additional P&M measures needed;
     Analyze how a potential failure could affect an HCA, 
including the consequences of the entire worst-case incident scenario, 
from initial failure to incident termination;
     Identify how each risk factor, or each combination of risk 
factors that simultaneously interact, contribute to risk at a common 
location;
     Account and compensate for uncertainties in the model and 
the data used in the risk assessment; and
     Evaluate risk reduction associated with candidate 
activities, such as P&M measures.
2. Summary of Public Comment
    Public interest groups supported PHMSA's proposed revisions at 
Sec.  192.917(c) to strengthen the functional requirements for risk 
assessment models. The Pipeline Safety Trust (PST) stated that the risk 
assessment models currently used by pipeline operators are inadequate 
and further noted that the proposed provisions could go farther to 
advance risk assessment quality. Other GPAC members representing the 
public supported the proposed revisions at Sec.  192.917(c) during the 
committee meetings and noted that the NPRM language for this topic was 
written using a risk-informed approach that articulated the functions 
and purposes of risk assessments without being prescriptive as to the 
method or process to be used, which is consistent with IM principles.
    Multiple industry trade associations and individual operators 
acknowledged the importance of risk assessments but believed that the 
proposed revisions at Sec.  192.917(c) were too prescriptive. Several 
individual operators emphasized their voluntary efforts to improve 
their risk models and disagreed that the industry's risk models needed 
further prescription.
    Many commenters emphasized that different pipeline systems are 
susceptible to different threats and believed that operators are best 
suited to determine which threat analyses are relevant to their 
systems. Multiple operators expressed the opinion that the proposed 
revisions at Sec.  192.917(c) would require operators to expand 
datasets substantially but would contribute little benefit to risk 
identification, suggesting instead that integrating unnecessary 
datasets would distract from other safety efforts. AGA and several 
individual operators requested that PHMSA give operators discretion to 
select which data sets to incorporate into risk assessments for their 
system.
    Some commenters requested that PHMSA specify what the NPRM meant 
when it proposed to revise Sec.  192.917(c) to require operators to 
``validate'' data. These commenters expressed doubts regarding the 
technical feasibility of implementing the proposed regulations in Sec.  
192.917(c), noting that some of the data PHMSA proposed requiring for 
the validation of risk assessment models is not available. These 
commenters proposed that operators be permitted to apply conservative 
values or values determined using engineering judgement. Southwest Gas 
Corporation, Paiute Pipeline, and Consumers Pipeline expressed concern 
that developing the newly required datasets would require the usage of 
ILI tools that their pipelines are not configured to accommodate. These 
commenters stated that gathering these datasets would present costs 
that were not captured by PHMSA's PRIA because PHMSA did not account 
for the cost of making lines piggable.
    Multiple commenters were concerned that the proposed revisions 
would make operators' current relative risk models invalid and would 
require a transition to quantitative or probabilistic risk models. 
Similarly, API agreed with that assessment and noted that quantitative 
and probabilistic models are not useful or appropriate for the 
analysis, prediction, or prevention of low-frequency, high-consequence 
events such as the PG&E incident. Further, API noted that the 
probabilities of certain infrequent circumstances and conditions 
occurring at a single location and single time are so low that the 
quantitative or probabilistic risk models would not identify them 
because there are no statistics available from which to predict them. 
AGA asserted that the proposed requirements deviate from industry 
standards and that PHMSA did not provide sufficient justification for 
this departure. Commenters also emphasized the high costs associated 
with implementing quantitative risk models, which can include the 
procurement of specialist expertise, development of new datasets, and 
transition to a GIS or other new database management system.
    Kern River requested clarification regarding which elements of 
Sec.  192.917 need to be included in an operator's risk model and which 
elements only need to be included in the overall IM plan. They noted 
that integrity assessment method determinations, repair decisions, P&M 
measures selection, root cause analyses, and similar pipe studies all 
play a part in the overall IM plan and have at times overlapping, but 
also unique, requirements for data gathering, integration, and threat 
analysis.

[[Page 52232]]

    AGA and several individual operators expressed concerns that the 
proposed rule does not provide a timeline for implementing new risk 
assessment requirements, thereby implying that operators must implement 
new requirements by the rule's effective date. Multiple operators and 
industry trade associations requested that operators be permitted to 
develop their own implementation schedules or provided suggestions for 
specific implementation schedules. For example, Enterprise Products 
requested that PHMSA include a 2-year implementation period for 
operators to incorporate the data integration and risk assessment 
requirements into their IM programs.
    At the GPAC meeting on January 12, 2017, some committee members 
noted that any revisions to the risk assessment requirements should be 
deferred until after PHMSA's Pipeline Risk Modeling Work Group issues 
its pipeline system risk modeling technical document.\19\ There was 
broad support from the committee for the revisions to Sec.  192.917(c) 
proposed in the NPRM, with members noting the language was consistent 
with IM principles and was written using a performance-based approach 
that articulated the functions and purposes of risk assessment without 
being prescriptive as to the method or process needing to be used. 
However, some committee members representing the industry expressed 
concern with the use of the term ``probability'' in the NPRM's proposed 
revisions to Sec.  192.917(c), which seemed to imply PHMSA intended for 
operators to be using probabilistic risk assessment techniques.
---------------------------------------------------------------------------

    \19\ For more information on the work group and its efforts, see 
https://www.phmsa.dot.gov/pipeline/risk-modeling-work-group/risk-modeling-work-group-overview.
---------------------------------------------------------------------------

    Following the discussion, the committee voted 11-0 that the 
proposed provisions for the risk assessment requirements were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA modified the proposed rule to restore the reference to ASME/ANSI 
B31.8S, section 5, to clarify that other methods besides probabilistic 
techniques may be used; change the term ``probability'' to 
``likelihood'' and delete the term ``risk factors'' from Sec.  192.917 
(c)(2); and provide a 3-year phase-in period for risk assessments to 
meet the functional objectives specified in Sec.  192.917(c).
3. PHMSA Response
    On March 6, 2020, PHMSA published the final report titled 
``Pipeline Risk Modeling--Overview of Methods and Tools for Improved 
Implementation'' from the joint PHMSA/industry working group on risk 
modeling.\20\ However, PHMSA notes that the report is focused 
exclusively on the models employed and ``best practices'' for using 
them. The working group did not address other aspects of the proposed 
rule, including how a risk assessment is used.
---------------------------------------------------------------------------

    \20\ https://www.phmsa.dot.gov/news/now-available-phmsa-report-pipeline-risk-modeling-overview-methods-and-tools-improved-0.
---------------------------------------------------------------------------

    PHMSA believes that the revisions to Sec.  192.917(c) are important 
to include in this rulemaking now, as many operators have not 
substantially improved their risk assessment techniques or models since 
the early initial efforts to prioritize baseline assessment plans in 
2004, with the findings from the PG&E incident being a prime, national 
example. Therefore, PHMSA is establishing explicit minimum standards 
for the functional requirements of a risk assessment to help assure 
that operators will achieve this specific aspect of a ``more detailed 
and comprehensive'' program as discussed in the 2003 IM rule.
    In the NPRM's proposed revisions to Sec.  192.917(c), when PHMSA 
used terms such as ``probability'' and ``risk factors,'' it was not 
intended to imply that an operator must perform probabilistic risk 
analysis. To address this, PHMSA has modified the rule language to 
replace the term ``probability'' with ``likelihood'' and restored the 
reference to ASME/ANSI B31.8S, section 5, for acceptable risk 
assessment methodologies as recommended by the GPAC. Similarly, and as 
also recommended by the GPAC, PHMSA has deleted the phrase ``or risk 
factors'' from paragraph Sec.  192.917(c)(2) for clarity. Whichever 
risk assessment methodology an operator chooses, the result must meet 
the functional requirements and accomplish the purposes specified in 
this final rule.
    PHMSA notes that all data elements specified in Sec.  192.917(b) 
are important for a robust risk assessment. While operators do have the 
discretion to expand their data collection efforts, this minimum 
defined data set is required to be used. As was emphasized by multiple 
operators in their comments, each pipeline system is susceptible to 
different threats, and the individual operator is best suited to 
determine these threats. However, an operator needs the specified data 
elements to identify threats objectively. As noted in the previous 
section, PHMSA has modified the rule to refer to the ``pertinent'' data 
elements, including information derived from O&M activities that assure 
safe operation and pipeline integrity. This revision clarifies that 
data elements that are not pertinent for a given pipeline segment need 
not be included in a risk assessment.
    Pertaining to comments regarding the validity of the method used, 
an operator must ensure the soundness of the risk modelling method they 
are using applicable to the threats to a given pipeline segment, 
including its specific leak or failure history. To Kern River's comment 
as to which elements of Sec.  192.917 need to be included in an 
operator's risk model and which elements need to be included in an 
operator's IM plan, PHMSA will note that integrity assessment method 
determinations, repair decisions, P&M measure selection, and root cause 
analyses are examples of items that could be included in an operator's 
risk model based on the particular types of threats being assessed. The 
existing regulations state that a ``particular threat'' is an 
identified threat being assessed for each covered segment.
    As discussed above, some commenters claimed there would be high 
costs associated with implementing quantitative risk models, which 
might include the procurement of specialist expertise, the development 
of new data sets, and a transition to a GIS or other new database 
management system. PHMSA notes that operators can use the same data 
they have been, and are currently, collecting when implementing a 
quantitative risk model. Operators do not necessarily have to 
``recollect'' or otherwise change their existing data to use a 
probabilistic risk model.
    Given the state of some operators' risk assessment programs, PHMSA 
is persuaded that it is reasonable to allow operators a reasonable 
amount of time to upgrade their risk assessment models, methodologies, 
and analyses. However, this is an important provision that operators 
need to implement as soon as practicable. Therefore, and to be more 
consistent with the implementation for the data attributes discussed 
earlier, PHMSA is modifying this final rule to allow an 18-month 
implementation period for this provision.

A. IM Clarifications--Sec. Sec.  192.917(a)-(d), 192.935(a)

iii. Threat Assessment for Plastic Pipe--Sec.  192.917(d)
1. Summary of PHMSA's Proposal
    PHMSA proposed to add to the regulations examples of threats unique 
to plastic pipe that operators must consider, such as poor joint fusion 
practices, pipe with poor slow crack

[[Page 52233]]

growth (SCG) resistance, brittle pipe, circumferential cracking, 
hydrocarbon softening of the pipe, internal and external loads, 
longitudinal or lateral loads, proximity to elevated heat sources, and 
point loading. The proposed revisions would not otherwise change the 
current requirements of Sec.  192.917(d).
2. Summary of Public Comment
    PHMSA did not receive any public comments on this section. At the 
GPAC meeting on June 7, 2017, PHMSA noted in its presentation to the 
committee that there were no public comments on the issue. 
Subsequently, the GPAC voted 11-0 that the proposed changes to the 
provisions for IM clarifications for threat assessments for plastic 
pipe were technically feasible, reasonable, cost-effective, and 
practicable, and they did not recommend any additional changes to Sec.  
192.917(d).
3. PHMSA Response
    Since PHMSA did not receive any public comments or additional GPAC 
recommendations regarding threat assessment for plastic pipe, the final 
rule includes the requirement in Sec.  192.917(d) as proposed in the 
NPRM. PHMSA proposed these changes to highlight these potential threats 
to both operators and inspectors, and finalizing these requirements 
will provide additional safety and enforcement awareness.

A. IM Clarifications--Sec. Sec.  192.917(a)-(d), 192.935(a)

iv. Preventive and Mitigative Measures--Sec.  192.935(a)
1. Summary of PHMSA's Proposal
    PHMSA's inspection experience shows that some operators do not 
implement additional P&M measures based on the evaluation required at 
Sec.  192.935(a). PHMSA believes that strengthening requirements 
related to operators' use of insights gained from their IM programs is 
prudent to ensure effective risk management. Therefore, PHMSA proposed 
to clarify the expectation that operators use knowledge from risk 
assessments to establish and implement adequate P&M measures and 
provided more explicit examples of the types of P&M measures for 
operators to evaluate.
2. Summary of Public Comment
    Several commenters requested that PHMSA revise the requirements at 
Sec.  192.935(a) to remove the requirement for operators to perform all 
the listed measures to prevent a pipeline failure and to mitigate the 
consequences of a pipeline failure in an HCA. These commenters stated 
that requiring operators to perform all the measures listed at Sec.  
192.935(a) negates the need for a risk analysis, as the rule would then 
require that operators perform each of the listed actions regardless of 
whether conditions warrant these actions or whether past efforts have 
been taken. INGAA suggested that PHMSA should keep the existing 
language, which states that an operator must base the additional 
measures on the threats the operator has identified to each pipeline 
segment. GPAC members representing the industry echoed INGAA's claims 
during the committee meetings.
    During the GPAC meeting on June 7, 2017, the GPAC noted that 
PHMSA's proposed changes removed a statement that an operator must base 
additional P&M measures on the threats an operator has identified for 
each pipeline segment. The proposed text, the members believed, implied 
an operator would be required to evaluate and implement each listed P&M 
measure every time. Based on PHMSA's webinars and other discussions, 
the committee members didn't believe that was PHMSA's intent.
    Following that discussion, the committee voted 11-0 that the 
proposed provisions for strengthening the requirements for applying IM 
knowledge were technically feasible, reasonable, cost-effective, and 
practicable if PHMSA clarified it was not the agency's intent to 
require that all listed P&M measures be implemented, and that operators 
``must consider'' the listed items.
3. PHMSA Response
    PHMSA agrees that all listed measures are not mandatory for 
implementation in all cases. Requiring an operator to implement P&M 
measures against threats that might not be applicable to their 
particular system could be overly burdensome. However, PHMSA has 
determined that requiring operators to consider the listed measures in 
their risk analyses and apply them to threats as appropriate is a 
practical requirement. As recommended by the GPAC, the final rule has 
been modified to reflect that position; each operator will be required 
to consider the listed measures and determine the appropriateness of 
each for their system.

B. Management of Change--Sec. Sec.  192.13 & 192.911

1. Summary of PHMSA's Proposal
    Section 192.911(k) requires that an operator's IM program include a 
MOC process as outlined in ASME/ANSI B31.8S, section 11. That document 
guides operators to develop formal MOC procedures to identify and 
consider the impact of major and minor changes to pipeline systems and 
their integrity. These changes can include technical, physical, 
procedural, and organizational changes, and they can be either 
temporary or permanent changes. Per ASME/ANSI B31.8S, section 11, an 
operator's MOC process should include the reason for the change, the 
authority for approving changes, an analysis of the implications of the 
change, the proper acquisition of the necessary work permits, 
appropriate documentation, communications of the change to any affected 
parties, time limitations of the change, and the qualification of 
staff. The document notes that changes to a pipeline system might 
require changes to an operator's IM program; similarly, changes to an 
IM program might also cause changes to a pipeline system. If changes in 
land use (e.g., increased population) would affect the potential 
consequence of an incident or the likelihood of an incident occurring, 
such a change should be reflected in an operator's IM program. The 
operator should also reevaluate threats accordingly. In short, the MOC 
process outlined by ASME/ANSI B31.8S helps to ensure that an operator's 
IM process remains viable and effective as changes to pipeline systems 
occur or new data becomes available.
    Inadequately reviewed or documented design, construction, 
maintenance, or operational changes can contribute to pipeline 
failures. In the PG&E incident, the NTSB investigation determined that 
a substandard piece of pipe was substituted in the field without proper 
authorization, design review, or approval. PHMSA has subsequently 
determined that more specific attributes of the MOC process should be 
explicitly codified within the text of Sec. Sec.  192.13 (general 
requirements) and 192.911(k) (IM requirements). As a result, PHMSA 
proposed to require that operators have a MOC process that includes the 
reasons for the change; the authority for approving changes; an 
analysis of implications; the acquisition of required work permits; and 
evidence documenting communication of the change to affected parties, 
time limitations, and the qualification of staff.

[[Page 52234]]

2. Summary of Public Comment
    Public interest groups, such as the PST, and the National 
Association of Pipeline Safety Representatives (NAPSR) agreed with and 
supported the proposed MOC provisions, stating that these provisions 
would enhance pipeline safety. Several individual pipeline operators 
and trade associations opposed the proposed MOC provisions, stating 
that the provisions are generally too broad and would be applied to 
many routine activities that already have established procedures. More 
specifically, AGA stated that they would create a new requirement for 
each transmission operator to have a formal MOC process to document and 
evaluate all changes to pipelines and processes. They further stated 
that the proposed revisions are unnecessary due to current industry 
progress related to MOC and the voluntary adoption of industry 
consensus standards.
    Several commenters opposed the proposed addition of four types of 
changes (design, environmental, operational, and maintenance), 
asserting that these elements are not included in current industry 
standards or recommended practices. Similarly, INGAA asserted that 
PHMSA should eliminate the changes it proposed to Sec.  192.13 that go 
beyond the recommendations of ASME/ANSI B31.8S. These commenters stated 
that PHMSA significantly underestimated the impact and burden caused by 
codifying and expanding the scope of MOC.
    Several commenters, including AGA, API, and INGAA, opposed the 
proposed immediate implementation of the MOC provisions, with some 
commenters requesting an implementation period of 1 to 5 years. These 
commenters stated that the proposed changes were significant and would 
need to be incorporated into existing MOC processes, and that 
additional time would be needed to complete this in an effective 
manner. Many commenters also expressed concern over the retroactive 
application of the proposed MOC provisions.
    At the GPAC meeting on January 12, 2017, the committee voted 8--2 
that the proposed MOC revisions were technically feasible, reasonable, 
cost-effective, and practicable if PHMSA provided a 2-year phase-in 
period for the regulations as they pertain to non-IM pipeline assets, 
provided a notification procedure for justified extensions, clarified 
the requirements only covers significant changes that affect safety and 
the environment, and clearly stated that the revisions do not apply to 
distribution or gathering lines. The dissenters in the vote 
(representatives from the Environmental Defense Fund (EDF) and PST) 
were members representing the public, who thought that the proposed 
revisions were acceptable as proposed in the NPRM, the phase-in period 
recommended by the majority of the GPAC was too long, and that there 
was no reason that the proposed revisions should not apply to gathering 
lines.
3. PHMSA Response
    PHMSA believes that an operator must understand the impacts that 
their decisions have on safety and the environment. Therefore, PHMSA 
believes that specifying the types of changes that must be addressed 
under a MOC program is appropriate. PHMSA also believes that the 
proposed changes to the MOC provisions conform with the requirements 
and intent of ASME/ANSI B31.8S.
    However, based on the comments received and GPAC recommendations, 
PHMSA is persuaded that, as published in the NPRM, the language of 
proposed Sec.  192.13(d) could be overly broad. Therefore, PHMSA has 
revised the requirement to specify the requirement applies to a 
``significant change that poses a risk to safety or the environment'' 
to limit the application of this requirement to significant changes, as 
the GPAC recommended. Additionally, and as also recommended by the 
GPAC, PHMSA is specifying that Sec.  192.13(d) is not retroactive and 
applies only to onshore transmission pipelines (i.e., not gathering or 
distribution pipelines).\21\
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    \21\ PHMSA stated, in response to written comments submitted in 
the docket and discussion during the January 2017 GPAC meeting, that 
it would in the final rule limit application of the NPRM's proposed 
management of change amendments at Sec.  192.13(d) to exclude gas 
distribution and gathering lines. PHMSA notes, however, that (1) 
PHMSA has undertaken a rulemaking (under RIN 2137-AF53) that will 
consider extending those or similar requirements to gas distribution 
pipelines as required by a mandate in section 204 of the Protecting 
our Infrastructure of Pipelines and Enhancing Safety Act of 2020 
(Pub. L. 116-260)); and (2) PHMSA may consider extending those or 
similar requirements to gas gathering lines as PHMSA obtains more 
information on the safety risks of such pursuant to enhanced 
reporting requirements codified by PHMSA's Gas Gathering Final Rule.
---------------------------------------------------------------------------

    PHMSA agrees that operators should be afforded time to comply with 
this new requirement, but also believes that operators can apply this 
process to non-HCA assets more promptly than the period that the GPAC 
recommended. Therefore, operators have 18 months for the MOC process to 
be fully incorporated for non-HCA pipeline segments. PHMSA is also 
including a notification procedure in accordance with Sec.  192.18 for 
operators to apply for an extension, of up to 1 year, of the compliance 
deadline. PHMSA believes including this compliance deadline strikes a 
balance between the GPAC recommendation and the implementation of a 
procedure that operators already have in place for HCA pipeline 
segments, and including a notification procedure to provide operators 
with more time, if necessary, effectively implements the GPAC 
recommendations.

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

i. Applicability
1. Summary of PHMSA's Proposal
    Incidents attributed to corrosion continue to occur, which 
demonstrates that the current requirements can be more effective at 
preventing incidents caused by certain types of corrosion. This 
includes compromised pipe or pipe coating caused by damage from 
construction, cathodic protection deficiencies, interference currents, 
and internal corrosion. As a result, PHMSA proposed several changes to 
the regulations for corrosion control, including new requirements for 
pipe coating assessments, protective coating strength, P&M measures, 
and additional mitigation of stray current (also referred to as 
interference current). PHMSA also proposed changes regarding gas stream 
monitoring program requirements to mitigate internal corrosion. These 
proposed revisions were made in Sec. Sec.  192.319, 192.461, 192.465, 
192.473, and 192.935(f) and (g) and are discussed more thoroughly in 
this section. PHMSA also proposed to add a new Sec.  192.478 for the 
monitoring and mitigation of internal corrosion.
2. Summary of Public Comment
    The Coalition to Reroute Nexus, the Michigan Coalition to Protect 
Public Rights-of-Way, NAPSR, and the PST supported the proposed changes 
regarding corrosion control and pipeline condition monitoring. 
Earthworks suggested that PHMSA issue even more stringent requirements 
given the number of post-Carlsbad incidents that have occurred due to 
corrosion.\22\ The Pipeline Safety Coalition, the Public Service 
Commission of West Virginia, and the Pennsylvania Public Utility

[[Page 52235]]

Commission stated that not all gathering pipelines should be exempt 
from corrosion monitoring.
---------------------------------------------------------------------------

    \22\ An incident near Carlsbad, NM, on August 19, 2000, which 
was caused due to corrosion, killed 12 people and caused nearly $1 
million in damage. The incident was a catalyst for PHMSA's IM 
program requirements for pipelines.
---------------------------------------------------------------------------

    Some commenters requested clarification regarding whether the 
proposed provisions were intended to include transmission, 
distribution, and gathering pipelines. Other commenters provided input 
on whether gathering pipelines should be included in the corrosion 
control requirements, especially alternating current voltage gradient 
(ACVG) and direct current voltage gradient (DCVG) inspections in 
proposed Sec.  192.461.
    During the meeting on June 7, 2017, GPAC committee members 
questioned whether the corrosion control requirements would apply to 
gathering lines--the presumption among the majority of the members was 
that the requirements were not intended to include gathering or 
distribution lines. The committee provided other feedback specific to 
the applicability and implementation of specific corrosion topic areas, 
which are discussed in the applicable sections below.
3. PHMSA Response
    PHMSA has considered the comments received regarding the 
applicability of the proposed corrosion control requirements. PHMSA 
stated at the June 2017 GPAC meetings, in response to comments received 
on the NPRM and the discussions during the GPAC meeting, that it would 
in the final rule exclude gathering and distribution pipelines from the 
NPRM's proposed requirements in subpart I related to corrosion control. 
Accordingly, PHMSA has revised Sec.  192.9 to exempt gathering lines 
from several of these requirements. PHMSA, however, may consider 
expanding this provision to gathering lines in the future. Comments on 
the specific provisions proposed for corrosion control are addressed in 
the following sections.
    As to commenters requesting the regulations be made even more 
strict than proposed, PHMSA notes that changes more stringent than 
those proposed would require further notice. PHMSA believes that 
currently, there is also not sufficient data to justify more stringent 
changes. PHMSA will continue to review all data sources on the subject, 
including incident and annual reports, and consider more stringent 
corrosion control safety requirements in a future rulemaking if there 
is data supporting the need.

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

ii. Installation of Pipe in the Ditch and Coating Surveys--Sec. Sec.  
192.319 and 192.461
1. Summary of PHMSA's Proposal
    Section 192.319 prescribes requirements for installing pipe in a 
ditch, including requirements to protect pipe coating from damage 
during the process. While most operators perform the required high-
voltage holiday detection \23\ on the pipeline prior to it being placed 
into the ditch, pipe coating can sometimes be damaged during the 
handling, lowering, and backfilling process, which can compromise its 
ability to prevent external corrosion. To address this problem, PHMSA 
proposed to require that onshore gas transmission pipeline operators 
perform an above-ground indirect assessment through an ACVG or DCVG 
survey to identify locations of suspected damage promptly after an 
operator completes the backfilling process. Per the proposal, operators 
would remediate any moderate or severe coating damage issues identified 
by such an assessment, which, was defined as where there are voltage 
drops of greater than 35 percent for DCVG or 50 dB[mu]V for ACVG.
---------------------------------------------------------------------------

    \23\ ``Holidays'' are essentially holes or gaps in the coating 
film that exposes the pipeline to corrosion. The inspections of 
pipeline coating through electronic defect detectors is commonly 
also referred to as ``jeeping.''
---------------------------------------------------------------------------

    Section 192.461 prescribes requirements for protective coating 
systems. PHMSA notes that pipe coating can disbond \24\ from the pipe 
and shield the pipe from CP. The NTSB determined that this was a 
significant contributing factor in the major crude oil spill that 
occurred near Marshall, MI, in 2010. As a result, PHMSA determined that 
additional requirements are needed to specify that coating should not 
impede cathodic protection. Further, and as discussed above, PHMSA 
determined that additional requirements are needed so that operators 
verify that pipeline coating systems for protection against external 
corrosion have not become compromised or damaged during the 
installation and backfill process performed during maintenance, 
repairs, or pipe replacement.\25\
---------------------------------------------------------------------------

    \24\ Disbonding is the failure of a coating to adhere to the 
underlying substance to which it was applied. Specific to pipelines, 
it is a loss of adhesion between the cathodic coating and the pipe 
due to a corrosive reaction taking place.
    \25\ This is similar to a proposal in Sec.  192.319 for new 
construction.
---------------------------------------------------------------------------

    In the NPRM, PHMSA proposed to revise Sec.  192.461(a) to require 
that pipelines have sufficient coating to protect against damage from 
being handled. PHMSA also proposed to add Sec.  192.461(f) to require 
operators to perform an above-ground coating survey within 3 months of 
placing the pipeline into service and require operators to repair 
moderate or severe coating damage within 6 months of the assessment.
2. Summary of Public Comment
    Stakeholders representing the public, including NAPSR and the PST, 
generally agreed with and supported the revisions to this section, 
stating that such requirements would increase safety and were a good 
step towards reducing the number of incidents that occur due to 
corrosion. Many commenters stated that ACVG/DCVG surveys are not always 
feasible and that PHMSA should not limit the tools for performing 
coating surveys to the two types specified in Sec. Sec.  192.319 and 
192.461(f). For example, INGAA stated that PHMSA did not provide 
justification for requiring coating surveys, such as ACVG and DCVG, to 
be used to detect coating issues after construction or after performing 
a repair or replacement. INGAA further stated that PHMSA should allow 
operators to use other assessment technologies, such as close interval 
surveys (CIS) and high- resolution geometry ILI inspection tools, to 
detect and manage post-construction, post-repair, and post-replacement 
conditions that contribute to external corrosion.
    AGA and AGL Resources (now Southern Company Gas) commented that 
depth of cover and excessive pavement can make indirect surveys 
impossible. Further, AGA stated that while conducting post-construction 
surveys is industry best practice, activities that are not always 
feasible for operators to complete should not be codified within the 
regulations.
    NACE expressed concern that ACVG and DCVG surveys do not address 
the stated goal of identifying coatings that impede cathodic protection 
and objected to setting specific thresholds for these tests. Similarly, 
INGAA stated that if the requirements for operators to perform coating 
surveys using ACVG and DCVG are finalized, the proposed voltage drop 
threshold value in Sec.  192.461(f) should be eliminated.
    Industry commenters also stated objections or suggested limitations 
to the timeframe proposed in Sec.  192.461(f) regarding when these 
surveys should be performed, stating that the 3-month timeline is 
inconsistent with the 1-year period allowed to install cathodic 
protection after the construction of a

[[Page 52236]]

pipeline in existing Sec.  192.455(a)(2). New Jersey Natural Gas 
expressed concern that 3 months may not be adequate both to procure 
qualified personnel and to perform these surveys and have a fully 
mature cathodic protection system to perform a successful coating 
assessment. NAPSR believed that, unless there was a technical reason 
for the 3-month deadline for the surveys, the timeline might be too 
conservative due to service procurement and seasonal conditions. 
Therefore, they recommended extending the assessment deadline.
    API and Enterprise Products commented that PHMSA does not provide 
any supporting evidence that backfilling a ditch for an onshore 
transmission pipeline is, or has been, an issue meriting the need for 
ACVG or DCVG surveys to assess coating integrity. Further, API and 
Southern California Gas Company stated that Sec.  192.319(a) already 
requires all operators of transmission gas pipelines to ``protect the 
pipe coating from damage,'' either in initial installation, or any time 
the pipe is exposed and backfill material is added. Therefore, the 
proposed provisions may be duplicative with Sec.  192.461.
    At the GPAC meeting on June 6 and 7, 2017, committee members 
representing the industry echoed many of the comments received, noting 
also that ACVG and DCVG surveys may not address issues related to 
coatings impeding CP. Additionally, some of these members noted that 
coating surveys are not always feasible, and that PHMSA should not 
limit the tools for performing such surveys. Further, several GPAC 
members representing the industry suggested that PHMSA should not set 
specific repair thresholds in the regulations, and that the provisions 
do not align with current NACE standards.\26\ Certain committee members 
also recommended applying a greater-than-1000-feet standard for this 
provision, which would match a proposed requirement for external 
corrosion control under Sec.  192.461 and thought that the timeline for 
the above-ground coating survey should be extended from 3 months to 1 
year to synchronize with current CP installation requirements. The 
committee also suggested PHMSA clarify the applicability of these 
provisions is limited to transmission pipelines.
---------------------------------------------------------------------------

    \26\ When the ANPRM was being developed, NACE did have standards 
for ACVG/DCVG surveys. Since the development of this final rule, 
NACE has subsequently revised those standards, and there is no 
longer a standard for these surveys.
---------------------------------------------------------------------------

    Therefore, the committee voted 10-0 that these provisions proposed 
at Sec. Sec.  192.319 and 192.461 were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA: (1) raised the 
repair threshold from ``moderate'' to ``severe'' indications, (2) 
modified the requirements to apply to segments greater than 1,000 feet 
in length to be consistent with other similar corrosion control 
requirements, (3) extended the assessment and remediation timeframe to 
6 months after a pipeline is placed into service and made allowances 
for delayed permitting, (4) adjusted the recordkeeping requirements so 
that operators would be required to make and retain for the life of the 
pipeline records documenting indirect assessment findings and remedial 
actions, and (5) provided flexibility for the use of alternative 
technology unless the agency objected.
3. PHMSA Response
    Operators have historically assumed that coating is functioning as 
intended after construction. However, the NTSB report on the Enbridge 
crude oil accident near Marshall, MI, identified shielded CP due to 
disbonded coating as being a contributing cause of the failure. 
Whenever an operator backfills a pipeline, there is the potential for 
coating damage. PHMSA believes that conducting coating surveys after 
backfill is a reasonable and reliable way for operators to identify 
coating damage inflicted during the construction process before 
significant corrosion occurs. This is a means for an operator to 
confirm, after pipeline construction or replacement, that the pipe 
coating is not compromised and is functioning as intended.
    PHMSA believes that ACVG/DCVG surveys are currently the best and 
most reliable means of detecting coating damage following construction, 
as opposed to a CIS survey, which is a complementary survey employed to 
assess the performance of CP systems. However, PHMSA desires to promote 
the development of new technologies and methods and acknowledges that 
other technology could be used for performing coating assessments. 
Therefore, in this final rule, PHMSA is allowing an operator to notify 
PHMSA of the intent to use other technology, which it may use unless an 
objection is received, as was recommended by the GPAC. PHMSA's review 
of such notification would evaluate whether an operator has 
demonstrated that the ``other technology'' provides equivalent 
protection to public safety and the environment compared the existing 
technologies contemplated by this final rule. As a part of its 
evaluation, PHMSA considers whether there are technical papers from 
standard developing organizations that support the use of the new 
technology, as well as any research that has been conducted on that 
technology and any usage of the technology in other industries and non-
regulated pipelines.
    PHMSA disagrees that the voltage drop threshold value used as the 
remediation criterion should be eliminated from the regulation but does 
agree that the values in the proposed revisions to Sec. Sec.  192.319 
and 192.461 in the NPRM were conservative as they would indicate 
``moderate'' coating damage. Therefore, in this final rule and as 
recommended by the GPAC, PHMSA is specifying the voltage drop threshold 
value associated with a ``severe'' indication of coating damage as 
recommended by GPAC.
    As recommended by the GPAC, PHMSA is persuaded that the 3-month 
proposed timeline may not be practical in all situations and has 
modified the final rule to allow operators up to 6 months after the 
pipeline is placed into service to complete the necessary assessments 
and remediation (with allowance for time required to obtain permits, if 
required). PHMSA has also included a requirement for the associated 
recordkeeping requirements of these provisions that includes the 
editorial changes recommended by the GPAC; specifically, that operators 
must make and retain for the life of the pipeline records documenting 
the indirect assessment findings and remedial actions.
    PHMSA also modified both sections to apply to segments greater than 
1,000 feet in length to be consistent with other corrosion control 
requirements that were similarly altered in this final rule. PHMSA 
notes that the application of these requirements to segments greater 
than 1,000 feet in length is also consistent with conditions that have 
been applied in several special permit applications.
    As a part of the requirements for these sections, PHMSA has 
provided in the regulatory text that the applicable coating surveys 
must be conducted, except in locations where effective coating surveys 
are precluded by geographical, technical, or safety reasons.\27\ These 
might include crossings of major interstates or rivers. An operator 
must document, in accordance with a technically proven

[[Page 52237]]

analysis, any decision made not to perform such a coating survey.
---------------------------------------------------------------------------

    \27\ For example, coating surveys could require drilling holes 
in roadways, or digging up pipe--each of which entail their own 
risks to public safety and the environment. Some of the pipelines 
that would be surveyed could either be cased or have thick-walls, 
further complicating efforts to conduct coating surveys.
---------------------------------------------------------------------------

    As noted before, PHMSA did not intend for these provisions to apply 
to gathering or distribution pipelines, and it has clarified the 
applicability of these provisions to transmission lines only. However, 
PHMSA may expand the application of these provisions in a future 
rulemaking.

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

iii. Interference Surveys--Sec.  192.473
1. Summary of PHMSA's Proposal
    Interference currents occur when metallic structures pick up a 
stray electrical current from elsewhere and discharge the current, 
thereby causing corrosion. These currents can negate the effectiveness 
of cathodic protection systems. The sources of stray current problems 
are commonplace; they can result from other underground facilities, 
such as the cathodic protection systems from crossing or parallel 
pipelines, light rail systems, commuter train systems, high-voltage 
alternating current (HVAC) electrical lines, or other sources of 
electrical energy in proximity to the pipeline. Stray current corrosion 
is electrochemical corrosion that occurs when potential differences 
between a high-conductivity steel pipeline and lower-conductivity 
environments causes the stray current to flow through the pipe and 
create a corrosion cell. If stray current or interference issues are 
not remediated, accelerated corrosion could occur and potentially 
result in a leak or rupture. Section 192.473 prescribes general 
requirements to minimize the detrimental effects of interference 
currents. However, specific requirements to monitor and mitigate 
detrimental interference currents have not been prescribed in subpart I 
of part 192. Therefore, in the NPRM, PHMSA proposed to explicitly 
require operators to conduct interference surveys and remediate adverse 
conditions in a timely manner. Specifically, PHMSA proposed to amend 
Sec.  192.473 to require that an operator's program include 
interference surveys to detect the presence of interference currents 
and take remedial actions within 6 months of completing the survey. 
Additionally, PHMSA proposed to require in Sec.  192.473 that operators 
perform periodic interference surveys whenever needed.
2. Summary of Public Comment
    Generally, stakeholders representing the public agreed with and 
supported the revisions to this section, noting that the requirements, 
as proposed, could help reduce the number of pipeline incidents caused 
by corrosion. Numerous trade associations and pipeline companies were 
concerned about the proposed requirements for interference surveys 
under Sec.  192.473. Commenters, including Atmos Energy Corporation and 
AGA, expressed doubt regarding the ability of individual operators to 
obtain the necessary information from electric transmission providers. 
APGA and INGAA urged PHMSA to limit this new requirement to specific 
transmission lines, such as those pipelines subject to the threat of 
stray electric current. Commenters, including INGAA, also stated that 
the provisions should allow for the phased-in implementation of 
remediation measures and provided timeframes from 12 to 18 months. Some 
commenters suggested a lengthened implementation period for this 
requirement due to the potential difficulties in obtaining the proper 
permits.
    At the GPAC meeting on June 7, 2017, certain committee members 
believed that these requirements should apply only to lines that are 
subject to stray current risks and noted that interference surveys 
might not be feasible depending on the information operators can obtain 
from electricity transmission companies. Committee members also 
suggested a phased-in compliance period between 12 and 18 months for 
these requirements, and noted, similarly to the proposed external 
corrosion provisions, that the remediation period did not account for 
activities like obtaining the necessary permits. There was also 
extensive discussion at the meeting regarding PHMSA's proposed use of 
the word ``significant'' in context of the level of corrosion that 
would need to be remediated, with several committee members suggesting 
that phrase be tied to a numeric threshold for easier compliance. The 
committee also discussed, at length, what PHMSA's expectation for a 
remediation ``plan'' is and what the necessary paper trail would look 
like for compliance.
    After discussion, the committee voted 9-0 that the provisions for 
external corrosion interference currents are technically feasible, 
reasonable, cost-effective, and practicable if PHMSA clarified that the 
surveys are required for lines subject to stray currents and updated 
the remediation timeframe to require operators create a remediation 
procedure and apply for necessary permits within 6 months and complete 
remediation activities within 12 months with allowances for delayed 
permitting. The committee also specifically recommended that PHMSA 
clarify that operators must take remedial action when the interference 
is at a level that could cause significant corrosion as being 100 amps 
per meter squared, or if it impedes the safe operating pressure of the 
pipeline, or if it may cause a condition that would adversely affect 
the environment or the public.
3. PHMSA Response
    PHMSA agrees with commenters that every pipeline segment is not 
equally subject to stray current. Therefore, in this final rule, PHMSA 
is modifying Sec.  192.473 as recommended by the GPAC to clarify that 
interference surveys are required when electric potential monitoring 
indicates a significant increase in stray current, or new potential 
stray current sources are introduced. Additionally, PHMSA recognizes 
the need for objective remediation criteria and has included the 
criteria recommended by the GPAC, specifically ``greater than or equal 
to 100 amps per meter squared or if it impedes the safe operation of a 
pipeline or may cause a condition that would adversely impact the 
environment or the public.'' PHMSA has also revised this final rule to 
establish a remediation timeframe of 15 months, with allowance for 
delayed permitting, as recommended by the GPAC.

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

iv. Internal Corrosion--Sec.  192.478
1. Summary of PHMSA's Proposal
    Section 192.477 prescribes requirements to monitor internal 
corrosion by coupon testing or other means if corrosive gas is being 
transported. However, the regulation is silent on standards for 
determining whether corrosive gas is being transported or regarding any 
changes occurring that could introduce corrosive contaminants in the 
gas stream. The existing regulations also do not prescribe that 
operators continually or periodically monitor the gas stream for the 
introduction of corrosive constituents through system changes, changing 
gas supply, abnormal conditions, or other changes. This could result in 
pipelines that are not monitored for internal corrosion because an 
initial assessment did not identify the presence of corrosive gas.
    As such, PHMSA determined that additional requirements are needed 
to ensure that operators effectively monitor gas stream quality to 
identify if and when corrosive gas is being transported and to mitigate 
deleterious gas stream constituents such as contaminants or

[[Page 52238]]

liquids. In the NPRM, PHMSA proposed to add a new Sec.  192.478 to 
require onshore gas transmission pipeline operators monitor for 
deleterious gas stream constituents and evaluate gas monitoring data 
quarterly. The proposed Sec.  192.478 would also add a requirement for 
onshore gas transmission pipeline operators to review their internal 
corrosion monitoring and mitigation program semi-annually and adjust 
the program as necessary to mitigate the presence of deleterious gas 
stream constituents. These requirements would be in addition to the 
existing requirements to check coupons or perform other measures to 
monitor for the presence of internal corrosion when transporting a 
known corrosive gas.
2. Summary of Public Comment
    NAPSR generally agreed with and supported the addition of this 
section. They did note, however, that PHMSA should consider the 
applicability of these requirements to pipelines that are transporting 
dry, tariff-quality gas. The PST noted that these proposed requirements 
in this section provided an enforceable mechanism to hold operators 
accountable for future incidents caused by internal corrosion.
    Multiple commenters considered the proposed changes to requirements 
for internal corrosion control in Sec.  192.478 to be overly 
prescriptive, particularly regarding gas monitoring and the list of 
corrosive constituents. INGAA stated that transmission operators are 
already taking comprehensive steps to address internal corrosion under 
subparts I and O of part 192 and that proposed Sec.  192.478 should be 
eliminated for this reason. Atmos Energy Corporation and INGAA asserted 
that the internal corrosion monitoring timeline proposed in Sec.  
192.478(d) is unreasonable and too frequent, particularly for pipeline 
systems that are not susceptible to internal corrosion. They further 
stated that mitigation of internal corrosion is necessary only if a 
pipeline is transporting, or has the potential to transport, corrosive 
gas. At the GPAC meeting on June 6, 2017, committee members 
representing the industry supported those comments made by Atmos Energy 
Corporation and INGAA.
    Commenters at the GPAC meeting, including committee members, noted 
that some distribution operators rely on upstream transmission pipeline 
gas suppliers to monitor gas quality and do not own any gas monitoring 
equipment. A committee member noted that if pipeline operators are 
getting gas from native sources, gathering lines, or underground 
storage fields, it might be necessary to determine the quality of the 
gas. Another committee member noted that there are tariffs that prevent 
certain quantities of constituents that could be internally corrosive 
from entering a transmission system. That commenter also noted that 
operators continually monitor for internal corrosion on pipelines 
transporting tariff-quality gas as a part of IM.
    GPAC members also noted that PHMSA should consider harmonizing 
these requirements with the existing corrosion control monitoring 
requirements, as they appeared to be duplicative in certain areas.
    After discussing the provisions, the committee voted 10-0 that the 
proposed provisions related to internal corrosion were technically 
feasible, reasonable, cost-effective, and practicable if PHMSA limited 
the applicability of the requirements to those pipelines that are 
transporting corrosive gas and provided additional guidance based on 
the committee discussion; changed the reference from the use of ``gas-
quality monitoring equipment'' to ``gas-quality monitoring methods;'' 
specified types of technologies operators can use to mitigate 
potentially corrosive gas streams; and changed the frequency of the 
monitoring and program review requirements from twice per year to once 
per calendar year, not to exceed 15 months. The committee also 
specifically recommended deleting language that was duplicative to 
existing requirements and instead recommended PHMSA cross-reference 
those existing requirements in this section.
3. PHMSA Response
    PHMSA noted during the GPAC meeting, that, in its experience, 
transmission pipeline operators measure the quality of the gas coming 
into their transmission systems. Based on the quality of the gas, 
transmission pipeline operators are paying suppliers for the gas they 
receive or are receiving money for the gas they deliver. Therefore, 
PHMSA assumes transmission pipeline operators have monitoring systems 
for the quality of the gas entering their systems. PHMSA's intent with 
the proposed revision of this section was to help ensure that operators 
were getting that data to the necessary people in their organization. 
For instance, if an organization's accountants are getting gas quality 
data due to their work with tariffs, the personnel responsible for 
operations and integrity management should get that data.
    Based on the comments received, PHMSA is revising the scope of 
proposed Sec.  192.478 in this final rule to limit its applicability to 
the transportation of corrosive gas and is modifying the proposed 
language in paragraph (b)(1) to specify that operators perform 
monitoring at points where gas with potentially corrosive contaminants 
enters the pipeline. To address concerns regarding the monitoring 
frequency, PHMSA is changing the requirement from twice per year to 
once per calendar year, not to exceed 15 months. Making such a change 
is more consistent with the timeframes for similar requirements in the 
regulations as revised by this rulemaking and implements the 
recommendation made by the GPAC.
    Further, to harmonize this rule with other rule requirements, PHMSA 
is deleting proposed paragraph (c), since Sec.  192.477 currently 
requires the monitoring of internal corrosion. To address comments 
regarding technology, PHMSA revised paragraph (b)(2) to read 
``Technology to mitigate the potentially corrosive gas stream 
constituents. Such technologies may include product sampling and 
inhibitor injections.''
    There have been instances where operators do transport corrosive 
gas by pipeline without investigating the possibility of corrosive 
effect of the gas on its pipeline and taking steps to minimize internal 
corrosion.\28\ This has happened after operators have withdrawn gas 
from storage facilities (e.g., caverns) where the gas that was injected 
became corrosive over time because of properties of the storage 
facilities. Therefore, there can be scenarios where corrosive gas can 
enter a pipeline system even if the gas being delivered into the 
upstream system is non-corrosive.
---------------------------------------------------------------------------

    \28\ In the Matter of Transcontinental Gas Pipe Line Company, 
LLC, CPF 1-2018-1005, available at https://primis.phmsa.dot.gov/comm/reports/enforce/documents/120181005/120181005_Final%20Order_06192019.pdf (last visited March 27, 2020). 
On December 12, 2016, Transcontinental Gas Pipe Line Company 
reported an explosion and fire that severely damaged a portion of 
one of its facilities and station piping, resulting in an estimated 
$15 million in damage. The root cause was determined to be internal 
corrosion caused by salt water produced from a storage field during 
gas withdrawal.
---------------------------------------------------------------------------

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

v. Cathodic Protection--Sec.  192.465 & Appendix D
1. Summary of PHMSA's Proposal
    Appendix D to part 192, ``Criteria for Cathodic Protection and 
Determination of Measurements,'' which is referenced in Sec.  
192.465(f), specifies requirements for CP of steel, cast iron, and 
ductile pipelines. Appendix D has not been updated since 1971. The NPRM

[[Page 52239]]

proposed to update appendix D by eliminating outdated guidance on CP 
and the interpretation of voltage measurement to better align with 
current standards and PHMSA's understanding of current industry 
practice.
    Section 192.465 currently prescribes that operators monitor CP and 
take prompt remedial action to correct deficiencies indicated by the 
monitoring. The provisions in Sec.  192.465 do not specify the remedial 
actions required to correct deficiencies and do not define ``prompt.'' 
To address this gap, the NPRM proposed to amend Sec.  192.465(d) to 
require that operators must complete remedial action promptly, but no 
later than the next monitoring interval specified in Sec.  192.465, or 
within 1 year, whichever is less. Additionally, new paragraph (f) 
proposed to add requirements for onshore gas transmission pipeline 
operators to perform CIS if annual test station readings indicate CP is 
below the level of protection required in subpart I. Unless it is 
impractical to do so, PHMSA proposed to require that operators complete 
CIS with the protective current interrupted. Whereas ACVG and DCVG are 
performed at the time of construction, before electrical current is on 
the pipe for CP, a CIS requires the pipe to be in the ground with the 
rectifiers installed. A CIS will discover areas of low current where CP 
might be weakened and can discover additional construction, operational 
or environmental damage along the pipeline when performed as a post-
construction task. The NPRM's proposed revisions to Sec.  192.465 would 
also require each operator to take remedial action to correct any 
deficiencies indicated by the CIS.
2. Summary of Public Comment
    NAPSR and the PST generally agreed with and supported the revisions 
to Sec.  192.465. NAPSR believed that the inclusion of a timeframe for 
operators to perform CIS and perform subsequent mitigation measures 
would increase pipeline safety but noted that PHMSA should provide 
further guidance on the intervals at which operators should perform the 
surveys. Both PST and NAPSR supported the revisions to appendix D.
    Several industry entities commented on the proposed revisions to 
appendix D to part 192. INGAA stated that the proposed remaining 
criteria in appendix D for determining the adequacy of cathodic 
protection are too narrow, and that all industry standards provide for 
additional methods of assessing voltage drop. These commenters 
recommended that PHMSA follow the applicable paragraphs of NACE 
Standard Practice SP0169. Enterprise noted that appendix D should be 
consistent with Sec.  195.571, which outlines the criteria that 
hazardous liquid pipeline operators must use when determining the 
adequacy of cathodic protection.
    Commenters stated that the proposed changes to appendix D, as 
written, would apply to distribution pipelines as well as transmission 
pipelines and expressed concern that PHMSA has offered neither 
justification nor an estimate of the impact on distribution systems. 
These commenters requested that PHMSA clarify that the proposed changes 
to appendix D apply only to transmission pipelines.
    Commenters, including committee members representing the industry 
during the meeting on June 6, 2017, stated that PHMSA should amend 
Sec.  192.465 to include a more realistic timeframe for remedial 
action, specifically noting that the timeframe for remediation does not 
account for difficulties in obtaining the necessary permits. 
Additionally, commenters and GPAC committee members stated this 
provision could lead to unnecessary and costly work, as there are 
various situations that can produce a low CP reading that do not 
require CIS for the identification of the root cause. Those commenters 
stated there are certain conditions that do not require CIS and 
recommended allowing operators to identify, troubleshoot, and remediate 
these certain conditions on their own without the need to conduct CIS.
    Further, GPAC members representing the industry disagreed with 
PHMSA's proposed revisions to the appendix D criteria for determining 
the adequacy of cathodic protection. Like their commentary on other 
provisions, these committee members also noted that the impact of these 
changes to distribution pipelines was not justified or analyzed, and 
therefore, distribution pipelines should be exempt from the proposed 
requirements.
    Following their discussion, the committee voted 10-0 that the 
provisions related to the CP of steel, cast iron, and ductile pipelines 
were technically feasible, reasonable, cost-effective, and practicable 
if PHMSA clarified that the new requirements in Sec.  192.465(d) only 
apply to gas transmission pipelines and withdrew the proposed revisions 
to appendix D. The committee also recommended that PHMSA address 
situations where CIS may not be an effective response by instead 
requiring operators investigate and mitigate any non-systemic or 
location-specific causes of corrosion and require CIS if operators need 
to address systemic causes of corrosion. Additionally, the committee 
recommended PHMSA address its comments regarding the timeframe by which 
the proposed provisions would need to be completed by requiring 
operators make a remedial action plan and apply for any necessary 
permits within 6 months and finish the remedial action within 1 
calendar year, not to exceed 15 months, or as soon as practicable once 
the operator obtains the necessary permits.
3. PHMSA Response
    PHMSA intended that the amendments proposed in the NPRM would apply 
only to transmission pipelines and has, in this final rule, added the 
phrase ``onshore gas transmission pipelines'' to Sec.  192.465(d)(1) of 
to clarify that limitation. PHMSA will consider expanding application 
beyond onshore gas transmission pipelines in the future. PHMSA believes 
that modifying the timeline for remediation is appropriate, and 
therefore, is requiring operators develop a remedial action plan and 
apply for the necessary permits within 6 months of the inspection, with 
the completion of remediation activities to be completed prior to the 
next monitoring interval or within 1 year, not to exceed 15 months. 
Like the previous section, such a change is consistent with both the 
GPAC recommendation on the issue and the timeframes for the related 
regulations in this final rule. PHMSA understands that, in almost all 
cases where an operator performs an excavation of 1,000 feet or more, 
that excavation will probably require some permits. An operator should 
obtain such permits in a manner to allow the performance of coating 
surveys and any necessary repairs to the coating.
    In the NPRM, PHMSA proposed to update appendix D but did not intend 
to introduce any new requirements. PHMSA agrees with certain commenters 
that the proposed revisions could have unintended consequences by 
creating potential tension with analogous cathodic protection 
evaluation criteria in NACE Standard Practice SP0169 and Sec.  195.571 
governing hazardous liquid lines (which section incorporates NACE 
Standard Practice SP0169 by reference). However, as PHMSA did not 
propose incorporation by reference of NACE Standard Practice SP0169 in 
appendix D, PHMSA is withdrawing the proposed changes to appendix D. 
PHMSA will continue to examine appropriate evaluation criteria for 
catholic protection of gas transmission pipelines and may pursue future 
rulemaking on

[[Page 52240]]

this topic. These changes to the final rule for CP requirements are in 
accordance with the GPAC recommendations.

C. Corrosion Control--Sec. Sec.  192.319, 192.461, 192.465, 192.473, 
192.478, and 192.935 and Appendix D

vi. P&M Measures--Sec.  192.935(f) & (g)
1. Summary of PHMSA's Proposal
    Currently, the gas transmission IM provisions do not explicitly 
address additional P&M measures for the threats of external and 
internal corrosion. For the same reasons that apply to the proposed 
changes for general corrosion control as discussed above, PHMSA 
proposed to address these gaps for HCAs. PHMSA determined that 
additional P&M measures are needed in Sec.  192.935(f) and (g) to 
assure that public safety is enhanced in HCAs through additional 
protections from the time-dependent threats of internal and external 
corrosion. Specifically, PHMSA proposed to add Sec.  192.935(f) and 
(g), which would require that operators enhance their corrosion control 
programs in HCAs to provide additional corrosion protections in 
addition to the proposed standards in subpart I. Under proposed Sec.  
192.935(f), operators would be required to enhance their internal 
corrosion management programs by performing mitigative actions if 
deleterious gas stream constituents are being transported and through 
performing semi-annual reviews of their programs.
    Regarding the internal corrosion provisions discussed earlier in 
this document, Sec.  192.477 prescribes requirements to monitor 
internal corrosion by coupon testing or other means if corrosive gas is 
being transported. However, the existing regulations do not prescribe 
that operators continually or periodically monitor the gas stream for 
the introduction of corrosive constituents through system changes, 
changing gas supply, abnormal conditions, or other changes. This could 
result in pipelines that are not monitored for internal corrosion 
because an operator's initial assessment did not identify the presence 
of corrosive gas. To provide additional protections for HCAs in 
addition to the standards proposed in subpart I, PHMSA proposed that 
Sec.  192.935(f) would require operators use specific gas quality 
monitoring equipment for HCA segments, including but not limited to, a 
moisture analyzer, chromatograph, samplers for carbon dioxide, and 
samplers for hydrogen sulfide. The proposed provisions would also 
require operators sample at a certain frequency, use cleaning pigs to 
sample accumulated liquids and solids, and use corrosion inhibitors 
when corrosive constituents are present. PHMSA also proposed the 
maximum amounts of carbon dioxide, moisture content, and hydrogen 
sulfide that would require operator action.
    Under proposed Sec.  192.935(g), operators would also be required 
to enhance their external corrosion management programs, including 
controlling both alternating and direct electrical interference 
currents, confirming external corrosion control through indirect 
assessment, and controlling external corrosion through CP.
    As described in the discussion on interference surveys above, 
interference currents can negate the effectiveness of CP systems. 
Section 192.473 prescribes general requirements to minimize the 
detrimental effects of interference currents. In the NPRM, PHMSA 
proposed to amend Sec.  192.473 to require that an operator's corrosion 
control program include interference surveys to detect the presence of 
interference currents and require the operator take remedial actions 
within 6 months of completing the survey. In HCAs, PHMSA proposed 
additional prescriptive requirements in Sec.  192.935(g) to afford 
extra protections for HCAs, including a maximum interval of 7 years for 
an operator to perform interference surveys; more specificity regarding 
the survey performance, including technical acceptance criteria; and a 
requirement that pipe-to-soil test stations be located at half-mile 
intervals within each HCA segment with at least one station in each 
HCA, if practicable.
    Lastly, PHMSA proposed to make conforming edits to appendix E, 
which provides guidance for P&M measures for HCA segments subject to 
subpart O. PHMSA proposed to accommodate the proposed revised 
definition for ``electrical survey'' by replacing that term with 
``indirect assessment'' to accommodate other techniques in addition to 
CIS.
2. Summary of Public Comment
    NAPSR and the PST agreed with and supported the proposed changes to 
the P&M measures for addressing internal and external corrosion in HCAs 
and suggested strengthening the proposed provisions further.
    While trade associations and individual operators supported certain 
aspects of the proposed provisions covering the P&M measures addressing 
external corrosion and internal corrosion in HCAs, these commenters 
objected to the specific requirements in Sec.  192.935. Many of these 
commenters stated a preference for allowing operators the flexibility 
to implement corrosion control based on their own judgment of the 
severity of the threat. In general, many industry commenters stated 
that individual sections of the proposed provisions were too broad and 
prescriptive, and pipeline operators would incur greater costs without 
justified benefit. Further, they stated that the monitoring frequency 
of twice per year was too frequent. Some commenters recommended that 
PHMSA reference ASME standards for implementing P&M measures, and other 
commenters stated concern that some of the proposed provisions are not 
consistent with NACE standards.
    Many commenters objected to several of the proposed aspects of 
internal corrosion control, such as the identification of threats, 
monitoring, and filtering, and these commenters stated that operators 
should have flexibility in implementing P&M measures. For example, 
INGAA opposed the proposed requirement in Sec.  192.935(f) that 
requires operators to install continuous gas quality monitoring 
equipment at all points in which gas with potentially deleterious 
contaminants enters the pipeline. INGAA recommended that Sec.  
192.935(f) apply only to pipeline segments with a history of internal 
corrosion and stated that this would be consistent with the required 
risk analysis that operators perform to determine whether P&M measures 
are necessary. Similarly, Atmos Energy recommended that gas sources be 
monitored only at those sources suspected, in the judgment of the 
operator, of having deleterious gas stream constituents, and that such 
monitoring can be performed in real-time or periodically. INGAA stated 
that PHMSA should modify proposed Sec.  192.935(g) to require that 
operators conduct periodic indirect inspections only where a pipeline 
segment has a known history of corrosion.
    During the GPAC meeting on June 6, 2017, committee members 
representing the industry reiterated that Sec.  192.935(f) and (g) were 
too broad and prescriptive and should not apply to every HCA pipeline 
segment indiscriminately. These members, echoing comments made by 
INGAA, stated that operators should use their risk assessments to be 
used to determine which specific P&M measures are needed in accordance 
with the current IM approach.
    The committee also suggested that PHMSA should reference specific 
ASME standards for P&M measures and ensure they are consistent with 
NACE

[[Page 52241]]

standards. Members representing the public suggested PHMSA review the 
proposed changes throughout subpart I and ensure that they would be as 
enforceable as the proposed P&M measures if the P&M measures were to be 
deleted. Members also discussed the fact that distribution operators do 
not always have gas monitoring equipment for their lines, as they 
depend on the suppliers to monitor the gas quality.
    Following the discussion, the committee voted 9-1 (with a 
representative from PST dissenting) that the proposed rule, regarding 
the provisions for P&M measures for internal and external corrosion, 
were technically feasible, reasonable, cost-effective, and practicable 
if PHMSA withdrew the specific provisions discussed in Sec.  192.935(f) 
and (g) and appendix E, as the requirements would have been duplicative 
with subpart I.
3. PHMSA Response
    PHMSA noted during the GPAC meeting that it was persuaded by 
commenters that the changes it is making to the general corrosion 
control requirements in subpart I in this final rule are sufficient and 
that the additional regulations proposed in Sec.  192.935(f) and (g) 
and appendix E were duplicative. The proposed changes to subpart I that 
PHMSA is finalizing in this rulemaking apply to pipelines in both HCAs 
and non-HCAs, and they were similar to the P&M measures that PHMSA was 
proposing regarding corrosion control in HCAs specifically. Therefore, 
PHMSA believes that the changes to subpart I in this rule provide the 
safety that the proposed changes at Sec.  192.935(f) and (g) intended 
to provide. The proposed changes to appendix E incorporated the 
proposed definition for ``electrical survey'' and did not contain 
further substantive changes. After considering those comments, and as 
recommended by the GPAC, PHMSA is withdrawing all the proposed changes 
to Sec.  192.935(f) and (g) and appendix E.

D. Inspections Following Extreme Weather Events--Sec.  192.613

1. Summary of PHMSA's Proposal
    Weather events and natural disasters that can cause river scour, 
soil subsidence or ground movement may subject pipelines to additional 
external loads, which could cause a pipeline to fail. These conditions 
can pose a threat to the integrity of pipeline facilities if those 
threats are not promptly identified and mitigated. While the existing 
regulations provide for design standards that consider the load that 
may be imposed by geological forces, weather events and natural 
disasters can quickly impact the safe operation of a pipeline and have 
severe consequences if not mitigated and remediated as quickly as 
possible.
    In the NPRM, PHMSA proposed revising Sec.  192.613 to require that 
an operator inspect all potentially affected pipeline facilities after 
an extreme weather event to help ensure that no conditions exist that 
could adversely affect the safe operation of that pipeline. The 
operator would be required to consider the nature of the event and the 
physical characteristics, operating conditions, location, and prior 
history of the affected pipeline in determining the appropriate method 
for performing the inspection required. The NPRM's proposed revisions 
to Sec.  192.613 also provided that the initial inspection must occur 
within 72 hours after the cessation of the event, defined as the point 
in time when the affected area can be safely accessed by available 
personnel and equipment required to perform the inspection. If an 
operator finds an adverse condition, the NPRM' s proposed revisions to 
Sec.  192.613 would require an operator to take appropriate remedial 
action to ensure the safe operation of a pipeline based on the 
information obtained because of performing the inspection.
2. Summary of Public Comment
    The PST, NAPSR, and EnLink Midstream supported the proposed 
amendments to Sec.  192.613, with many other stakeholders supporting 
the intent of the proposed provisions but requesting further 
clarification on some of the terms used within the proposal.
    Some commenters expressed concern with the broad requirements of an 
``inspection'' and requested PHMSA clarify what an inspection following 
an extreme weather event would entail. Additionally, these stakeholders 
stated that the proposed definition of an extreme weather event was 
vague and requested clarification. INGAA stated that operators are 
already required to have procedures to ensure a prompt and effective 
response to emergency conditions through Sec.  192.615 and suggested 
that to avoid duplicative regulation, PHMSA should instead modify Sec.  
192.615(a)(3) to incorporate additional specificity on weather events 
that may trigger a response.
    Many commenters objected to the proposed timeframe, stating that 
the 72-hour requirement listed in the rule could be problematic. 
Commenters stated that PHMSA should allow operators to determine when 
an impacted area can be safely accessed, and that pipeline operators 
are best positioned to evaluate the balance between the safety and the 
need for inspections to ensure continued safe operation of their 
systems. INGAA stated that the 72-hour requirement should either be 
replaced with a more general statement such as ``as soon as 
practicable,'' or that PHMSA should create a process to request an 
exception to the requirement. Louisiana Mid-Continent Oil and Gas 
Associations stated that extreme weather events vary significantly by 
region and commented that not all local geography and extreme weather 
events are the same. They further stated that the 72-hour deadline for 
inspection may be too prescriptive depending on the extreme weather 
event. They stated that because Louisiana is subjected to many unusual 
extraordinary events, such as spillway openings, high/low river flows, 
and rainwater flooding, PHMSA should clarify what ``other events'' 
means and how the cessation of an event is determined.
    At the GPAC meeting of January 12, 2017, members noted concerns 
with the provisions as proposed but voted 12-0 that the provisions were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA modified the proposed rule to clarify that the timing for this 
provision is to begin after the operator has made a reasonable 
determination that the area is safe, clarify in the preamble that 
operators are encouraged to consult with pipeline safety and public 
safety officials in order to make such determinations, delete the 
phrase ``whichever is sooner'' at the end of Sec.  192.613(c)(2), and 
change the word ``infrastructure'' to ``facilities.''
3. PHMSA Response
    PHMSA agrees that an operator's ability to inspect a pipeline 
facility following an extreme weather event may vary greatly depending 
on the type of extreme weather event that has taken place and the 
specific location of the event. The NPRM's proposed revisions to Sec.  
192.613 would require operators to inspect its pipeline facilities 
after the cessation of an extreme weather event. Cessation of the event 
was defined as the point of time when the affected area could be safely 
accessed by the personnel and equipment, including availability of 
personnel and equipment, required to perform the inspection. However, 
in consideration of the comments received, PHMSA is persuaded that 
additional clarification is warranted and that 72 hours after the 
cessation of the event may not be enough time in all cases for operator 
personnel and equipment to assess and inspect a pipeline safely.

[[Page 52242]]

    Therefore, as recommended by the GPAC, PHMSA has modified this 
final rule to require an operator perform an initial inspection 72 
hours after the operator reasonably determines that the affected area 
can be safely accessed by personnel and equipment, and the necessary 
personnel and equipment required to perform such an inspection are 
available. PHMSA encourages operators to consult with pipeline and 
public safety officials, including the appropriate PHMSA regional 
office, when making these determinations. If an operator is unable to 
commence the inspection in the 72-hour timeframe due to the 
unavailability of personnel or equipment, the operator must notify the 
appropriate PHMSA Region Director as soon as practicable.
    If an operator finds an adverse condition, the operator must take 
appropriate remedial action to ensure the safe operation of a pipeline 
based on the information obtained from the inspection. Such actions 
might include, but are not limited to:
     Reducing the operating pressure or shutting down the 
pipeline;
     Isolating pipelines in affected areas and performing 
``stand up'' leak tests;
     Modifying, repairing, or replacing any damaged pipeline 
facilities;
     Preventing, mitigating, or eliminating any unsafe 
conditions in the pipeline rights-of-way;
     Performing additional patrols, depth of cover surveys and 
adding cover over the pipeline, ILI or hydrostatic tests, or other 
inspections to confirm the condition of the pipeline and identify any 
imminent threats to the pipeline;
     Implementing emergency response activities with Federal, 
State, or local personnel; and
     Notifying affected communities of the steps that can be 
taken to ensure public safety.
    PHMSA would not expect operators to comply with these provisions 
for weather or other disruptive events when, considering the physical 
characteristics, operating conditions, location, and prior history of 
the affected system, the event would not be expected to impact the 
integrity of the pipeline. For example, extreme weather events would 
not include rain events that do not exceed the high-water banks of the 
rivers, streams or beaches in proximity to the pipeline; rain events 
that do not result in a landslide in the area of the pipeline; storms 
that do not produce winds at tropical storm or hurricane level 
velocities; or earthquakes that do not cause soil movement in the area 
of the pipeline.
    PHMSA is also modifying Sec.  192.613(c) introductory text and 
(c)(1) as the GPAC recommended, by removing the phrase ``whichever is 
sooner'' and replacing the term ``infrastructure'' with ``facilities.'' 
As discussed during the GPAC meeting, ``pipeline facilities'' is a 
defined term at Sec.  192.3, and the use of that term will likely 
provide additional clarity.

E. Strengthening Requirements for Assessment Methods--Sec. Sec.  
192.923(b) & (c), 192.927, 192.929

i. Internal Corrosion Direct Assessment (ICDA)--Sec. Sec.  192.923(b) & 
192.927
1. Summary of PHMSA's Proposal
    The current regulations do not specify the quality and 
effectiveness of ICDA. NACE International submitted a petition for 
rulemaking on February 11, 2009, requesting that PHMSA address this 
issue. In the NPRM, PHMSA proposed amendments to Sec. Sec.  192.923(b) 
and 192.927 to incorporate by reference NACE SP0206-2006 and further 
supplement the NACE standard to address issues observed by PHMSA.
    For indirect inspections, PHMSA proposed to require that operators 
use pipeline-specific data, exclusively in performing an indirect 
inspection, and that the use of assumed pipeline or operational data 
would be prohibited. PHMSA also proposed operators be required to 
consider the accuracy, reliability, and uncertainty of data used to 
make calculations regarding the critical inclination angle of liquid 
holdup and the inclination profile of pipelines. Further, PHMSA 
proposed that operators be required to select locations for direct 
examination and establish the extent of pipe exposure needed, to 
explicitly account for these uncertainties and their cumulative effect 
on the precise location of predicted liquid dropout.
    For detailed examinations as defined in NACE SP0206-2006, PHMSA 
proposed to require that operators identify a minimum of two locations 
for excavation within each covered segment associated with the ICDA 
Region and perform a detailed examination for internal corrosion at 
each location using ultrasonic thickness measurements, radiography, or 
other generally accepted measurement techniques. One required location 
would be the low point within the covered segment nearest to the 
beginning of the ICDA Region. The second required location would be 
near the end of the ICDA Region within the covered segment. If 
corrosion was found at any location, the operator would be required to 
evaluate the severity of the defect, expand the detailed examination 
program to determine all locations that have internal corrosion within 
the ICDA region, and expand the detailed examination program to 
evaluate the potential for internal corrosion in all pipeline segments 
(both covered and non-covered) with similar characteristics to the ICDA 
Region in the operator's pipeline system.
    For post-assessment evaluation and monitoring, PHMSA proposed to 
require that operators evaluate the effectiveness of ICDA as an 
assessment method for addressing internal corrosion and determining 
whether a covered segment should be reassessed at more frequent 
intervals than those currently specified in the regulations at Sec.  
192.939. PHMSA also proposed to require that operators validate their 
flow modeling calculations by comparing locations of discovered 
internal corrosion with locations predicted by the model. Additionally, 
PHMSA proposed to require that operators continually monitor each ICDA 
Region that contains a covered segment where internal corrosion was 
identified and by periodically drawing off liquids at low points and 
chemically analyzing the liquids for the presence of corrosion 
products.
    Finally, PHMSA proposed to require that operators include in their 
plans the criteria used in making key decisions in implementing each 
stage of the ICDA process and provisions that the analysis be carried 
out on the entire pipeline in which covered segments are present.
2. Summary of Public Comment
    NAPSR expressed its agreement with, and support for, the proposed 
revisions to Sec. Sec.  192.923(b) and 192.927. Multiple pipeline 
operators and industry trade associations commented that the proposed 
provisions should simply incorporate the NACE standard by reference, 
and should not exceed those established industry standards, be rigidly 
prescriptive, or otherwise be mandatory. PG&E, commenting on the 
incorporation of standards by reference, requested PHMSA replace the 
phrase ``as required by'' with ``in accordance with'' so that operators 
can meet the substantial requirement but have flexibility in the 
implementation of that requirement if the industry publishes new 
techniques to perform ICDA. NACE International expressed its belief 
that, as described in NACE SP0206-2006, ICDA is an acceptable 
standalone methodology for assessing pipeline integrity.
    Atmos Energy commented that the proposed mandated monitoring for 
all ICDA regions would be potentially excessive and recommended that 
PHMSA delete the proposed language and restore the current language at

[[Page 52243]]

Sec.  192.927(c)(4)(ii).\29\ Another commenter recommended that PHMSA 
remove the proposed notification requirement prior to an operator 
performing an ICDA, noting that operators currently provide this 
information as part of other annual reporting.
---------------------------------------------------------------------------

    \29\ PHMSA regulations at Sec.  192.927(c)(2) define an ICDA 
region as a continuous length of pipe (including weld joints), 
uninterrupted by any significant change in water or flow 
characteristics, that includes similar physical characteristics or 
operating history. An ICDA region extends from the location where 
liquid may first enter the pipeline and encompasses the entire area 
along the pipeline where internal corrosion may occur until a new 
input introduces the possibility of water entering the pipeline.
---------------------------------------------------------------------------

    At the GPAC meeting on December 15, 2017, the GPAC committee voted, 
13-0, to revise Sec. Sec.  192.923(b)(2) and (3) and 192.927 according 
to the recommendations by PHMSA staff at the meeting, which included 
supplementing the NACE standard with additional requirements to address 
specific issues that could adversely affect ICDA results.
3. PHMSA Response
    PHMSA believes that it is appropriate to address ICDA by 
incorporating by reference the NACE standard and supplementing it with 
additional requirements pertaining to indirect inspections (a step in 
the NACE standard's ICDA process to help in determining where direct 
assessments need to be made), detailed examinations, and post-
assessments. For indirect inspections, PHMSA has implemented additional 
requirements regarding the data an operator must use and accounting for 
uncertainties in that data. Where an indirect inspection demonstrates 
that detailed examinations are needed, PHMSA is expanding the 
examinations that an operator must perform to evaluate for the 
potential for internal corrosion in all pipeline segments if corrosion 
is found in the ICDA region. Regarding post-assessments, PHMSA is 
requiring operators to evaluate the effectiveness of ICDA as an 
assessment method and determine whether a covered segment should be 
reassessed more frequently than the intervals specified at Sec.  
192.939. Additionally, PHMSA is requiring operators validate the flow 
modelling calculations they use in the ICDA process as well as 
continually monitor each ICDA region that contains a covered segment 
where internal corrosion has been identified.
    When the first IM regulations were promulgated in the 2003 IM rule, 
there was no consensus industry standard for ICDA that could be adapted 
or incorporated into the regulations to promote better pipeline safety 
regarding internal corrosion. Incorporating by reference the NACE 
standard into the regulations would improve pipeline safety because the 
NACE standard (1) typically requires more direct examinations than the 
current regulatory requirements; (2) encompasses the entire pipeline 
segment and requires that all inputs and outputs be evaluated; and (3) 
is considered by many to be an equivalent or superior indirect 
inspection model compared to the Gas Technology Institute (GTI) model 
currently referenced in Sec.  192.927. Its range of applicability with 
respect to operating pressure is greater than the GTI model, thus 
allowing the use of ICDA in pipelines with lower operating pressures 
and higher flow velocities.
    The existing requirements in Sec.  192.927 have one aspect that has 
proven problematic: the definition of regions and requirements for 
selection of direct examination locations in the regulations are tied 
to the covered segment. A ``covered segment'' is defined in Sec.  
192.903 as ``a segment of gas transmission pipeline located in a high 
consequence area.'' The terms ``gas'' and ``transmission line'' are 
defined in Sec.  192.3. Therefore, covered segment boundaries are 
determined by population density and other consequence factors without 
regard to the orientation of the pipe and the presence of locations at 
which corrosive agents may be introduced or may collect and where 
internal corrosion would most likely be detected (e.g., low spots). 
Section 192.927 requires that locations selected for excavation and 
detailed examination be within covered segments, meaning that the 
locations at which internal corrosion would most likely be detected may 
not be examined. Thus, the existing requirements do not always 
facilitate the discovery of internal corrosion that could affect 
covered segments. PHMSA is addressing this problem in this final rule 
by incorporating NACE SP0206-2006 and by expanding the detailed 
examination program, whenever internal corrosion is discovered, to 
determine all locations that have internal corrosion within the ICDA 
region.
    PHMSA believes requiring a notification requirement for operators 
is important so that PHMSA can review the specific proposal to use a 
standard to assess pipe segments that are explicitly excluded from the 
scope of the standard. PHMSA has also revised Sec.  192.927(c) to 
clarify that an operator must conduct the ICDA process ``in accordance 
with'' the NACE standard to avoid the implication that all non-
mandatory recommendations contained in the standard are required.

E. Strengthening Requirements for Assessment Methods--Sec. Sec.  
192.923(b) & (c), 192.927, 192.929

ii. Stress Corrosion Cracking Direct Assessment (SCCDA)--Sec. Sec.  
192.923 & 192.929
1. Summary of PHMSA's Proposal
    The current regulations do not specify a number of issues that 
affect the quality and effectiveness of SCCDA integrity assessments. 
Specifically, Appendix A3 of ASME/ANSI B31.8S, which is referenced in 
the regulations, provides some guidance for conducting SCCDA, but the 
guidance is limited to stress corrosion cracking (SCC) that occurs in 
high-pH environments. NACE International submitted a petition for 
rulemaking to PHMSA on February 11, 2009, requesting that PHMSA address 
this issue by incorporating by reference NACE SP0204-2008, which 
addresses near-neutral SCC in addition to high-pH SCC. Accordingly, in 
the NPRM, PHMSA proposed changes to Sec. Sec.  192.923 and 192.929 to 
incorporate by reference NACE SP0204-2008 and supplement the NACE 
standard to address issues observed by PHMSA in the areas of data 
gathering and integration, indirect inspection, direct examinations, 
remediation and mitigation, and post-assessments.
    PHMSA proposed to require an operator's SCCDA plan to evaluate the 
effects of a carbonate-bicarbonate environment; the effects of cyclic 
loading conditions on the susceptibility and propagation of SCC in both 
high-pH and near-neutral-pH environments; the effects of variations in 
applied CP, such as overprotection, CP loss for extended periods, and 
high negative potentials; the effects of coatings that shield CP when 
disbonded from the pipe; and other factors that affect the mechanistic 
properties associated with SCC.
    For indirect inspections, PHMSA proposed to require an operator's 
plan include provisions for conducting at least two above-ground 
surveys using complementary measurement tools most appropriate for the 
pipeline segment based on the data gathered.
    For direct examinations, PHMSA proposed to require an operator's 
procedures provide for conducting a minimum of three direct 
examinations within the SCC segment at locations determined to be the 
most likely for SCC to occur.
    For post-assessments, PHMSA proposed to require that the operator's 
procedures include the development of a reassessment plan based on the

[[Page 52244]]

susceptibility of the operator's pipe to SCC as well as on the 
mechanistic behavior of identified cracking.
2. Summary of Public Comment
    Multiple commenters supported the proposed changes to Sec.  192.929 
for SCCDA. NAPSR expressed its agreement with, and support of, these 
revisions. Spectra Energy Partners (SEP), which merged with Enbridge in 
2017, provided comments in support of the proposed inclusion of 
explicit requirements for SCCDA. SEP expressed its belief that SCCDA is 
a diligent, practicable approach for assessments for SCC for cases 
where the pipeline has not previously experienced an in-service failure 
caused by SCC and provided specific edits to make the proposed 
requirements for SCCDA clearer and more practicable. A commenter 
recommended that the requirements for SCCDA specify that an operator is 
required to conduct assessments in areas that are most likely to be 
subject to SCC regardless of HCA designation.
    Several other commenters questioned or opposed the proposed changes 
to Sec.  192.929. Several commenters, including API, expressed their 
support of NACE standards SP0204-2008 for SCCDA but recommended that 
PHMSA not exceed those established industry standards and should not 
make the recommendations within those standards mandatory. NACE 
International stated it was unaware of any conclusive data regarding 
overprotection or high-negative potentials as a factor in SCC of 
pipelines, which is what the NPRM's proposed revisions to Sec.  192.929 
suggested. Additionally, NACE International commented that PHMSA went 
beyond the practices stated in NACE Standard SP0204-2008 by proposing 
to require a minimum of two above-ground surveys and three direct 
examinations.
    INGAA proposed to clarify the way in which SCCDA can be used as an 
IM method, asserting that SCCDA is a valid method to assess SCC threats 
in gas pipeline segments that are susceptible to, but have no history 
of, SCC.
    Other commenters provided specific technical comments regarding 
these proposed provisions. TransCanada asserted that applying the NACE 
``significant SCC'' definition as the threshold for immediate repair is 
both overly conservative and overly complicated, and they suggested 
that PHMSA instead adopt the threshold of ``noteworthy'' as defined in 
ASME STP-PT-011.
    Enable Midstream Partners (EMP) agreed that operators should 
consider the specific factors PHMSA proposed in Sec.  192.929(b)(1) and 
(4) as part of the data gathering and integration and post-assessment 
remediation and mitigation process for SCCDA. However, EMP asserted 
that PHMSA should clarify these sections by including a referenced 
standard that provides guidance to operators on how they should 
consider these specific factors. Another commenter stated that PHMSA 
should include a reference to ASME/ANSI B31.8S, Appendix A3, for 
susceptibility criteria.
    Commenters also suggested that PHMSA allow operators to use sound 
engineering judgments when calculating the remaining strength of the 
pipeline segment if the segment is subject to the pipeline material 
properties and attributes verification requirements of Sec.  192.607 
and those requirements have not yet been met.
    At the GPAC meeting on December 15, 2017, the committee recommended 
PHMSA revise the approach proposed in the NPRM by making the changes to 
these provisions that were recommended by PHMSA staff during the 
meeting, which were to replace the spike hydrostatic pressure test 
requirements with a reference to Sec.  192.506(e) to eliminate 
redundancy; address the gap pertaining to failure pressure calculations 
when data is not available; codify, as applicable, the expectation that 
the recommendations within the NACE standard are not mandatory; 
communicate additional guidance as needed during rule implementation; 
and consider how to structure the rule to apply results from non-HCAs 
to HCAs.
3. PHMSA Response
    When the first IM rule was promulgated in 2003, there was no NACE 
standard for SCCDA. Additionally, the requirements pertaining to SCC in 
ASME/ANSI B31.8S, Appendix B, only applied to pipe susceptible to high 
pH SCC (i.e., pipelines susceptible to near-neutral SCC were not 
addressed). Therefore, PHMSA believes that incorporating by reference 
the NACE standard and supplementing it with additional requirements to 
address issues it has observed related to data gathering and 
integration, indirect inspection, direct examinations, remediation and 
mitigation, and post-assessments, is an appropriate way to address 
SCCDA.
    For data gathering and integration, PHMSA is requiring that 
operators gather and evaluate data related to SCC at all sites an 
operator excavates while conducting its pipeline operations where the 
criteria in NACE SP0204-2008 indicate the potential for SCC. Per this 
final rule, operators must additionally analyze the effects of a 
carbonate-bicarbonate environment, cyclic loading conditions, 
variations in applied CP, the effects of coatings that shield CP when 
disbonded from the pipe, and other factors that would affect the 
mechanics of SCC. For indirect inspections, PHMSA is requiring 
operators conduct at least two above-ground surveys using the 
measurement tools most appropriate for the pipeline segment based on an 
evaluation of the collected data. An operator's plan for direct 
examination must include a minimum of three direct examinations within 
the SCC segment at the locations where SCC would be most likely to 
occur. If an operator finds any indication of SCC in a segment, an 
operator must perform specific mitigation measures. Further, in this 
final rule, an operator must develop procedures for post-assessments 
based on the susceptibility of the pipeline segment to SCC as well as 
the mechanical behavior of identified cracking. Regarding EMP's comment 
stating that PHMSA should provide guidance to operators on how they 
should consider specific factors as a part of the data gathering and 
integration process by referring to a standard incorporated by 
reference within PHMSA regulations, as well as the comment recommending 
that PHMSA incorporate a reference to ASME/ANSI B31.8S, Appendix A3, 
for susceptibility criteria, PHMSA declines to incorporate by reference 
such standards because it could limit operators from considering all of 
the factors that they should.
    PHMSA also agrees with commenters that referring to Sec.  192.506, 
Transmission lines: Spike hydrostatic pressure test, in Sec.  192.929 
is preferred instead of repeating the spike hydrostatic test 
requirements and has changed this final rule accordingly. PHMSA 
addressed the comment about determining predicted failure pressure when 
needed data are not available by referencing Sec.  192.712, which 
explicitly provides an operator with conservative assumptions and 
alternatives for material toughness values, material strength, and pipe 
dimensions and other data, in lieu of documented material properties.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

    PHMSA identified several improvements to the IM repair criteria 
based on its experience gained since the IM rule became effective in 
2004; ongoing research and development, including developments in ASME/
ANSI B31.8S; and investigations into recent incidents. In the NPRM, 
PHMSA

[[Page 52245]]

proposed adjustments to the existing repair criteria for anomalies 
discovered in HCAs and proposed new repair criteria for anomalies found 
outside of HCAs.\30\
---------------------------------------------------------------------------

    \30\ The GPAC voted on each section of the repair criteria 
separately, and each section is discussed in more detail below.
---------------------------------------------------------------------------

F. Repair Criteria--Sec. Sec.  192.714, 192.933

i. Repair Criteria in HCAs--Sec.  192.933
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add more immediate repair conditions 
and more 1-year repair conditions for HCA pipeline segments in Sec.  
192.933. The specific anomalies and repair schedules for cracks, dents, 
and corrosion metal loss are discussed in their respective sections 
below. In certain cases, like for SCC and selective seam weld corrosion 
anomalies that were new to the repair criteria, PHMSA proposed to 
require that operators repair ``any indication of '' such anomalies. In 
other cases, such as for dents, PHMSA did not make significant changes 
to the existing repair criteria at Sec.  192.933, which require the 
repair of ``any indication of '' metal loss, cracking, or a stress 
riser.
2. Summary of Public Comment
    Public advocacy groups, including Pipeline Safety Coalition, the 
PST, and Clean Water for North Carolina, supported the proposed 
provisions that would strengthen the existing repair criteria at 
Sec. Sec.  192.713 (non-HCAs) and 192.933 (HCAs). Additionally, NAPSR 
and the NTSB supported PHMSA's proposed repair criteria revisions.
    There was common agreement from pipeline operators and the industry 
trade associations that the processes for HCA repairs and non-HCA 
repairs should be standardized. However, the trade associations and 
pipeline operators generally believed that the proposed provisions at 
Sec. Sec.  192.713 and 192.933 were too prescriptive and would impede 
operators from performing repairs based on risks. They further stated 
that the proposed provisions do not take into consideration other 
factors that operators currently consider when optimizing plans to 
remediate anomalies, such as historical data, geography, and congestion 
of the right-of-way.
    Some of the commenters representing the industry recommended PHMSA 
eliminate all references to the words ``any indication of '' within the 
proposed revisions to Sec. Sec.  192.713 and 192.933 when applied to 
anomalies needing repair so that it is the confirmed presence of a 
condition that requires a repair instead. These commenters stated that 
requiring operators to repair an ``indication of '' certain anomalies 
would cause needless repairs and misallocate resources. Spectra Energy 
stated that PHMSA's annual report data indicates that only one repair 
is required for every three anomaly investigations, which demonstrates 
that the existing anomaly response criteria operators have implemented 
are appropriately conservative.
3. PHMSA Response
    Based on PHMSA's annual report data, the number of immediate 
repairs have remained relatively constant even though the baseline 
assessment period has concluded. PHMSA understands that this is likely 
the result of operators deferring repair of non-immediate conditions 
until the defect progresses into an immediate repair condition, rather 
than immediate conditions arising spontaneously. PHMSA understands that 
most defects that become immediate repair conditions are observable by 
ILI equipment well in advance of progression to an immediate repair 
condition. The repair criteria in this final rule are intended to 
assure that anomalies are repaired before they become an immediate 
condition and are at or near failure. In this final rule, PHMSA has 
included reference to ASME/ANSI B31.8S within each of Sec. Sec.  
192.714 and 192.933 to take into consideration other factors that 
operators currently consider when establishing remediation plans.
    In this final rule, PHMSA has removed the proposed repair criteria 
under Sec. Sec.  192.714 (non-HCAs) and 192.933 (HCAs) for SCC and 
selective seam weld corrosion, which were new repair criteria that 
contained the phrase ``any indication of.'' PHMSA combined SCC and 
selective seam weld corrosion repair criteria into a more general 
cracking repair criteria because each of these phenomena is, or results 
in, cracking. PHMSA included remediation measures for SCC under the 
requirements at Sec.  192.929, which are the requirements for using 
direct assessment for SCC but did not require the remediation of ``any 
indication of '' SCC. PHMSA was not proposing to change any of the 
existing repair criteria that referenced ``any indication of,'' such as 
that for dents with any indication of metal loss, cracking, or a stress 
riser. Those repair criteria remain unchanged in this final rule.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

ii. Repair Criteria in Non-HCAs--Sec.  192.714
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed at Sec.  192.713 repair criteria for 
non-HCA areas to assure that operators promptly repair injurious 
defects that are discovered outside of HCAs. These proposed repair 
criteria for non-HCAs were based on, and were similar, to, the repair 
criteria (regarding structure, anomaly types, and the repair 
timeframes) for HCA pipeline segments proposed at Sec.  192.933.
    For those anomalies for which a 1-year response is required on HCA 
pipeline segments, PHMSA proposed that a 2-year response would be 
required in non-HCA pipeline segments. This proposal would require 
operators to remediate anomalous conditions on gas transmission 
pipeline segments promptly and commensurate with the risk they present, 
while allowing operators to allocate their resources to those anomalies 
in HCAs that present a higher risk.
    The specific anomalies and repair schedules for cracks, dents, and 
corrosion metal loss are discussed in their respective sections below.
2. Summary of Public Comment
    Citizen groups, including Pipeline Safety Coalition, the PST, and 
Clean Water for North Carolina, supported the proposed provisions that 
would strengthen the repair criteria for HCAs and non-HCAs. 
Additionally, NAPSR and the NTSB supported PHMSA's revisions to the 
repair criteria.
    Generally, the industry trade associations and pipeline operators 
supported PHMSA's intention of establishing repair criteria outside of 
HCAs but disagreed with some of the specific provisions. There was 
common agreement, however, that the processes for HCA repairs and non-
HCA repairs should be standardized.
    The trade associations and pipeline operators generally believed 
that the proposed provisions were too prescriptive and would impede 
operators from performing repairs based on risks. They further stated 
that the proposed provisions do not take into consideration other 
factors that operators currently consider when optimizing plans to 
remediate anomalies, such as historical data, geography, and congestion 
of the right-of-way.
    AGA recommended that PHMSA create a new subpart to address 
assessment requirements outside of

[[Page 52246]]

HCAs and add a section within that subpart to cover repair criteria. 
Several other trade associations and pipeline operators echoed AGA's 
recommendations.
    Several industry commenters also stated that the rulemaking did not 
demonstrate that the safety benefit of strengthened repair criteria 
outweighs the costs. Multiple operators stated that the proposed repair 
provisions in Sec.  192.713 would increase the number of digs operators 
would need to perform and asserted that the increased number of digs 
may not improve pipeline safety.
    Certain commenters suggested that it would not be appropriate for 
PHMSA to require operators to repair immediate conditions in non-HCAs 
before repairing immediate conditions in HCAs, and that PHMSA should 
require operators to prioritize those conditions discovered within HCAs 
if operators discover multiple immediate conditions in HCAs and non-
HCAs simultaneously. More specifically, AGA requested that the rule 
explicitly prioritize immediate conditions within HCAs over immediate 
conditions in other locations when conditions are discovered 
simultaneously and recommended that PHMSA adopt different terminology 
for ``immediate repair conditions'' inside and outside HCAs. Similarly, 
other industry trade organizations expressed concern that the proposed 
provisions for non-HCAs would complicate the allocation of resources to 
HCAs on a higher-priority basis when confronted with the large number 
of new, non-HCA pipelines needing assessments.
    Commenters also requested PHMSA make the sections pertaining to 
non-HCA repairs and HCA repairs consistent regarding pressure 
reductions. Commenters representing the industry noted that, as 
proposed, certain notification requirements for long-term pressure 
reductions or for those operators unable to respond within the given 
timeframe were different depending on whether the pipeline was in an 
HCA or a non-HCA. These commenters suggested that those notification 
procedures be made consistent, wherever possible, between the HCA and 
non-HCA repair criteria. Multiple trade associations and pipeline 
industry entities also expressed concerns that the proposed provisions 
requiring ``an operator to reduce the operating pressure of its 
affected pipeline until it can remediate the immediate repair 
conditions'' are unnecessarily conservative. INGAA asserted that the 
proposed pressure reduction requirements for non-HCAs are more 
stringent than the pressure reductions requirements for HCAs, and 
several commenters offered alternative methods for determining 
appropriate operating pressure reductions. Specifically, these 
commenters requested PHMSA allow operators to take a pressure reduction 
other than 80 percent if they documented the analysis performed and 
assumptions used. These commenters claimed that, as proposed in the 
NPRM, operators were allowed to use a different pressure reduction in 
HCAs if an analysis supported it but were not allowed to do so in non-
HCAs.
    During its meeting in late March 2018, the GPAC recommended PHMSA 
clarify that pressure reductions would be required for immediate 
conditions in non-HCAs and in cases where repair schedules could not be 
met. As a part of this recommendation, the GPAC also recommended that 
operators notify PHMSA when they could not meet the schedule for 
anomaly evaluation and remediation or when a temporary pressure 
reduction exceeds 365 days. The GPAC also recommended that PHMSA should 
allow operators to calculate pressure reductions (following the 
discovery of repairable conditions) by using either class location 
factors, or 80 percent of the operating pressure, or 1.1 times the 
predicted failure pressure. The GPAC also recommended PHMSA require 
that operators document and keep records, for 5 years, of the 
calculations and decisions used to determine such pressure reductions 
and the implementation of the actual reduced operating pressure. 
Further, the GPAC recommended PHMSA avoid duplicating language 
regarding the need for repairs and pressure reductions found in other 
sections of the regulations.
3. PHMSA Response
    In the 2019 Gas Transmission Rule, PHMSA promulgated new 
requirements for operators to conduct integrity assessments in areas 
outside of HCAs, including all Class 3 and Class 4 locations and the 
newly defined ``moderate consequence areas'' (MCA) that are piggable. 
This new requirement was in response to the congressional mandate in 
the 2011 Pipeline Safety Act (Pub. L. 112-90) to expand IM or elements 
of IM beyond HCAs. The non-HCA repair criteria PHMSA is issuing in this 
final rule are the companion requirements to those assessments and are 
necessary to extend the assessment and repair program elements of IM 
effectively to areas beyond HCAs. Although PHMSA agrees that this 
requirement will likely result in additional repairs, PHMSA believes it 
is necessary and important to assure that injurious defects are 
remediated before they lead to loss of pipeline integrity.
    Commenters requested that the non-HCA repair criteria be split out 
from the general non-IM repair provisions that previously existed in 
the regulations. PHMSA determined that the non-HCA repair criteria 
would be clearer and easier to comply with if they were in a distinct 
section, and PHMSA has created a new Sec.  192.714 with all of the non-
HCA repair criteria.
    To the comments that suggested that a different schedule be created 
for immediate conditions within HCAs and non-HCAs, PHMSA believes that 
the existing approach used in subpart O for HCAs is better because the 
identification of anomalies based on ILI results is an actionable 
indication that there might be an injurious defect in the pipeline. 
Establishing repair criteria based on operators discovering these 
actionable anomalies assures that the anomaly is investigated promptly 
and repaired, if necessary. PHMSA believes it is prudent for an 
operator to perform any necessary repairs once the operator has 
excavated the pipe and exposed the anomaly for field investigation, 
instead of deferring the repairs. Although PHMSA agrees that defects in 
HCAs, if they were to fail, could result in higher consequences, PHMSA 
reminds readers that ASME/ANSI B31.8S, section 7.2, defines an 
immediate condition as an ``indication show[ing] that [a] defect is at 
failure point.'' PHMSA believes that any indication of a pipe that is 
at the point of failure needs to be addressed immediately, and as such, 
for both HCAs and non-HCAs, operators must reduce pressure and 
immediately remediate the anomaly.
    PHMSA agrees with several commenters and the GPAC recommendations 
for consistently addressing pressure reductions for repairs for both 
HCA and non-HCA pipeline segments. PHMSA believes that pressure 
reductions are needed for immediate conditions and when repair 
schedules cannot be met and has incorporated pressure reductions for 
non-HCA pipelines that are like the existing requirements for HCAs in 
subpart O, which include the operator notifying PHMSA. PHMSA also 
agrees that the amount of the pressure reduction should be established 
to be 80 percent of the operating pressure at the time of discovery of 
the defect, or the predicted failure pressure divided by 1.1, or the 
predicted failure pressure times the design factor for the class 
location in which the affected pipeline is located, and that records 
for such pressure reductions must be kept for a minimum of 5 years. 
PHMSA

[[Page 52247]]

incorporated these provisions, as recommended by the GPAC, in Sec.  
192.714(e) for non-HCA pipelines. Further, PHMSA followed the GPAC 
recommendation for reducing duplicative language regarding repairs and 
pressure reductions and has streamlined this final rule accordingly.
    PHMSA also notes that AGA suggested creating a new subpart for non-
HCA assessments and repairs. Although PHMSA has not created a new 
subpart, PHMSA believes it has accomplished the same purpose by putting 
the new non-HCA assessment and repair requirements in separate, 
distinct sections.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

iii. Cracking Criteria--Sec. Sec.  192.714(d)(1)(v) & 192.933(d)(1)(v)
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add criteria to address cracking and 
crack-like defects, including SCC, because the existing regulations 
have no explicit repair criteria for those types of critical defects. 
The cracking criteria would apply to both HCAs and non-HCAs, but they 
would require repair at different size thresholds and at different 
timeframes depending on the anomaly location.
    Following the Enbridge incident near Marshall, MI, the NTSB 
recommended that PHMSA revise the hazardous liquid regulations at Sec.  
195.452 to state clearly: (1) when an engineering assessment of crack 
defects, including environmentally assisted cracks, must be performed; 
(2) the acceptable methods for performing these engineering 
assessments, including the assessment of cracks coinciding with 
corrosion with a safety factor that considers the uncertainties 
associated with sizing of crack defects; (3) criteria for determining 
when a probable crack defect in a pipeline segment must be excavated 
and time limits for completing those excavations; (4) pressure 
restriction limits for crack defects that are not excavated by the 
required date; and (5) acceptable methods for determining crack growth 
for any cracks allowed to remain in the pipe, including growth caused 
by fatigue, corrosion fatigue, or SCC as applicable.\31\ Although the 
recommendation was limited to hazardous liquid pipelines, the issue 
applies equally to gas transmission pipelines, as SCC can occur on 
these pipelines as well.
---------------------------------------------------------------------------

    \31\ NTSB Recommendation P-12-3, available at https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003.
---------------------------------------------------------------------------

    Therefore, in the NPRM, PHMSA proposed to allow operators to use an 
engineering critical assessment (ECA) to evaluate indications of SCC. 
If the SCC was ``significant,'' it would be categorized as an 
``immediate'' repair condition. If the SCC was not ``significant,'' it 
would be categorized as a ``1-year'' condition. Further, PHMSA proposed 
to adopt the definition of significant SCC from the consensus industry 
standard NACE SP0204-2008. PHMSA also proposed that an operator could 
not use an ECA to justify not remediating any known indications of SCC.
    The current regulations also do not have repair criteria for seam 
cracks or crack-like flaws. Current regulations also fail to address 
corrosion affecting a longitudinal seam and selective seam weld 
corrosion, which are time-sensitive integrity threats that behave like 
cracks and are categorized as crack-like defects. In the NPRM, PHMSA 
proposed to address these gaps by including repair criteria for cracks 
and crack-like flaws in Sec.  192.933 and proposed similar criteria in 
Sec.  192.713.
2. Summary of Public Comment
    INGAA, API, and Piedmont strongly opposed the proposed provisions 
in Sec.  192.713(d)(1)(v), that stated ``any indication of significant 
SCC'' constitutes an immediate repair condition. Commenters requested 
that PHMSA determine the repair condition of cracks and crack-like 
defects according to factors that capture the severity of the defect, 
such as predicted failure pressures or maximum depth. Many commenters 
believed that PHMSA's proposed criteria were too conservative and 
suggested the repair criteria be for anomalies with a crack depth of 
greater than 70 percent of the pipe wall thickness or with a predicted 
failure pressure of less than 1.1 times MAOP. Other commenters 
suggested PHMSA delete the definitions of specific significant crack 
defects and use the alternative cracking criterion proposed by PHMSA at 
the GPAC meeting on March 2, 2018.
    INGAA recommended making the repair criteria for cracking 
consistent with the repair criteria for metal loss and suggested that 
PHMSA consider anomalies with a crack depth of 80 percent wall 
thickness as immediate conditions for this reason. INGAA also 
recommended that PHMSA adopt a failure pressure ratio approach for 
cracking.
    Certain commenters noted that the classification of all cracks or 
crack-like defects as 2-year repair conditions was overly conservative 
and suggested PHMSA relax that requirement. For example, some 
commenters suggested requiring repairs at 50 percent crack depth or a 
predicted failure pressure of less than 1.25 times MAOP.
    At the GPAC meeting, for the proposed repair criteria for cracks, 
members representing the industry stated PHMSA's criteria for the 
immediate repair of certain crack defects were too conservative and 
suggested establishing an immediate repair threshold for cracks up to 
70 percent of wall thickness or those with a predicted failure pressure 
of less than 1.1 times MAOP rather than those cracks with a predicted 
failure pressure of less than 1.25 times MAOP. Members representing the 
public noted that public safety would be better served by the threshold 
for immediate crack repairs being more conservative but questioned 
whether the more stringent threshold would be practical.
    Similarly, members representing the industry suggested that PHMSA's 
proposed criteria for 1-year and 2-year scheduled conditions were too 
conservative as well and suggested setting the relevant criteria as 
those cracks with a depth of 50 percent wall thickness or those cracks 
with a predicted failure pressure of less than 1.25 times MAOP. Members 
representing the industry also suggested that, in addition to relaxing 
the criteria for immediate cracks, PHMSA should also add language 
requiring operators to consider tool tolerance and other factors when 
examining crack growth rates. Further, members representing the 
industry suggested that PHMSA base the repair criteria on design 
conditions or design factors rather than class location factors. 
Committee members also suggested that PHMSA cross-reference specific 
regulatory language rather than repeat the text in full in other 
sections of the code.
    Following the discussion, the committee voted 12-0 that, as 
published in the Federal Register, the provisions in the proposed rule 
and draft regulatory evaluation for cracking repair criteria were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA: (1) struck the proposed definitions of ``significant seam 
cracking'' and ``significant stress corrosion cracking,'' (2) deleted 
the phrase ``any indication of'' from the repair criteria related to 
cracking, (3) combined the criteria for SCC and seam cracking, (4) 
required that operators calculate predicted failure pressures for all 
time-dependent cracking anomalies by using the fracture mechanics

[[Page 52248]]

procedure PHMSA developed, (5) revised the definition of ``hard spot'' 
as discussed,\32\ and (6) considered specific crack repair criteria as 
immediate conditions. Those specific crack repair criteria for 
immediate conditions would include (1) crack depth plus corrosion 
greater than 50 percent of pipe wall thickness; (2) crack depth plus 
any corrosion is greater than the inspection tool's maximum measurable 
depth; or (3) the crack anomaly is determined to have a predicted 
failure pressure that is less than 1.25 times MAOP.
---------------------------------------------------------------------------

    \32\ This is discussed more under the ``Definitions'' subsection 
of this section.
---------------------------------------------------------------------------

3. PHMSA Response
    In this final rule, PHMSA did not adopt the proposed definitions of 
``significant seam cracking'' and ``significant stress corrosion 
cracking.'' With the revisions to the cracking repair criteria, these 
definitions weren't necessary. Similarly, with the deletion of the 
proposed repair criteria using those specific definitions, the 
recommendation for deleting the phrase ``any indication of'' from those 
criteria, became moot. Further, PHMSA's revisions to the cracking 
repair criteria also made the recommendation for PHMSA to combine the 
proposed SCC criteria and the seam cracking criteria moot.
    PHMSA believes that the repair criteria it proposed in the NPRM for 
cracks are consistent with research findings and provides an adequate 
safety margin while accounting for the severity of the defects through 
the analysis of the predicted failure pressure.\33\ PHMSA believes the 
repair criteria for cracks that were suggested by some of the 
commenters would not provide an adequate safety margin due to factors 
including the accuracy of tool results, varying pipe toughness, and 
pressure cycling. This was discussed at length by the GPAC, who 
ultimately recommended that anomalies be classified as immediate 
conditions where the crack depth plus corrosion is greater than 50 
percent of pipe wall thickness, compared to certain commenters who 
suggested that cracks with a depth of up to 70 percent pipe wall 
thickness be classified as immediate conditions.
---------------------------------------------------------------------------

    \33\ See ASME, ``STP-PT-0011:Integrity Management of Stress 
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008). 
See also Young, B.A., et al., ``Comprehensive Study to Understand 
Longitudinal ERW Seam Failures'' (2017), available at https://primis.phmsa.dot.gov/matrix/PrjHome.rdm?prj=390. Both papers call 
for anomaly evaluation; the knowledge of certain properties, 
including the length and depth of the crack, and pipe properties 
like wall thickness, grade, and toughness; and a proposed safety 
factor based on the time until the next assessment period. The 
papers also require that the depth of a crack not be greater than 
the depth of the assessment tool's tolerance. See Sec.  192.712(e).
---------------------------------------------------------------------------

    While the GPAC did not have an explicit recommendation for 
scheduled (i.e., non-immediate) crack repair criteria, they recommended 
that PHMSA consider a repair schedule for cracks that is less 
conservative than what was proposed in the NPRM. Their recommended 
schedule is: 1.39 times MAOP for Class 1 and 2 locations and 1.5 times 
MAOP for Class 3 and 4 locations. PHMSA considered this recommendation 
and determined that the condition should cover Class 1 locations and 
Class 2 locations containing Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, where the predicted failure pressure is 
1.39 times MAOP. For all other Class 2 locations and higher class 
locations, the predicted failure pressure would be 1.5 times MAOP. 
Section 192.611 allows Class 1 pipe to remain in a Class 2 location if 
it has had a subpart J pressure test, for 8 hours, at 1.25 times MAOP. 
Also, it allows pipe with a design factor of 0.72, with the reciprocal 
of 1 divided by 0.72 being equal to 1.39, which is the predicted 
failure pressure. Therefore, PHMSA elected to apply a predicted failure 
pressure ratio of 1.39 times MAOP to both Class 1 pipe and uprated 
Class 2 pipe.
    For immediate conditions, the GPAC asked PHMSA to consider if a 
less conservative repair criterion of 1.1 times MAOP (after tool 
tolerance had been applied) would be appropriate. PHMSA considered this 
suggestion but notes that, after allowing for pressure excursions above 
MAOP due to over pressure protection device settings, the actual safety 
margin of such an approach would be between 0 and 6 percent. PHMSA has 
determined that this safety margin for immediate crack conditions is 
inadequate and, for this final rule, has retained the requirement that 
operators must immediately repair crack anomalies with a predicted 
failure pressure that is less than 1.25 times MAOP.
    PHMSA took technical guidance information from several sources into 
account regarding significant SCC and significant seam weld corrosion 
when creating the repair criteria for these anomalies, including ASME 
ST-PT-011 (``Integrity Management of Stress Corrosion Cracking in Gas 
Pipeline High Consequence Areas'').\34\
---------------------------------------------------------------------------

    \34\ ASME, ``STP-PT-011: Integrity Management of Stress 
Corrosion Cracking in Gas Pipeline High Consequence Areas'' (2008).
---------------------------------------------------------------------------

    ASME ST-PT-011 states that stress corrosion cracks are 
``Noteworthy'' if the maximum crack depth is greater than 10 percent of 
the wall thickness and if the maximum interacting crack length is more 
than the critical length of a 50 percent through-wall crack at a stress 
level of 110 percent SMYS.\35\ The report provides categories as 
follows:
---------------------------------------------------------------------------

    \35\ PHMSA notes that 110 percent SMYS for a Class 1 pipeline is 
roughly equivalent to 1.49 times MAOP.
---------------------------------------------------------------------------

    Category 1: Predicted Failure Pressure (PFP) is above 110 percent 
SMYS (note that 110 percent SMYS is used to delineate Category 1 cracks 
because it corresponds to the pressure most commonly prescribed for 
hydrostatic testing).
    Category 2: PFP is above 125 percent MAOP \36\ and below 110 
percent SMYS.
---------------------------------------------------------------------------

    \36\ PHMSA notes that 125% times MAOP for a pipeline that 
operates at 72% SMYS in a Class 1 location would correspond to 
roughly 90% SMYS for a Category 2 crack. PHMSA has defined in Sec.  
192.506 that a spike test for cracking should be conducted at a 
pressure of 100 percent of SMYS (roughly equivalent to 1.39 times 
MAOP for a Class 1 location) or 1.5 times MAOP.
---------------------------------------------------------------------------

    Category 3: PFP is above 110 percent MAOP and below 125 percent 
MAOP.
    Category 4: PFP is below 110 percent MAOP.
    Category Zero: A crack below the threshold for Noteworthy cracks. 
These typically fall into two groups: (1) Those that are shallow (i.e., 
less than 10 percent through-wall depth), or (2) Those that are so 
short that, even if they were 50 percent through-wall depth, they would 
not result in a hydrostatic test failure.
    In this final rule, operators can use an engineering analysis on 
cracks in Categories 1 through 2 as described above. However, any 
Category 3 or 4 cracking defect below 125 percent MAOP would require 
immediate remediation. Category 3 cracks would have a 10 percent or 
greater safety factor, which is similar to how PHMSA currently treats 
corrosion anomalies at Sec.  192.933. PHMSA provides more conservatism 
in the cracking criteria because there is more uncertainty with the 
accuracy of current ILI technology in its ability to measure crack 
length and depth, as well operational factors.
    These severity categories allow operators to estimate the minimum 
remaining life at operating pressure for each category. The following 
estimates from ASME ST-PT-011 are based on the time it would take for 
the crack depth to increase to a failure-causing depth at the operating 
pressure. For pipelines operating at 72 percent SMYS, the following 
minimum operational lives for each category of cracks are as follows:

[[Page 52249]]

    Category Zero: Failure life exceeds 15 years (for short cracks) to 
25 years (for shallow cracks).
    Category 1: Failure life exceeds 10 years.
    Category 2: Failure life exceeds 5 years.
    Category 3: Failure life exceeds 2 years.
    Category 4: Failure may be imminent.
    ASME ST-PT-011 further states that mitigating a pipeline segment 
with SCC should be commensurate with the severity of the discovered 
crack, which would reflect the PFP and the estimated life at the 
operating pressure. For example, Category Zero cracks may warrant no 
more than ongoing SCC condition monitoring and reassessment after a 
period of 7 years. Cracks may be best assessed by direct assessment, 
hydrostatic testing, or ILI. The most severe cases would require an 
immediate pressure reduction, repair (if the location is known), and 
hydrostatic testing or ILI, followed by replacing the pipe or 
installing an appropriate sleeve over the crack or known cracking 
areas.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

iv. Dent Criteria--Sec. Sec.  192.714 & 192.933
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed that dents in non-HCA segments with any 
indication of metal loss, cracking, or a stress riser would be 
considered ``immediate'' repair conditions. Additionally, PHMSA 
proposed that dents meeting the ``1-year'' repair conditions under 
Sec.  192.933 would be required to be repaired in non-HCAs within 2 
years.
2. Summary of Public Comment
    Multiple commenters, including the industry trade associations and 
operators, disagreed that all dents with metal loss should be 
considered immediate repair conditions. These commenters requested that 
PHMSA's final rule address different kinds of dents separately. Many 
pipeline operators stated that dents with metal loss from ``scratches, 
gouges, and grooves'' are appropriate as immediate repair conditions, 
while dents caused by corrosion are lower risk and should be conditions 
scheduled for later repair. Several organizations cited API Publication 
1156 \37\ and ASME/ANSI B31.8, ``Gas Transmission and Distribution 
Piping Systems,'' to support these claims. Several commenters also 
recommended that PHMSA impose different response timelines for dents 
depending on the location and the manner of the dents, because dents 
with bottom-side metal loss are usually corrosion-related and low-risk, 
while dents on the top of the pipeline with metal loss are likely to be 
from mechanical damage and are at a higher risk to fail. This 
distinction would be consistent with the criteria for smooth dents 
(dents with no peaks, buckling, gouging, cracking, or metal loss that 
can reduce the operational life of the pipe).
---------------------------------------------------------------------------

    \37\ API, ``Pub. 1156: Effects of Smooth and Rock Dents on 
Liquid Petroleum Pipelines'' (1997).
---------------------------------------------------------------------------

    With further regard to the repair criteria for dents, commenters 
representing the industry believed PHMSA should allow operators to use 
an ECA to evaluate dents as an alternative to following the prescribed 
repair criteria. Some of this discussion focused on whether PHMSA 
should include a finite element analysis (FEA) \38\ as part of the ECA 
and whether PHMSA should define critical strain levels as a criterion 
in the ECA. Comments from industry additionally suggested that the 
criterion related to gouges or grooves greater than 12.5 percent of 
wall thickness was duplicative with other criteria. Industry trade 
associations noted that gouges and grooves would be evaluated in 
accordance with the dent, metal loss, or cracking criteria, and 
therefore, a separate anomaly category for gouges and grooves should be 
removed. Further, they asserted that current ILI technology can't 
determine the specific cause of metal loss, which would make this 
criterion unfeasible.
---------------------------------------------------------------------------

    \38\ FEA is a modeling technique used to find and solve 
structural or integrity issues for phenomena such as cracking or 
denting. Pipe properties, including the parameters of the damage to 
the pipe, planned operating pressure, lifespan until the next 
evaluation, and any future operational conditions (max pressure, 
pressure cycle, higher temperatures), are needed to perform an FEA.
---------------------------------------------------------------------------

    At the GPAC meeting on March 26, 2018, the committee recommended 
changes to several of the specific repair criteria for cracks, 
corrosion metal loss, and dents. Specific to dents, the committee 
recommended that PHMSA allow use of an ECA to evaluate certain dent-
related anomalies and incorporate the ECA into the repair criteria.\39\
---------------------------------------------------------------------------

    \39\ Many of the recommended changes to the proposed repair 
criteria were highly technical in nature. For more information, 
including transcripts of the discussion and the voting slides, 
please visit: https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=132.
---------------------------------------------------------------------------

    Following the discussion, the committee voted 12-0 that, as 
published in the Federal Register, the provisions in the proposed rule 
and draft regulatory evaluation for dent repair criteria were 
technically feasible, reasonable, cost-effective, and practicable if 
PHMSA: (1) allowed operators to use an ECA for specific dent-related 
repair criteria and considered language to accommodate alternative ECA 
methods (including an FEA), and (2) distinguished between top-side 
dents that exceeded critical strain levels and bottom-side dents that 
exceeded critical strain levels by making distinct criteria for those 
anomalies.
3. PHMSA Response
    PHMSA believes that the repair criteria it proposed in the NPRM for 
dents provide an adequate safety margin and believes the criteria for 
dents that were suggested by some of the commenters would not provide 
adequate safety margin. PHMSA based this judgment on R&D programs that 
have been sponsored by PHMSA and the Pipeline Research Council 
International, and on elements of dent repair criteria that are 
contained within API RP 1183.\40\
---------------------------------------------------------------------------

    \40\ API, Recommended Practice 1183, ``Assessment and Management 
of Dents in Pipelines'' (Nov. 2020).
---------------------------------------------------------------------------

    PHMSA agrees with the GPAC recommendation for allowing an ECA 
method to evaluate dent anomalies and has revised the dent repair 
criteria for immediate, scheduled, and monitored conditions, as 
recommended by GPAC, to do so. PHMSA believes that the development of 
high-resolution deformation ILI tools has advanced enough to justify 
allowing operators to use an ECA method to evaluate dent anomalies and 
believes that it would be consistent with public safety while providing 
operators additional flexibility. While this rulemaking was under 
development, API published API RP 1183, which provides guidance for 
assessing and managing dents that are present in pipeline systems as a 
result of contact by rocks, machinery, or other forces. The RP presents 
guidance for developing a dent assessment and management program by (1) 
providing suitable methods for inspecting and characterizing the 
condition of the pipeline with respect to dents; (2) establishing data 
screening processes to evaluate dents relative to the extent and degree 
of deformation and operational severity; (3) providing response 
criteria for dents based on the dent shape and profile as determined by 
ILI; (4) applying engineering assessment methods to evaluate the 
fitness-for-service of dents, including the reassessment interval; (5) 
presenting remediation and repair options to address dents; and (6) 
developing preventive and mitigative measures for dents in lieu of, or 
in addition to,

[[Page 52250]]

periodic dent integrity assessment, including pressure reductions and 
pressure cycle management.
    PHMSA agrees with commenters that the criteria based on gouges and 
grooves would be duplicative with other criteria being proposed in the 
NPRM, namely the criteria related to metal loss anomalies. Accordingly, 
PHMSA has removed the criteria related to gouges and grooves from this 
final rule.
    In the 2019 Gas Transmission Rule, PHMSA finalized an ECA method 
for operators to use as a part of the pipeline material property and 
attribute verification under Sec.  192.607 and the MAOP reconfirmation 
requirements of Sec.  192.624. A key aspect of that ECA method is the 
detailed analysis of the remaining strength of pipe with known or 
assumed defects. The 2019 Gas Transmission Rule created a new section, 
Sec.  192.712, to address the techniques and procedures an operator 
could use to analyze the predicted failure pressures for pipe with 
corrosion metal loss and cracks or crack-like defects.\41\ That 
analysis requires the conservative analysis of the defect to determine 
the remaining life of the pipeline. In this final rule, PHMSA is 
building on the provisions it promulgated in the 2019 Gas Transmission 
Rule by allowing operators to use such an analysis for determining the 
timing of certain anomaly repairs, including dents. Unlike the 
previously existing repair criteria, which required the repair of 
listed anomalies within a specific timeframe, operators, per this final 
rule, can perform this analysis to determine whether the predicted 
failure pressure of the anomaly would warrant additional monitoring and 
a later repair. PHMSA understands that operators may propose, for PHMSA 
review in accordance with Sec.  192.18, procedures for the assessment 
and remediation of dent anomalies (such as an ECA for dent anomalies); 
operators may develop those procedures using consensus industry 
standards (e.g., API RP 1183, ASME B31.8, ASME B31.8S) or current 
research findings.
---------------------------------------------------------------------------

    \41\ See 84 FR 52236, 52237.
---------------------------------------------------------------------------

F. Repair Criteria--Sec. Sec.  192.714, 192.933

v. Corrosion Metal Loss Criteria--Sec. Sec.  192.714 & 192.933
1. Summary of PHMSA's Proposal
    The required remediation of several types of corrosion defects that 
are incorporated in the hazardous liquid regulations in part 195 are 
currently omitted from part 192. The current gas transmission IM 
regulations allow operators to use ASME/ANSI B31.8S, Figure 4, for 
guiding repair decisions not specified in Sec.  192.933(d), which can 
allow operators significant discretion in assessing and remediating 
pipe with corrosion or metal loss defects. PHMSA has found a wide 
variation in operators' interpretation of how to meet the requirements 
of the regulations in assessing, evaluating, and remediating corrosion 
and metal loss defects.
    To address these gaps, and to harmonize part 192 with part 195, 
PHMSA proposed to amend Sec.  192.933 to designate as immediate repair 
conditions those anomalies where metal loss is greater than 80 percent 
of nominal wall thickness and for indications of metal loss affecting 
certain legacy pipe with longitudinal seams.
    To address gaps related to non-immediate conditions, the NPRM 
proposed that operators must repair the following within 1 year: (1) 
anomalies where a calculation of the remaining strength of the pipe 
shows a predicted failure pressure ratio at the location of the anomaly 
less than or equal to 1.25 times the MAOP for Class 1 locations, 1.39 
times the MAOP for Class 2 locations, 1.67 times the MAOP for Class 3 
locations, and 2.00 times the MAOP for Class 4 locations (comparable to 
the alternative design factor specified in Sec.  192.620(a)); (2) areas 
of general corrosion with a predicted metal loss greater than 50 
percent of nominal wall thickness; (3) anomalies with predicted metal 
loss greater than 50 percent of nominal wall thickness that are located 
at crossings of another pipeline, are in areas with widespread 
circumferential corrosion, or are in areas that could affect a girth 
weld; and (4) anomalies with metal loss due to gouges or grooves \42\ 
that are greater than 12.5 percent of nominal wall thickness.
---------------------------------------------------------------------------

    \42\ Gouges or grooves are stress concentrators that lead to 
cracking and fatigue, which in turn may lead to accelerated failure.
---------------------------------------------------------------------------

2. Summary of Public Comment
    A commenter noted that PHMSA should recognize that gouges and 
scrapes are metal loss defects that can be smoothed by grinding to 
eliminate stress concentrations.
    Multiple commenters also provided input on the proposed provisions 
that determine repair criteria for metal loss affecting certain pipe 
with longitudinal seams. INGAA, AGA, and a pipeline industry entity 
generally supported a classification of ``immediate'' for anomalies 
with ``an indication of metal loss affecting a detected longitudinal 
seam, if that seam was formed by direct current or low frequency or 
high frequency electric resistance welding or by electric flash 
welding.'' However, PG&E requested that PHMSA not classify metal loss 
affecting a detected longitudinal seam as an immediate repair condition 
if that seam was formed by high-frequency electric resistance welding, 
as that pipe is considered ductile. National Fuel requested that PHMSA 
categorize longitudinal seam metal loss based on a minimum metal-loss 
threshold rather than ``an indication.'' Certain commenters requested 
PHMSA allow operators to perform a fitness-for-service evaluation or 
ECA on selective seam weld corrosion.
    Kern River suggested PHMSA should consider applicable manufacturing 
and tool detection tolerances in the establishment of repair criteria 
that require response to ``any indication of metal loss.''
    Several commenters, including AGA, Pauite, and DTE, did not support 
the proposed inclusion of ``any indication of significant seam weld 
corrosion'' in Sec.  192.713(d)(1)(vi). INGAA and AGA asserted that 
seam weld corrosion can only be conclusively determined by an in-field 
examination even though ILI tools are often employed to identify 
possible seam weld corrosion areas.
    INGAA requested that gouge and groove metal loss anomalies be 
deleted from the 1-year and 2-year response conditions. Other 
commenters noted that current ILI tools do not have the capability of 
differentiating 12.5 percent gouge or groove metal loss anomalies from 
12.5 percent external corrosion metal loss anomalies and suggested 
PHMSA delete this proposed requirement. These commenters argued that, 
given current ILI technology and per this proposal, operators would be 
required to investigate all metal loss indications greater than 12.5 
percent to determine if the metal loss was a gouge or groove. Several 
trade associations and pipeline industry entities requested that 
operators be allowed to perform excavations to validate ILI results 
before classifying a segment as a high-priority repair.
    Several pipeline industry commenters disagreed with the proposed 
repair criteria and repair methods that differed from industry standard 
ASME/ANSI B31.8S. For example, AGA stated that they opposed the 
inclusion of different repair criteria for different class locations 
because this contradicts ASME/ANSI B31.8S. API noted that PHMSA's 
proposal contradicted the ASME/ANSI standard by including depth-based 
criteria and also stated that PHMSA should not include the depth-

[[Page 52251]]

based criteria but only reference ASME/ANSI B31.8S, which is considered 
the best accepted practice. Similarly, INGAA recommended that PHMSA 
allow operators to use the repair methods in ASME/ANSI B31.8S rather 
than the proposed criteria.
    Some commenters thought that the new proposed criteria for 
corrosion anomalies made the existing corrosion repair requirements at 
Sec.  192.485(c) duplicative and requested PHMSA delete the existing 
corrosion repair requirements for clarity. Other commenters noted that 
PHMSA's proposed requirement for corrosion greater than 50 percent of 
wall thickness was redundant to other proposed corrosion metal loss 
defects and suggested this specific item should be deleted. Similarly, 
commenters suggested that the criteria for predicted metal loss greater 
than 50 percent of nominal wall located at the crossing of another 
pipeline, areas with widespread circumferential corrosion, or areas 
that could affect a girth weld were both too conservative and 
duplicative of other corrosion repair criteria.
    At the GPAC meeting on March 26, 2018, regarding the general 
provisions and applicability of the corrosion metal loss repair 
criteria, commenters representing the industry noted that for 1-year 
and 2-year scheduled conditions, the use of class location safety 
factors would be burdensome, as it would require more frequent repairs 
for pipelines in Class 2, Class 3, or Class 4 locations than 
contemplated by consensus industry standard ASME/ANSI B31.8S section 7, 
figure 4.
    The committee also discussed specific requirements related to the 
repair of corrosion anomalies. Echoing many of the public comments on 
the topic, members representing the industry believed that the newly 
proposed corrosion repair requirements were either overly conservative 
or duplicative compared to existing repair requirements in the 
corrosion control subpart. These committee members suggested the new 
requirements should be deleted or otherwise changed to be less 
conservative. Additionally, these members noted that the proposed 
criteria for anomalies where corrosion is greater than 50 percent of 
wall thickness would be redundant with other repair criteria for 
evaluating corrosion metal loss defects using accepted analysis 
techniques, such as ASME B31G and remaining strength of corroded pipe 
(RSTRENG).\43\ Further, for corrosion metal loss affecting pipe seams, 
members representing the industry suggested the criteria should apply 
to corrosion that ``preferentially'' affects the long seam,\44\ and 
that PHMSA should allow an ECA to analyze such defects to prevent 
unnecessary excavations.
---------------------------------------------------------------------------

    \43\ Both are incorporated by reference at Sec.  192.7; see 
(c)(4): ASME/ANSI B31G-1991 (Reaffirmed 2004), ``Manual for 
Determining the Remaining Strength of Corroded Pipelines,'' 2004, 
and (j)(1): AGA, Pipeline Research Committee Project, PR-3-805, ``A 
Modified Criterion for Evaluating the Remaining Strength of Corroded 
Pipe,'' (December 22, 1989).
    \44\ Corrosion that ``preferentially'' affects the long seam is 
corrosion that is of and along the weld seam that is classified as 
selective seam weld corrosion. It normally effects low frequency 
electric resistance weld seams (LF-ERW) and electric flash welded 
seams (EFW).
---------------------------------------------------------------------------

    The committee also suggested that PHMSA evaluate predicted failure 
pressure ratings and thresholds for remediation schedules of anomalies 
at pipeline crossings with widespread circumferential corrosion or with 
corrosion that can affect a girth weld.
    Following the discussion, the committee voted 11-0 that, as 
published in the Federal Register, the provisions in the proposed rule 
and draft regulatory evaluation for corrosion metal loss repair 
criteria (excluding the repair timing) were technically feasible, 
reasonable, cost-effective, and practicable if PHMSA: (1) clarified 
that the criteria do not apply to corrosion pits near a long seam but 
does apply to corrosion along seams that could lead to slotting-type 
crack-like defects, (2) deleted duplicative criteria, (3) cross-
referenced the proposed new fracture mechanics section with the general 
corrosion remediation requirements, and (4) revised the repair criteria 
for scheduled conditions regarding the predicted failure pressure as 
discussed by the committee.
    The committee then voted 8-3 (with each of two members representing 
State regulators and one member representing the public dissenting) 
that, as published in the Federal Register, the provisions in the 
proposed rule and draft regulatory evaluation for scheduled conditions 
regarding the predicted failure pressure repair criteria for corrosion 
metal loss anomalies were technically feasible, reasonable, cost-
effective, and practicable if PHMSA: (1) incorporated ASME/ANSI B31.8S, 
section 7, figure 4, into the repair criteria; (2) required operators 
to consider ILI tool tolerance on all runs; (3) removed and revised the 
predicted failure pressure standards for metal loss anomalies per the 
discussion of the committee; and (4) provided guidance to improve the 
understanding and use of ASME/ANSI B31.8S, section 7, figure 4.
    For corrosion metal loss anomalies that meet the ``scheduled'' 
criteria (i.e., 1-year conditions for HCAs and 2-year conditions for 
non-HCAs), the GPAC voted 8-3 that PHMSA should remove the predicted 
failure pressure standards for Class 1 and Class 2 segments from the 
NPRM and require operators to use section 7, figure 4 from ASME/ANSI 
B31.8S instead (i.e., retain the current requirement in place for HCAs 
under subpart O).
3. PHMSA Response
    When developing the repair criteria in the NPRM, PHMSA evaluated 
grounding the predicted failure pressure for those criteria in one or 
more of the following three factors: (1) the test pressure of a 
pipeline, (2) the design factor of a pipeline, and (3) the HCA repair 
criteria. Because PHMSA sought to improve upon existing HCA repair 
criteria, PHMSA decided against using that factor as the basis for 
calculating predicted failure pressures and proposed using test 
pressure or design factor of a pipeline instead. PHMSA based its 
proposed threshold for Class 1 pipelines (less than or equal to 1.25 
times MAOP predicted failure pressure) on the maximum test pressure in 
Sec.  192.619 for Class 1 pipelines (1.25 times MAOP). For the repair 
thresholds for Class 2, Class 3, and Class 4 pipelines, PHMSA 
calculated predicted failure pressures using the reciprocals of the 
design factors listed at Sec.  192.111 for the immediately preceding 
class location rating. This approach ensured an adequate margin to 
failure even if the pipeline were to experience a one-class bump 
(pursuant to Sec.  192.611) from changes in population density of the 
surrounding area. The resulting predicted failure pressure thresholds 
were less than or equal to 1.39 times MAOP (reciprocal of the 0.72 
Class 1 design factor) for pipelines in a Class 2 location, less than 
or equal to 1.67 times MAOP for pipelines in Class 3 locations, and 
less than or equal to 2.00 times MAOP for pipelines in Class 4 
locations.
    PHMSA believes the repair criteria for corrosion metal loss that 
were suggested by some of the commenters would not provide adequate 
safety margin compared to what PHMSA proposed in the NPRM. This was 
discussed at length by the GPAC, who recommended repair criteria that, 
in some cases, were less conservative than what PHMSA proposed in the 
NPRM.
    In this final rule, PHMSA adopted the GPAC's recommendation to 
incorporate ASME/ANSI B31.8S section 7, figure 4, into the repair 
criteria by requiring operators to use it in Class 1 locations for 
metal loss anomalies with a

[[Page 52252]]

predicted failure pressure greater than 1.1 times MAOP, which is 
consistent with the previous IM repair regulations. The committee also 
recommended PHMSA provide additional guidance on the use of ASME/ANSI 
B31.8S section 7, figure 4. ASME/ANSI B31.8S, section 7, figure 4 has 
three scales for repair that are based on the MAOP of the pipeline and 
the MAOP's percentage of the pipeline's SMYS.\45\ Operators can use one 
of the 3 sliding scales of figure 4, as appropriate, to address 
anomalies when the anomaly has a failure pressure ratio above 1.1. As 
discussed previously, operators are currently required to follow ASME/
ANSI B31.8S section 7, figure 4 under elements of the previous IM 
repair regulations. PHMSA understands that the 10 percent nominal 
safety margin provided by compliance with ASME/ANSI B31.8S section 7, 
figure 4 is appropriate for the relatively low risk to public safety 
posed to pipelines in low-population-density, Class 1 locations.
---------------------------------------------------------------------------

    \45\ Those three scales pertain to (1) not exceeding 30 percent 
SMYS, (2) above 30 percent SMYS but not exceeding 50 percent SMYS, 
and (3) above 50 percent SMYS.
---------------------------------------------------------------------------

    However, PHMSA did not accept the GPAC's recommendation for Class 2 
locations. The number of immediate repair conditions being discovered 
during reassessments in Class 2 locations continues at approximately 
the same rate as they were discovered during the baseline assessment 
phase of the IM rule promulgated in 2004, according to PHMSA annual 
report data. PHMSA attributes this to defects that are not repaired and 
allowed to grow to a size that are at or near failure (i.e., an 
immediate condition). Existing immediate repair criteria for pipelines 
in Class 2 locations (predicated on ASME/ANSI B31.8S section 7, figure 
4) allow up to a maximum 10 percent safety margin over the MAOP. 
However, after allowing for pressure excursions above MAOP due to 
overpressure protection device settings, the actual safety margin is 
between 0 and 6 percent. PHMSA has determined that the continued 
reliance on those ASME/ANSI B31.8S section 7, figure 4-derived safety 
margins in more densely populated Class 2 locations does not ensure 
adequate identification and elimination of sub-critical defects before 
they grow to a size that would raise immediate safety concerns. 
Therefore, in this final rule, PHMSA chooses to retain the NPRM's 
predicted failure pressure threshold for metal loss anomalies in Class 
2 locations of less than 1.39 times MAOP.
    For Class 3 and Class 4 locations, PHMSA considered predicted 
failure pressure thresholds between 1.39 times and 1.50 times MAOP as 
requested by the committee. However, PHMSA has determined that, in 
order to provide adequate margin for public safety in higher- 
population-density Class 3 and 4 locations, PHMSA could not establish a 
predicted failure pressure threshold as low as 1.39 times MAOP. 
Therefore, in this final rule, PHMSA has provided a repair threshold 
for anomalies meeting a predicted failure pressure of less than 1.50 
times MAOP for pipelines in Class 3 and Class 4 locations. PHMSA notes 
this approach would align repair criteria with the approach in Sec.  
192.619 for determining maximum allowable pressures for the same 
locations, and reflects that transmission pipelines in Class 3 and 
Class 4 locations are more robust (as a result of thicker walls and 
other design requirements) than those used in Class 1 and Class 2 
locations.
    PHMSA has provided similar repair criteria in this final rule for 
corrosion metal loss anomalies that are at a crossing of another 
pipeline; are in an area with widespread circumferential corrosion; 
could affect a girth weld; or that preferentially affects detected 
longitudinal seams that are formed by direct current, low-frequency or 
high-frequency electric resistance welding, electric flash welding, or 
with a longitudinal joint factor less than 1.0. Specifically, PHMSA is 
requiring the repair of conditions that reach less than 1.39 times the 
MAOP for anomalies in Class 1 locations or where Class 2 locations 
contain Class 1 pipe that has been uprated in accordance with Sec.  
192.611. For those corrosion metal loss anomalies at all other Class 2 
locations, as well as those anomalies in Class 3 and Class 4 locations, 
operators will have to repair them once they reach a predicted failure 
pressure of less than 1.50 times MAOP.
    PHMSA is requiring the additional stringency in Class 1 locations 
and Class 2 locations compared to the general corrosion metal loss 
repair standard discussed above because, should corrosion at the 
crossing of other pipelines induce failure, multiple pipelines could be 
damaged or fail. Pipelines with anomalies located at areas of 
widespread circumferential corrosion could additionally lose pipe 
strength due to outside longitudinal (pulling force) loading on the 
pipeline. And, historically, longitudinal seams that are formed by 
direct-current welding, low-frequency or high-frequency electric 
resistance welding, electric flash welding, or that have a longitudinal 
joint factor of less than 1.0, are more likely to fail. Therefore, 
PHMSA has determined that more stringent repair criteria are necessary 
for corrosion metal loss anomalies that preferentially affect these 
longitudinal seams. In contrast, because pipelines in Class 3 and Class 
4 locations are (as noted above) more robust than those in Class 1 and 
Class 2 locations, PHMSA has determined that it is unnecessary to 
impose different thresholds for pipelines in Class 3 and Class 4 
locations based on whether they are located at the crossing of another 
pipeline.
    As explained in the discussion for dent anomalies above, PHMSA 
agreed with commenters that the specific criteria for gouges and 
grooves was duplicative with other metal loss conditions and has chosen 
not to finalize gouge and groove criteria in this final rule. 
Therefore, the comments related to whether ILI tools can properly or 
reliably identify gouges and grooves specifically are moot.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

vi. General Discussion
Process for Analyzing Defects Discovered--Sec.  192.933
1. Summary of PHMSA's Proposal
    Following the Enbridge hazardous liquid incident in 2010 that 
spilled nearly 1 million barrels of oil near Marshall, MI, in 2010, the 
NTSB recommended that PHMSA revise requirements in the hazardous liquid 
pipeline safety regulations at Sec.  195.452(h)(2) related to the 
``discovery of condition'' to require, in cases where a determination 
about pipeline threats has not been obtained within 180 days following 
the date of inspection, that pipeline operators notify PHMSA and 
provide an expected date when adequate information will become 
available.\46\ The NTSB also recommended that PHMSA revise part 195 to 
state the acceptable methods for performing engineering assessments of 
ILI results, including the assessment of cracks coinciding with 
corrosion, with a safety factor that considers the uncertainties 
associated with sizing of crack defects (P-12-3). Although these 
recommendations were for the hazardous liquid pipeline safety 
regulations in part 195, the issues apply equally to gas pipelines 
regulated under part 192.
---------------------------------------------------------------------------

    \46\ NTSB Recommendation P-12-4, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-004.
---------------------------------------------------------------------------

    Accordingly, PHMSA proposed to amend paragraph (b) of Sec.  192.933 
to

[[Page 52253]]

require that operators notify PHMSA within 180 days following an 
assessment where the operator cannot obtain sufficient information to 
determine if a condition presents a potential threat to the integrity 
of the pipeline; and expand the requirements in Sec.  192.933 to 
clarify that operators must assure that persons qualified by knowledge, 
training, and experience must analyze the data obtained from an ILI to 
determine if a condition could adversely affect the safe operation of 
the pipeline. PHMSA also proposed to require that operators explicitly 
consider uncertainties in reported results in identifying and 
characterizing anomalies, which includes uncertainties in tool 
tolerance, detection threshold, the probability of detection, the 
probability of identification, sizing accuracy, conservative anomaly 
interaction criteria, location accuracy, anomaly findings, and unity 
chart plots.
    PHMSA also proposed to amend paragraphs (a) and (d) of Sec.  
192.933 to require that operators document a pipeline's physical 
material properties and attributes that are used in remaining strength 
calculations in reliable, traceable, verifiable, and complete records. 
If such records were not available, operators would be required to base 
the pipe and material properties used in the remaining strength 
calculations on properties determined and documented in accordance with 
Sec.  192.607.
2. Summary of Public Comment
    Commenters noted that there were potential issues with how the 
revised repair criteria and the proposed material verification 
requirements at Sec.  192.607 would interact regarding remaining 
strength calculations. These commenters requested that, absent reliable 
data, PHMSA allow operators to use supportable, sound engineering 
judgments when calculating remaining strength. This would allow 
operators to establish the remaining strength of affected segments 
while material verification was completed. Similarly, commenters 
suggested if the value for specified minimum yield strength is unknown, 
operators should be able to use a conservative default value, such as 
30,000 pounds per square inch (psi). For predicted failure pressure 
calculations, operators suggested they should be able to use the 
records they have on hand and operator knowledge for calculations until 
any necessary material properties are verified through Sec.  192.607. 
Similarly, at the GPAC meeting on March 26, 2018, commenters 
representing the industry suggested PHMSA should allow, in the absence 
of traceable, verifiable, and complete material records,\47\ for 
operators to use sound engineering judgment or otherwise conservative 
assumptions in repair-related decision making, and recommended PHMSA 
modify the regulations as such.
---------------------------------------------------------------------------

    \47\ In an advisory bulletin dated May 7, 2012 (77 FR 26822), 
PHMSA provided guidelines for what records would meet a traceable, 
verifiable, and complete standard. The phrase ``traceable, 
verifiable, and complete'' matched a phrase from NTSB recommendation 
P-10-5, which recommended to the California Public Utilities 
Commission to ensure that PG&E ``aggressively and diligently 
searched documents and records relating to [ . . . ] natural gas 
transmission lines in class 3 and class 4 locations and class 1 and 
class 2 high consequence areas [ . . . ]. These records should be 
traceable, verifiable, and complete [ . . . ].'' See NTSB 
Recommendation P-10-5, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-10-005. While PHMSA proposed that records meet a reliable, traceable, 
verifiable, and complete standard, PHMSA believes that being 
consistent with the guidance it provided in the May 2012 advisory 
bulletin and the NTSB recommendation will provide further clarity.
---------------------------------------------------------------------------

    The EDF and PST supported PHMSA's proposals related to considering 
uncertainties in ILI results for identifying and characterizing 
anomalies. Several pipeline operators and industry trade associations 
on the other hand, including INGAA, expressed concern that the NPRM 
would require pipeline operators to repair anomalies that do not 
threaten pipeline integrity, stating that many anomalies that are 
identified by indirect measurements as requiring repair are later 
determined not to require repair upon examination in the field. These 
commenters requested that PHMSA change the proposed requirements to 
distinguish between ILI results and in-field examinations and start the 
repair timeline with the time an anomaly is examined in the field and 
not when it is identified by ILI.
    INGAA suggested that PHMSA change the proposed requirements to 
differentiate between response, remediation, and repair, and that PHMSA 
replace ``repair'' with ``response'' in the terms ``2-year repair 
criteria'' and ``1-year repair criteria'' as those terms pertain to the 
non-HCA repair criteria. INGAA also requested that PHMSA further divide 
``2-year response conditions'' into ``2-year response conditions and 
scheduled responses'' and similarly divide ``1-year response 
conditions'' into ``1-year response conditions and scheduled 
responses.'' INGAA suggested such a revision would be necessary because 
the proposed requirements for the response to, and repair of, potential 
pipeline anomalies do not recognize the differences between actions 
that operators take when evaluating the result of integrity assessments 
versus those actions operators take following in-field examinations of 
potential anomalies.
    Several commenters requested that PHMSA change the proposed 
regulatory language to distinguish between ILI results and in-field 
examinations (response) and the actual remediation activity (repair) 
with a view to start the repair timeline after an anomaly is examined 
in the field and not when it is identified by ILI. Commenters suggested 
separate timelines to distinguish between the ``response'' and 
``repair'' phases of pipeline remediation.
3. PHMSA Response
    PHMSA addressed comments pertaining to the use of sound engineering 
judgment and assumed values to evaluate anomalies when data required 
for the evaluation is unknown or not available in traceable, 
verifiable, and complete records in the 2019 Gas Transmission Rule at 
Sec.  192.712.\48\ If an operator does not have one or more of the 
material properties necessary to perform an ECA analysis (diameter, 
wall thickness, seam type, grade, and Charpy v-notch toughness values, 
if applicable), the operator must use the conservative assumptions 
PHMSA provided and include the pipeline segment in its program to 
verify the undocumented information in accordance with the material 
properties verification requirements at Sec.  192.607.
---------------------------------------------------------------------------

    \48\ See 84 FR 52236, 52251.
---------------------------------------------------------------------------

    In the Response to Petitions for Reconsideration on the 2019 Gas 
Transmission Rule,\49\ PHMSA stated that if operators are missing any 
material properties during anomaly evaluations and repairs, operators 
must confirm those material properties under Sec. Sec.  192.607 and 
192.712(e) through (g). For consistency in this final rule, and to make 
this requirement more explicit, PHMSA has linked those material 
property confirmation requirements to the anomaly repair requirements 
by cross-referencing Sec.  192.607 at both Sec. Sec.  192.714 and 
192.933. PHMSA will also note that, in accordance with the section 23 
mandate in the 2011 Pipeline Safety Act, operators reported that 
approximately 13 percent of pipeline segment mileage in HCAs and Class 
3 and Class 4 locations lack adequate documentation of the physical and 
operational characteristics of the pipelines necessary to confirm the 
proper MAOP. Such documentation is

[[Page 52254]]

also critical for performing predicted failure pressure calculations.
---------------------------------------------------------------------------

    \49\ 85 FR 40132 (July 6, 2020).
---------------------------------------------------------------------------

    In an earlier section of the repair criteria discussion, PHMSA 
noted that the identification of anomalies based on ILI results is an 
actionable indication that there might be an injurious defect in the 
pipeline. Establishing repair criteria based on operators discovering 
these actionable anomalies assures that these anomalies are 
investigated promptly and repaired. Therefore, PHMSA disagrees with 
commenters who suggested that there should be separate timelines for 
anomaly responses and repairs, as it would be prudent for operators to 
perform any necessary repairs once the operator has excavated the pipe 
and exposed the anomaly for investigation rather than deferring such 
repairs.

F. Repair Criteria--Sec. Sec.  192.714, 192.933

vii. Miscellaneous Comments
1. Summary of Public Comments
    Commenters were concerned that the requirements in this rulemaking 
would apply to gas gathering pipelines and requested that PHMSA clarify 
this is not the case. Similarly, the GPAC, in its late March 2018 
meeting, recommended PHMSA clarify that the non-HCA repair criteria 
applied to those pipeline segments not currently covered under the IM 
regulations at subpart O.
    Additionally, pipeline operators and their trade associations 
requested that PHMSA clarify the effective date of the repair 
provisions, as the requirements were proposed in an allegedly 
retroactive section of the regulations. These commenters claimed, as 
written, the proposed provisions would force operators to apply the 
revised repair criteria to prior ILI assessments that, at the time, met 
all the standards of the regulations. Some of these commenters 
recommended PHMSA establish reasonable, risk-based timeframes for 
operators to implement repairs of anomalies that were historically 
identified and were repaired in accordance with the code requirements 
of the time. The GPAC, during their meeting in late March of 2018, 
similarly recommended that PHMSA add an effective date to these general 
repair provisions to clarify that they were not retroactive.
    Some commenters also discussed the application of the proposed 
repair criteria to pipelines outside of HCAs that have established 
their MAOP under the alternative requirements at Sec.  192.620. The 
GPAC recommended PHMSA apply appropriate predicted failure pressure 
factors to alternative MAOP pipelines based on class location and 
design factors for scheduled conditions under the repair criteria.
2. PHMSA Response
    PHMSA did not intend for the new repair criteria for non-HCA pipe 
segments to be applicable to gas gathering pipelines, HCA segments, or 
offshore transmission lines. However, PHMSA will consider expanding the 
application of these provisions in the future. In this final rule, to 
clarify that the new non-HCA repair criteria apply only to onshore 
transmission lines, PHMSA placed the new non-HCA repair criteria in a 
new Sec.  192.714, which applies only to onshore transmission lines. 
Subsequently, PHMSA withdrew all proposed changes to Sec.  192.713. 
PHMSA has also revised Sec.  192.9 in this final rule to exempt 
regulated gas gathering lines from the requirements of Sec.  192.714. 
Additionally, PHMSA has modified Sec.  192.711 in this final rule to 
clarify that the new repair criteria in Sec.  192.714 do not apply to 
gathering lines or HCA segments subject to subpart O. The current and 
unchanged Sec.  192.713 would continue to apply to regulated gas 
gathering lines. Although the creation of a new Sec.  192.714 was not 
discussed at the GPAC, PHMSA determined that this approach was a 
clearer means to specify that the new non-HCA repair criteria only 
apply to onshore transmission pipelines and meet the intent of the GPAC 
recommendation to clarify that the non-HCA repair criteria do not apply 
to gathering lines, HCA segments, or offshore transmission lines. 
Furthermore, PHMSA determined that this approach avoids duplication of 
repair language in other code sections.
    PHMSA did not intend to imply that the new repair criteria were to 
be applied retroactively and has clarified this intent in this final 
rule by revising Sec.  192.711(b) to include an effective date as 
recommended by the GPAC.
    Regarding alternative MAOP pipelines, the NPRM did not propose, and 
therefore did not give opportunity for comment on, changes to repair 
criteria for alternative MAOP pipe segments. However, PHMSA agrees with 
commenters that the language proposed in the NPRM could create 
ambiguity with respect to the applicability of the non-HCA repair 
criteria to pipe with MAOP established in accordance with Sec.  
192.620. Therefore, in this final rule, PHMSA more broadly exempted 
alternative MAOP lines from compliance with non-HCA repair criteria and 
reiterated the applicability of the repair criteria provided at the 
alternative MAOP provisions under Sec.  192.620(d)(11) as they provide 
a comparable level of safety based upon the operating factors. PHMSA 
did not make a corresponding change to Sec.  192.933, as alternative 
MAOP pipelines in HCAs must meet both the HCA and the alternative MAOP 
repair criteria. This approach is preferable to repeating the alternate 
MAOP repair criteria in two locations of part 192.

G. Definitions--Sec.  192.3

i. Close Interval Survey
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed a new definition for ``close interval 
survey'' as a series of closely spaced pipe-to-electrolyte potential 
measurements taken to assess the adequacy of cathodic protection or to 
identify locations where a current may be leaving the pipeline and may 
cause corrosion, and for the purpose of quantifying voltage drops other 
than those across the structure electrolyte boundary.
2. Summary of Public Comment
    Comments from the trade associations and GPAC members representing 
the industry questioned whether PHMSA should tie the definition of 
``close interval survey'' to a corresponding NACE standard for 
consistency. PHMSA presented some minor changes to the definition at 
the meeting on March 28, 2018, and the committee voted 13-0 that PHMSA 
should adopt those changes into the final rule.
3. PHMSA Response
    After considering the comments and GPAC recommendations, PHMSA is 
adopting the definition of ``close interval survey'' as recommended by 
GPAC. As such, PHMSA has specified that the pipe-to-electrolyte 
potential measurements are taken ``over the pipe,'' and added the 
phrase ``such as when performed as a current interrupted, depolarized, 
or native survey'' to qualify what is ``other than those across the 
structure electrolyte boundary.''

G. Definitions--Sec.  192.3

ii. Distribution Center
1. Summary of PHMSA's Proposal
    PHMSA proposed to define a ``distribution center'' as a location 
where gas volumes are either metered or have a pressure or volume 
reduction prior to delivery to customers through a distribution line.
2. Summary of Public Comment
    AGL Resources, Pipeline Safety Coalition, Southern California Gas

[[Page 52255]]

Company, Spire STL Pipeline LLC, and Xcel Energy supported PHMSA's 
intention to define the term ``distribution center.'' In particular, 
AGL Resources stated that the proposed definition would remove 
confusion and the potential for conflict between operators and 
regulators throughout the Nation. Like its comments on the proposed 
definition for ``transmission line,'' Xcel Energy suggested that PHMSA 
add an implementation period for operators to handle the regulatory 
impacts of the new definition.
    AGA supported PHMSA's effort to define a ``distribution center'' to 
ensure consistency and certainty in the identification of transmission 
lines. However, AGA also stated that PHMSA failed to provide any 
justification or explanation for its proposed definition, and AGA 
proposed an alternative definition of ``distribution center'' where 
piping downstream of a distribution center that operates above 20 
percent SMYS would be classified as a transmission line. Other 
organizations, such as Alliant Energy, Dominion Energy, PECO Energy, 
Paiute Pipeline Company, and Southwest Gas Corporation, supported AGA's 
alternative definition.
    TPA recommended PHMSA revise the proposed definition of 
``distribution center'' to provide a clear endpoint for transmission 
lines and the start of distribution lines. Atmos Energy stated that the 
proposed definition did not recognize the many possible configurations 
of pipes in which transmission pipelines deliver to distribution 
systems. For example, Oleksa and Associates stated that some 
distribution systems may have no meters prior to delivery to customers 
and also may have no pressure or volume reductions (e.g., a 
distribution system supplied by a landfill). Lastly, Cascade Natural 
Gas requested the term ``distribution center'' clearly refer to 
distribution pipelines and that such a definition should not be 
included in a rulemaking for transmission and gathering pipelines.
    At the GPAC meeting, PHMSA offered for the committee's 
consideration the option of recommending withdrawal of the proposed 
definition for ``distribution center.'' Committee members opposed this 
suggestion, stating that finalizing a definition for ``distribution 
center'' would provide the industry and regulators with regulatory 
certainty and clarity. During the meeting, committee members came to a 
consensus on the definition of a ``distribution center'' based on 
comments the industry provided. However, certain committee members 
representing the public were not inclined to adopt a definition of a 
``distribution center'' that was based on the comments provided by 
industry and wished to defer to PHMSA regarding the wordsmithing of the 
definition.
    Following the discussion, the committee voted 10-0 that the 
definition for ``distribution center'' was technically feasible, 
reasonable, cost-effective, and practicable if PHMSA incorporated a 
definition for ``distribution center'' in the final rule and considered 
revising the definition to mean the initial point where gas enters 
piping used to deliver gas to customers for end use as opposed to 
customers who purchase it for resale. Examples of a distribution center 
would include a metering location; a pressure reduction location; or 
where there is a reduction in the volume of gas, such as a lateral off 
a transmission pipeline.
3. PHMSA Response
    After considering the comments received and the GPAC's 
recommendations, PHMSA is adopting the definition recommended by GPAC 
so that a ``distribution center'' means the initial point where gas 
enters piping used to deliver gas to customers for end use as opposed 
to customers who purchase it for resale.
    PHMSA disagrees that an implementation period for the definition is 
appropriate, given that this term has been in use for a long period of 
time. PHMSA agrees with commenters for the need to clarify the end 
point of transmission and the start of distribution. PHMSA agrees with 
those commenters who suggested that piping downstream of a distribution 
center operating at above 20 percent SMYS should be considered a 
transmission line and is modifying the definition of ``transmission 
line'' accordingly in this final rule.

G. Definitions--Sec.  192.3

iii. Dry Gas or Dry Natural Gas
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed a new definition for the term ``dry gas 
or dry natural gas'' to mean gas with less than 7 pounds of water per 
million cubic feet that is not subject to excessive upsets allowing 
electrolytes into the gas system.
2. Summary of Public Comment
    GPAC members representing the industry asked whether PHMSA should 
tie the definition for dry gas to the corresponding NACE standard for 
continuity. Committee members representing the public were concerned 
about incorporating by reference the definition into the regulations 
but were amenable to lifting the language directly from the standard to 
ensure consistency. PHMSA representatives noted that the agency could 
consider the NACE definition and make the definition for dry gas less 
prescriptive than proposed.
    After discussion, the committee voted 13-0 that the definition for 
``dry gas or dry natural gas'' was technically feasible, reasonable, 
cost-effective, and practicable if PHMSA revised the definition to be 
consistent with the NACE definition as discussed at the meeting.
3. PHMSA Response
    PHMSA has taken into consideration the comments as well as the GPAC 
recommendations and is modifying the definition for ``dry gas or dry 
natural gas'' to be consistent with the NACE standard. More 
specifically, the definition specifies that ``dry gas or dry natural 
gas'' is gas ``above its dew point and without condensed liquids.''

G. Definitions--Sec.  192.3

iv. Electrical Survey
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed revising the term ``electrical survey'' 
so that it means a series of closely spaced measurements of the 
potential difference between two reference electrodes to determine 
where the current is leaving the pipe on ineffectively coated or bare 
pipelines.
2. Summary of Public Comment
    PHMSA received a variety of comments on the definition for 
``electrical survey.'' Some commenters expressed support for the 
definition and its inclusion in the regulations. Other commenters 
supported the concept of the definition but provided PHMSA with varying 
edits to improve on the clarity and functionality of the definition.
    Several commenters noted that the proposed definition for 
electrical survey was duplicative with the proposed definition for 
``close interval survey'' and recommended that PHMSA retain the 
definition for close interval survey instead. Some of these commenters 
noted that the proposed definition for electrical survey was more 
restrictive than the definition of electrical survey in NACE standards 
and excluded certain types of surveys. Other commenters suggested that 
the proposed definition for electrical survey should match the 
definition in various NACE standards.
    NACE itself believed that the definition used in the NPRM for

[[Page 52256]]

``electrical survey'' was ambiguous and inaccurate, stating the 
proposed definition does not align with current terminology and 
accepted pipeline integrity practices. NACE recommended that PHMSA use 
the definition for ``indirect inspection'' in NACE SP0502, which is 
widely accepted as standard practice and should meet PHMSA's intent.
    The GPAC recommended that PHMSA withdraw the proposed changes to 
appendix D as a part of the recommended revisions to the proposed 
corrosion control regulations. There was no further discussion on the 
definition for the term, and the committee voted, 13-0, to delete the 
definition from the rule.
3. PHMSA Response
    PHMSA notes that, when the committee voted to withdraw the proposed 
changes to appendix D as a part of the corrosion control discussion, a 
revised definition for electrical survey was unnecessary as all 
references to ``electrical surveys'' were removed. Therefore, PHMSA 
agrees with the GPAC recommendation and has struck the proposed 
revision to the definition of ``electrical survey'' from this final 
rule.

G. Definitions--Sec.  192.3

v. Hard Spot
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to define a ``hard spot'' as steel pipe 
material with a minimum dimension greater than 2 inches (50.8 mm) in 
any direction with hardness greater than or equal to Rockwell 35 HRC, 
Brinnel 327 HB, or Vickers 345 HV10.
2. Summary of Public Comment
    During the GPAC meeting, committee members noted there was a small 
editorial correction that needed to be made--changing ``Brinnel'' to 
``Brinell'' --and also recommended that the definition be prefaced with 
the phrase ``an area on'' so that the definition reads ``an area on 
steel pipe material [. . .].''
3. PHMSA Response
    PHMSA has modified the proposed definition of hard spot as the GPAC 
recommended for this final rule.

G. Definitions--Sec.  192.3

vi. In-Line Inspection (ILI) and In-Line Inspection Tool or 
Instrumented Internal Inspection Device
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to add definitions for ``in-line 
inspection (ILI)'' and ``in-line inspection tool or instrumental 
internal inspection device'' to Sec.  192.3. Specifically, the term 
``in-line inspection'' would mean the inspection of a pipeline from the 
interior of the pipe using an ILI tool, which may also be known as 
intelligent or smart pigging. The term ``in-line inspection tool or 
instrumented internal inspection device'' would mean a device or 
vehicle that inspects a pipeline from the inside using a non-
destructive technique. Such a device might also be called an 
intelligent or smart pig.
2. Summary of Public Comment
    NACE International commented that the proposed definitions of ``in-
line inspection'' and ``in-line inspection tool or instrumented 
internal inspection device'' do not align with the definition provided 
in NACE International Standard SP01024 or SP0102, respectively. NACE 
International suggested that PHMSA use the definition in NACE Standard 
SP0102, as PHMSA had proposed to incorporate by reference the standard 
in the regulations.
    The GPAC reviewed the proposed definitions and, following their 
discussion, voted 13-0 that the definitions for ``in-line inspection'' 
and ``in-line inspection tool or instrumented internal inspection 
device'' were technically feasible, reasonable, cost-effective, and 
practicable if PHMSA considered clarifying in the preamble that the 
phrase ``a line that can accommodate inspection by means of an 
instrumented in-line inspection tool'' referred to pipeline segments 
that can be inspected with free-swimming ILI tools without any 
permanent physical modification of the pipeline segment.
3. PHMSA Response
    After considering these comments, PHMSA is modifying the 
definitions of both ``in-line inspection'' and ``in-line inspection 
tool or instrumented internal inspection device'' based on the 
definitions in NACE SP0102-2010. In accordance with the GPAC 
recommendation, PHMSA is also noting that an ILI can include both 
tethered and self-propelled (i.e., ``free-swimming'') tools.

G. Definitions--Sec.  192.3

vii. Transmission Line
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to modify the second criterion of the 
``transmission line'' definition to base the percentage of SMYS on the 
MAOP of the pipeline, whereas currently it is based on the pressure at 
which the pipeline is operating. PHMSA also proposed editorial changes 
to the ``Note'' section of the definition and make it clearer that 
``factories, power plants, and institutional users of gas'' were 
examples of a large-volume customer.
2. Summary of Public Comment
    AGA asserted that modifying the second criterion in the 
``transmission line'' definition in conjunction with other definition 
changes PHMSA proposed would result in the reclassification of some 
transmission pipelines to distribution lines and some distribution 
pipelines to transmission lines. Several pipeline operators and 
industry representatives, including AGL Resources, Alliant Energy, 
Black Hills Energy, Cascade Natural Gas, Centerpoint Energy, Spire, 
Delmarva Power, National Grid, National Fuel Gas Supply Corporation, 
North Dakota Petroleum Council, Paiute Pipelines, TECO Peoples Gas, 
TPA, and PECO Energy, supported AGA's comments or provided similar 
recommendations. Additionally, Dominion East Ohio and Southwest Gas 
objected to PHMSA's proposed modifications to the definition, stating 
that the proposed definition would burden operators with ongoing IM 
programs with no additional benefit to public safety.
    APGA commented that PHMSA's slight rewording of the note in the 
transmission definition regarding types of large-volume customers could 
be interpreted to mean that only factories, power plants, and 
institutional users of gas can be large-volume customers. APGA 
suggested PHMSA change the proposed language in the final rule to 
clarify that those listed items are examples of large-volume customers 
rather than a comprehensive list.
    ONE Gas proposed an alternative simplified approach to the 
definition of ``transmission line'' that focuses on a line's MAOP as it 
relates to the percentage of yield strength.
    There were various comments from other pipeline operators, 
including the suggestion that PHMSA remove the term ``distribution 
center'' from the definition of ``transmission line,'' allow operators 
to use MAOP to determine a transmission pipeline, and provide an 
implementation period for operators to incorporate regulatory 
requirements of the newly defined transmission lines.
    During the GPAC meeting, committee members representing the 
industry expressed support for allowing operators to designate 
pipelines voluntarily as transmission lines, especially if their risk 
profile was high,

[[Page 52257]]

so that operators could operate and maintain those lines to a higher 
standard.
    Following the discussion, the committee voted 10-0 that the 
definition for ``transmission line'' was technically feasible, 
reasonable, cost-effective, and practicable if PHMSA included the 
phrase ``an interconnected series of pipelines'' within the text of the 
definition and allowed operators to designate pipelines voluntarily as 
transmission lines.
3. PHMSA Response
    PHMSA has considered the comments received regarding the proposed 
definition of a ``transmission line.'' PHMSA agrees with the 
recommendation from the GPAC to allow operators to designate pipelines 
voluntarily as transmission lines, as well as the recommendation from 
the GPAC to include the phrase ``an interconnected series of 
pipelines.'' Accordingly, PHMSA has revised the definition of 
``transmission line'' in this final rule to include these 
recommendations.
    PHMSA agrees with commenters that the language to clarify the 
examples of large-volume customers may imply a specific list and has 
withdrawn the changes to the note in the definition. In response to the 
comment on providing an implementation period for compliance with the 
new definition, PHMSA notes that it does not apply separate 
implementation periods to definitions outside of the effective date of 
the rule. If PHMSA determines that corresponding regulations would be 
affected by a change in a definition, it incorporates appropriate 
implementation time to those regulations as necessary.
    PHMSA also notes that, per the comments received on the definition 
for ``distribution center,'' it agreed with commenters who suggested 
that piping downstream of a distribution center operating at above 20 
percent of SMYS should be considered a transmission line and is 
modifying the definition of ``transmission line'' accordingly in this 
final rule.
    PHMSA sees no functional difference in changing the definition of a 
transmission line from a pipeline that operators at a hoop stress of 20 
percent or more of SMYS and a pipeline that has a MAOP of 20 percent or 
more of SMYS. For a pipeline to operate above 20 percent or more of 
SMYS, it will have an MAOP of 20 percent or more of SMYS. If an 
operator has a pipeline where the theoretical MAOP is higher than the 
pipeline's actual operating pressure, and therefore the line would need 
to be reclassified, the operator could reduce the MAOP of the line to 
keep the line's classification the same without affecting its operating 
pressure.

G. Definitions--Sec.  192.3

viii. Wrinkle Bend
1. Summary of PHMSA's Proposal
    In the NPRM, PHMSA proposed to define ``wrinkle bend'' as a bend in 
the pipe that was formed in the field during construction such that the 
inside radius of the bend has one or more ripples of various sizes or 
where the ratio of peaks to peaks or peaks to valleys are of a certain 
size, or where a mathematical equation could be substituted when a 
wrinkle bend's length cannot reliably be determined.
2. Summary of Public Comment
    There was no significant public comment on this definition, and the 
GPAC recommended PHMSA adopt the definition as it was published in the 
NPRM.
3. PHMSA Response
    PHMSA adopts the definition as it was published in the NPRM.

IV. Section-by-Section Analysis

Section 192.3 Definitions

    Section 192.3 provides definitions for various terms used 
throughout part 192. In support of other regulations adopted in this 
final rule, PHMSA is amending the definition of ``transmission line'' 
and is adding new definitions for ``close interval survey,'' 
``distribution center,'' ``dry gas or dry natural gas,'' ``hard spot,'' 
``in-line inspection,'' ``in-line inspection tool or instrumented 
internal inspection device,'' and ``wrinkle bend.'' The definitions, 
including ``in-line inspection,'' ``dry gas or dry natural gas,'' and 
``hard spot,'' clarify technical terms used in part 192 or in this 
rulemaking.

Section 192.7 What documents are incorporated by reference partly or 
wholly in this part?

    Section 192.7 lists documents that are incorporated by reference in 
part 192. PHMSA is making conforming amendments to Sec.  192.7 to 
include two NACE standard practice documents regarding SCCDA and ICDA.

Section 192.9 What requirements apply to gathering lines?

    Section 192.9 lists the requirements that are applicable or not 
applicable to gathering lines. This final rule addresses several new 
requirements for transmission lines that are not intended to apply to 
gathering lines; PHMSA is adopting in this final rule revisions to 
Sec.  192.9 to except each of offshore and Types A, B, and C \50\ gas 
gathering lines from those requirements.
---------------------------------------------------------------------------

    \50\ PHMSA notes that it has introduced in this final rule 
revisions to Sec.  192.9(e), which paragraph was adopted in the Gas 
Gathering Final Rule, to identify specific provisions of part 192 
that would apply to the new Type C category of part 192-regulated 
onshore gas gathering pipelines.
---------------------------------------------------------------------------

Section 192.13 What general requirements apply to pipelines regulated 
under this part?

    Section 192.13 prescribes general requirements for gas pipelines. 
PHMSA has determined that public safety and environmental protection 
would be improved by requiring operators of transmission lines to 
evaluate and mitigate risks during all phases of the useful life of a 
pipeline as an integral part of managing pipeline design, construction, 
operation, maintenance, and integrity, including the MOC process.
    As such, PHMSA has added a new paragraph (d) to Sec.  192.13 with a 
general clause for transmission pipeline operators that invokes the 
requirements for the MOC process as it is outlined in ASME/ANSI B31.8S, 
section 11, and explicitly articulates the requirements for a MOC 
process applicable to onshore gas transmission pipelines. This final 
rule requires each operator to have a MOC process that must include the 
reason for change, authority for approving changes, analysis of 
implications, acquisition of required work permits, documentation, 
communication of change to affected parties, time limitations, and 
qualification of staff. While these general attributes of change 
management are already required for covered segments by virtue of the 
incorporation by reference of ASME/ANSI B31.8S, PHMSA believes it will 
improve the visibility and emphasis on these important program elements 
to require them for all onshore transmission pipelines directly in the 
rule text.

Section 192.18 How To Notify PHMSA

    Section 192.18 in subpart A contains the procedure for an operator 
to submit notifications to PHMSA. Paragraph (c) has been modified to 
incorporate notification requirements for the use of ``other 
technology'' with external corrosion control and ICDA per Sec. Sec.  
192.461(g) and 192.927(b).\51\ This is

[[Page 52258]]

consistent with the requirements PHMSA issued with the use of other 
technology for provisions finalized in the 2019 Gas Transmission Rule.
---------------------------------------------------------------------------

    \51\ PHMSA notes that between publication of this final rule and 
its effective date, regulatory amendments to Sec.  191.18 adopted in 
rulemaking published in April 2022 will have been codified in the 
Code of Federal Regulations. ``Pipeline Safety: Requirement of Valve 
Installation and Minimum Rupture Detection Standards,'' 87 FR 20940 
(Apr. 8, 2022) (identifying an effective date in October 2022) 
(Valve Installation Final Rule). The amendatory text at the end of 
this final rule, therefore, reflects the text of Sec.  192.18 as it 
will be revised when the Valve Installation Final Rule becomes 
effective.
---------------------------------------------------------------------------

Section 192.319 Installation of Pipe in a Ditch

    Section 192.319 prescribes requirements for installing pipe in a 
ditch, including requirements to protect pipe coating from damage 
during the process. Sometimes pipe coating is damaged during the 
construction process while it is being handled, lowered, and 
backfilled, which can compromise its ability to protect against 
external corrosion. Accordingly, this final rule adds new paragraphs 
(d) through (g) to Sec.  192.319, which require that onshore gas 
transmission operators perform an above-ground indirect assessment to 
identify locations of suspected damage promptly after backfilling is 
completed and remediate coating damage. Mechanical damage is also 
detectable by these indirect assessment methods, since the forces that 
can mechanically damage steel pipe usually result in detectable coating 
defects.
    If an operator uses ``other technology'' to perform an assessment 
required under this section, paragraph (e) requires the operator to 
notify PHMSA in accordance with Sec.  192.18. Paragraph (g) requires 
each operator of transmission pipelines to make and retain, for the 
life of the pipeline, records documenting the coating assessment 
findings and repairs. The additional requirements of this section do 
not apply to gas gathering pipelines or distribution mains.

Section 192.461 External Corrosion Control: Protective Coating

    Section 192.461 prescribes requirements for protective coating 
systems. Certain types of coating systems that have been used 
extensively in the pipeline industry can impede the process of cathodic 
protection if the coating disbonds from the pipe. Accordingly, this 
final rule amends paragraph (a)(4) to require that pipe coating has 
sufficient strength to resist damage during installation and backfill, 
and it also adds a new paragraph (f) to require that onshore gas 
transmission operators perform an above-ground indirect assessment to 
identify locations of suspected damage promptly after backfill is 
completed or anytime there is an indication that the coating might be 
compromised. To ensure the prompt remediation of any severe coating 
damage, new paragraph (h) requires operators create a remedial action 
plan and provides the specific timing requirements for repairs. New 
paragraph (g) requires an operator to notify PHMSA, in accordance with 
Sec.  192.18, if using ``other technology'' for the coating assessment, 
and paragraph (i) specifies the documentation requirements for this 
section. The additional requirements of this section do not apply to 
gas gathering pipelines or distribution mains.

Section 192.465 External Corrosion Control: Monitoring

    Section 192.465 requires that operators monitor CP and take prompt 
remedial action to correct deficiencies indicated by the monitoring. To 
clarify that regulatory requirement, this final rule amends paragraph 
(d) to require that operators of onshore transmission pipelines must 
complete remedial action no later than the next monitoring interval 
specified in Sec.  192.465, within 1 year, or within 6 months of 
obtaining any permits, whichever is less.
    This final rule also adds a new paragraph (f) to require onshore 
gas transmission operators to conduct annual test station readings to 
determine if CP is below the level of protection required in subpart I. 
For non-systemic or location-specific causes of insufficient CP, the 
operator must investigate and mitigate the cause. For insufficient CP 
due to systemic causes, an operator must complete CIS with the 
protective current interrupted, unless it is impractical to do so based 
on a geographical, technical, or safety reason. For example, issues 
related to cost would not be an adequate reason for not performing the 
survey, whereas performing a survey on a pipeline protected by direct 
buried sacrificial anodes (anodes directly connected to the pipelines) 
might be impractical. The revisions to paragraph (d) and new paragraph 
(f) do not apply to gas gathering lines or distribution mains.

Section 192.473 External Corrosion Control: Interference Currents

    Interference currents can negate the effectiveness of CP systems. 
Section 192.473 currently prescribes general requirements to minimize 
the detrimental effects of interference currents. However, subpart I 
does not presently contain specific requirements to monitor and 
mitigate detrimental interference currents. Accordingly, this final 
rule adds a new paragraph (c) to require that onshore gas transmission 
operator corrosion control programs include interference surveys to 
detect the presence of interference currents when potential monitoring 
indicates a significant increase in stray current, or when new 
potential stray current sources are introduced. Sources of stray 
current can include co-located pipelines, structures, HVAC power lines, 
new or enlarged power substations, new pipelines, and other structures. 
They can also include additional generation, a voltage uprating, and 
additional lines. The rule also requires operators perform remedial 
actions no later than 15 months after completing the interference 
survey, with an allowance for permitting, to protect the pipeline 
segment from detrimental interference currents. These additional 
requirements do not apply to gas gathering pipelines or distribution 
mains.

Section 192.478 Internal Corrosion Control: Monitoring

    Section 192.477 prescribes requirements to monitor internal 
corrosion if corrosive gas is being transported. However, the existing 
rules do not prescribe operators continually or periodically monitor 
the gas stream for the introduction of corrosive constituents through 
system modifications, gas supply changes, upset conditions, or other 
changes. This could result in operators not identifying internal 
corrosion if an initial assessment did not identify the presence of 
corrosive gas. Accordingly, PHMSA has determined that additional 
requirements are needed to ensure that operators effectively monitor 
their gas stream quality to identify if, and when, corrosive gas is 
being transported and mitigate deleterious gas stream constituents 
(e.g., contaminants or liquids).
    Therefore, this final rule adds a new Sec.  192.478 to require 
onshore gas transmission operators monitor for known deleterious gas 
stream constituents and evaluate gas monitoring data once every 
calendar year, not to exceed a period of 15 months. Additionally, this 
final rule adds a requirement for onshore gas transmission operators to 
review their internal corrosion monitoring and mitigation program 
annually, not to exceed 15 months, and adjust the program as necessary 
to mitigate the presence of deleterious gas stream constituents. These 
requirements are in addition to the existing requirements to check 
coupons or perform other methods to monitor for the actual

[[Page 52259]]

presence of internal corrosion in the case of transporting a known 
corrosive gas stream. The new Sec.  192.478 does not apply to gas 
gathering pipelines or distribution mains.

Section 192.485 Remedial Measures: Transmission Lines

    Section 192.485 prescribes requirements for operators to perform 
remedial measures to address general corrosion and localized corrosion 
pitting in transmission pipelines. For such conditions, the 
requirements specify that an operator may determine the strength of 
pipe based on actual remaining wall thickness by using the procedure in 
ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee 
Project PR 3-805 (RSTRENG). PHMSA has determined that additional 
requirements are needed beyond ASME/ANSI B31G and RSTRENG to ensure 
such calculations have a sound basis and has revised Sec.  192.485(c) 
to specify that an operator must calculate the remaining strength of 
the pipe in accordance with Sec.  192.712, which prescribes important 
aspects such as pipe and material properties, assumptions allowed when 
data is unknown, accounting for uncertainties, and recordkeeping 
requirements.

Section 192.613 Continuing Surveillance

    Extreme weather and natural disasters can affect the safe operation 
of a pipeline. Accordingly, this final rule revises Sec.  192.613 to 
require operators to perform inspections after these events and take 
appropriate remedial actions.

Section 192.710 Transmission Lines: Assessments Outside of High 
Consequence Areas

    Section 192.710 prescribes requirements for the periodic assessment 
of certain pipelines outside of HCAs. In the NPRM, PHMSA proposed for 
operators to use the non-HCA repair criteria being finalized in this 
rule if they performed an assessment on a non-HCA pipeline and 
discovered an anomaly requiring repair. However, in splitting the 
rulemaking, PHMSA finalized the assessment requirement in the 2019 Gas 
Transmission Final Rule but did not incorporate regulatory text 
establishing the corresponding repair criteria. Therefore, in this 
final rule, PHMSA has revised the assessment requirement at Sec.  
192.710 to require operators to use the repair criteria finalized in 
this rulemaking if anomalies are discovered during these assessments.

Section 192.711 Transmission Lines: General Requirements for Repair 
Procedures

    Section 192.711 prescribes general requirements for repair 
procedures. For non-HCA segments, the existing regulations required 
that operators make permanent repairs as soon as feasible. However, no 
specific repair criteria were detailed, and no specific timeframe or 
pressure reduction requirements were provided. PHMSA has determined 
that more specific repair criteria are needed for pipelines not covered 
under the integrity management regulations. Such repair criteria will 
help to maintain safety in a consistent manner in Class 1 through Class 
4 locations that may have significant populations but that are not 
HCAs. Accordingly, this final rule amends paragraph (b)(1) of Sec.  
192.711 to require operators remediate specific conditions, as defined 
in Sec.  192.714, on non-HCA gas transmission pipelines. Paragraph 
(b)(1) retains the existing requirement that operators must repair 
anomalies on gathering pipelines regulated in accordance with Sec.  
192.9 as soon as feasible.

Section 192.712 Analysis of Predicted Failure Pressure and Critical 
Strain Levels

    In the 2019 Gas Transmission Rule, PHMSA updated and codified 
minimum standards for determining the predicted failure pressure of 
pipelines containing anomalies or defects associated with corrosion 
metal loss and cracks. In this final rule, PHMSA is revising the repair 
criteria for gas transmission pipelines, including for dents. Some of 
the revised dent repair criteria allow operators to determine critical 
strain levels for dents and defer repairs if critical strain levels are 
not exceeded. As such, PHMSA has established minimum standards for 
operators to calculate critical strain levels in pipe with dent 
anomalies or defects and has included those standards in a new 
paragraph (c) of Sec.  192.712. The title of this section has also been 
updated to reflect this addition. PHMSA has also provided reassessment 
schedules for engineering critical assessments that operators perform 
to determine maximum reevaluation intervals to ensure that anomalies do 
not grow to critical sizes.

Section 192.714 Transmission Lines: Permanent Field Repair of 
Imperfections and Damages

    Section 192.713 prescribes requirements for the permanent repair of 
pipeline imperfections or damage that impairs the serviceability of 
steel transmission pipelines operating at or above 40 percent of SMYS. 
PHMSA has determined that more explicit requirements are needed in 
Sec.  192.714 to identify criteria for the severity of imperfections or 
damage that must be repaired, and to identify the timeframe within 
which repairs must be made for pipelines in all class locations that 
are not in HCAs. Pipelines not in HCAs can still have significant 
populations that could be harmed by a pipeline leak or rupture. As 
such, PHMSA has determined that repair criteria should apply to any 
onshore transmission pipeline not covered under the IM regulations in 
subpart O. PHMSA believes that establishing these non-HCA segment 
repair conditions for Class 1 locations through Class 4 locations are 
important because, even though they are not within HCAs, these 
locations could be in highly populated areas and are not without 
consequence to public safety and the environment.
    Accordingly, this final rule creates a new Sec.  192.714 to 
establish repair criteria for immediate, 2-year, and monitored 
conditions that the operator must remediate or monitor to ensure 
pipeline safety. PHMSA is using the same criteria as it is issuing for 
HCAs, except conditions for which a 1-year response is required in HCAs 
will require a 2-year response in non-HCA pipeline segments so that 
operators can allocate their resources to HCAs on a higher-priority 
basis. Additionally, PHMSA is prescribing more explicit requirements 
for the in situ evaluation of cracks and crack-like defects using in-
the-ditch tools whenever required, such as when an ILI, SCCDA, pressure 
test failure, or other assessment identifies anomalies that suggest the 
presence of such defects.

Section 192.911 What are the elements of an integrity management 
program?

    Paragraph (k) of Sec.  192.911 requires that IM programs include a 
MOC process as outlined in ASME/ANSI B31.8S, section 11. PHMSA has 
determined that specific attributes and features of the MOC process 
that are currently specified in ASME/ANSI B31.8S, section 11, should be 
codified directly within the text of subpart O for HCAs to make the 
requirements readily available to all operators of onshore gas 
transmission pipelines. This change is consistent with the new 
paragraph (d) in Sec.  192.13 for all onshore transmission pipelines.

[[Page 52260]]

Section 192.917 How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    Section 192.917 requires that operators with IM programs for 
covered pipeline segments identify potential threats to pipeline 
integrity and use the threat identification in their integrity program. 
This performance-based process includes requirements to identify 
threats to which the pipeline is susceptible, collect data for 
analysis, and perform a risk assessment. The regulations include 
special requirements for operators to address plastic pipe and 
particular threats, such as third-party damage and manufacturing and 
construction defects.
    As specified in Sec.  192.907(a), PHMSA expected operators to start 
with a framework for IM, which would later evolve into a more detailed 
and comprehensive program, and expected that an operator would 
continually improve its IM program as it learned more about the process 
and about the material condition of its pipelines through integrity 
assessments. PHMSA elaborated on this philosophy in the 2003 IM 
rule.\52\
---------------------------------------------------------------------------

    \52\ ``Pipeline Integrity Management in High Consequence Areas 
(Gas Transmission Pipelines)''; 68 FR 69778 (Dec. 15, 2003). See 68 
FR 69789.
---------------------------------------------------------------------------

    Even though the IM regulations have been in effect since 2004, 
PHMSA still finds certain operators have poorly developed IM programs. 
The clarifications and additional specificity adopted in this final 
rule, with respect to the processes an operator must use in 
implementing the threat identification, risk assessment, and preventive 
and mitigative measure program elements, reflect PHMSA's expectation 
regarding the degree of progress operators should be making, or should 
have made, during the first 10 years of the implementation of the IM 
regulations.
    The current IM regulations incorporate by reference ASME/ANSI 
B31.8S to require that operators implement specific attributes and 
features of the threat identification, data analysis, and risk 
assessment process in their IM programs. In this final rule, PHMSA is 
amending Sec.  192.917 to insert certain critical features of ASME/ANSI 
B31.8S directly into the regulatory text. PHMSA is specifying several 
pipeline attributes that must be included in pipeline risk assessments 
and is explicitly requiring that operators integrate analyzed 
information and ensure that data is verified and validated to the 
maximum extent practical. To the degree that subjective data from SMEs 
must be used, PHMSA is requiring that an operator's program account and 
compensate for uncertainties in the risk model used and the data used 
in the operator's risk assessment. PHMSA is also in this final rule 
revising the non-exhaustive list of data to be collected for clarity or 
to eliminate redundant language.
    PHMSA will note that in its advisory bulletin on the verification 
of records that ``verifiable'' records are those in which information 
is confirmed by other complementary, but separate, documentation. Such 
records might include contract specifications for a pressure test of a 
line segment complemented by field logs or purchase orders with pipe 
specifications verified by metallurgical tests of coupons pulled from 
the same pipe segment.
    Additionally, PHMSA is clarifying the performance-based risk 
assessment aspects of the IM regulations in this final rule by 
specifying that operators must perform risk assessments that are 
adequate for evaluating the effects of interacting threats; determine 
additional P&M measures needed; analyze how a potential failure could 
affect HCAs, including the consequences of the entire worst-case 
incident scenario from initial failure to incident termination; 
identify the contribution to risk of each risk factor, or each unique 
combination of risk factors that interact or simultaneously contribute 
to risk at a common location; account for, and compensate for, 
uncertainties in the model and the data used in the risk assessment; 
and evaluate risk reduction associated with candidate risk reduction 
activities, such as P&M measures.
    In consideration of NTSB recommendation P-11-18, PHMSA is adopting 
regulations that require operators to validate their risk models 
considering incident, leak, and failure history and other historical 
information. These features are currently requirements because they are 
incorporated by reference in ASME/ANSI B31.8S. However, PHMSA has found 
that provisions incorporated directly into its regulatory text have 
higher levels of compliance. The final rule also amends the 
requirements for plastic pipe to provide specific examples of integrity 
threats for plastic pipe that must be addressed.

Section 192.923 How is direct assessment used and for what threats?

    This final rule incorporates by reference NACE SP0206-2006, 
``Internal Corrosion Direct Assessment Methodology for Pipelines 
Carrying Normally Dry Natural Gas,'' for addressing ICDA, and NACE 
SP0204-2008, ``Stress Corrosion Cracking Direct Assessment,'' for 
addressing SCCDA. Accordingly, PHMSA has revised Sec.  192.923(b)(2) 
and (3) to require operators comply with these standards.

Section 192.927 What are the requirements for using internal Corrosion 
Direct Assessment (ICDA)?

    Section 192.927 specifies requirements for gas transmission 
pipeline operators who use ICDA for IM assessments. The requirements in 
Sec.  192.927 were promulgated before NACE SP0206-2006 was published 
and require that operators follow ASME/ANSI B31.8S provisions related 
to ICDA. PHMSA has reviewed NACE SP0206-2006 and finds that it is more 
comprehensive and rigorous than either Sec.  192.927 or ASME/ANSI 
B31.8S in many respects. Therefore, PHMSA is incorporating NACE SP0206-
2006 into the regulations for the performance of ICDA and is 
establishing additional requirements for addressing covered segments 
within the technical process defined by the NACE standard.
    This final rule requires that operators perform two direct 
examinations within each covered segment the first time ICDA is 
performed. These examinations are in addition to those required to 
comply with the NACE standard. The additional examinations are 
consistent with the current requirement in Sec.  192.927(c)(5)(ii) that 
operators apply more restrictive criteria when conducting ICDA for the 
first time and are intending to verify, within the HCA, that the 
results of applying the process of NACE SP0206-2006 for the ICDA are 
acceptable. Applying the process for NACE SP0206-2006 requires more 
precise knowledge of the pipeline orientation (particularly slope) than 
operators may have in many cases. Conducting examinations within the 
HCA during the first application of ICDA will verify that applying the 
ICDA process provides an operator with adequate information about the 
covered segment. Operators who identify internal corrosion on these 
additional examinations, even though excavations at locations 
determined using NACE SP0206-2006 did not identify any internal 
corrosion, will know that improvements are needed to their knowledge of 
pipeline orientation. In addition, operators will know they need other 
adjustments to their application of the NACE standard to the covered 
segment for using ICDA in the future. Section 192.927(b) and (c) are 
revised in this final rule to address these issues.
    PHMSA notes that, for these requirements, operators are prohibited 
from using assumed pipeline or operational data. Any data an operator

[[Page 52261]]

uses for its ICDA process should be based on known information, such as 
the pipeline route, the pipeline diameter, and pipeline flow inputs and 
outputs. Operators can choose to base their ICDA process on data that 
is more conservative than their known pipeline or operational data.

Section 192.929 What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?

    Section 192.929 specifies requirements for gas transmission 
pipeline operators who use SCCDA for IM assessments. The requirements 
in Sec.  192.929 were promulgated before NACE Standard Practice SP0204-
2008 was published, and the standard requires that operators follow 
Appendix A3 of ASME/ANSI B31.8S. That appendix provides some guidance 
for conducting SCCDA but is limited to SCC that occurs in high-pH 
environments. Experience has shown that pipelines can also experience 
SCC degradation in areas where the surrounding soil has a pH near 
neutral (referred to as near-neutral SCC). NACE SP0204-2008 addresses 
near-neutral SCC as well as high-pH SCC. NACE SP0204-2008 also provides 
technical guidelines and process requirements that are both more 
comprehensive and rigorous for conducting SCCDA than Sec.  192.929 or 
ASME/ANSI B31.8S.
    Since NACE SP0204-2008 provides comprehensive guidelines on 
conducting SCCDA and is more comprehensive in scope than Appendix A3 of 
ASME/ANSI B31.8S, PHMSA has concluded the quality and consistency of 
SCCDA conducted under IM requirements would be improved by requiring 
operators to use NACE SP0204-2008. The final rule accomplishes this.

Section 192.933 What actions must be taken to address integrity issues?

    Section 192.933 specifies injurious anomalies and defects that 
operators must remediate and the timeframes within which such 
remediation must occur. PHMSA determined that the existing regulations 
for repair criteria had gaps, as some injurious anomalies and defects 
were not listed as requiring remediation in a timely manner 
commensurate with their seriousness. To remedy this, in this final 
rule, PHMSA is designating the following types of defects as immediate 
conditions: (1) anomalies where the metal loss is greater than 80 
percent of nominal wall thickness; (2) metal loss anomalies with a 
predicted failure pressure less than or equal to 1.1 times the MAOP; 
(3) a topside dent that has metal loss, cracking, or a stress riser; 
(4) anomalies where there is an indication of metal loss affecting 
certain longitudinal seams; and (5) cracks or crack-like anomalies 
meeting specified criteria.
    The final rule also designates the following types of defects as 1-
year conditions: (1) smooth topside dents with a depth greater than 6 
percent of the pipeline diameter; (2) dents greater than 2 percent of 
the pipeline diameter that are located at a girth weld or spiral seam 
weld; (3) a bottom-side dent that has metal loss, cracking, or a stress 
riser; (4) metal loss anomalies where a calculation of the remaining 
strength of the pipe shows a predicted failure pressure ratio less than 
or equal to 1.39 for Class 2 locations, and 1.50 for Class 3 locations 
and Class 4 locations; (5) anomalies where there is metal loss that is 
at a crossing of another pipeline, is in an area with widespread 
circumferential corrosion, or is in an area that could affect a girth 
weld, and that has a predicted failure pressure less than 1.39 in Class 
1 locations or where Class 2 locations contain Class 1 pipe that has 
been uprated in accordance with Sec.  192.611, and less than 1.50 times 
the MAOP in all other Class 2 locations and all Class 3 and 4 
locations; (6) anomalies where there is metal loss affecting a 
longitudinal seam; and (7) any indications of cracks or crack-like 
defects other than those listed as an immediate condition.
    In this final rule, PHMSA is also adding requirements for 
addressing regulatory gaps related to the methods for calculating 
predicted failure pressure if metal loss exceeds 80 percent of wall 
thickness; time-sensitive integrity threats including corrosion 
affecting a longitudinal seam, especially those associated with seam 
types that are known to be susceptible to latent manufacturing defects, 
such as the failed pipe at San Bruno,\53\ and selective seam weld 
corrosion; and the fact that the current regulations do not list SCC as 
an immediate condition even though it is listed in ASME/ANSI B31.8S as 
an immediate repair condition.
---------------------------------------------------------------------------

    \53\ These seam types include seams formed by direct current, 
low- or high-frequency electric resistance welding, electric flash 
welding, or with a longitudinal joint factor less than 1.0, and 
where the predicted failure pressure, determined in accordance with 
Sec.  192.712(d), is less than 1.25 times the MAOP.
---------------------------------------------------------------------------

    With respect to SCC, PHMSA has incorporated repair criteria to 
specify that operators must use engineering assessment techniques 
specified in Sec.  192.712 to evaluate if cracks or crack-like 
anomalies should be categorized as an ``immediate'' condition, a ``1-
year'' condition, or a ``monitored'' condition. PHMSA believes that 
this will help address NTSB recommendation P-12-3, which resulted from 
the investigation of the Enbridge accident near Marshall, MI.\54\ 
Although the NTSB recommendation was specifically made for hazardous 
liquid pipelines regulated under part 195, SCC can affect gas 
transmission pipelines regulated under part 192 as well.
---------------------------------------------------------------------------

    \54\ See NTSB Recommendation P-12-3, available at https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-003.
---------------------------------------------------------------------------

    The current regulations do not include 1-year conditions for metal 
loss anomalies. For non-immediate conditions, the regulations direct 
operators to use Figure 4 in ASME/ANSI B31.8S to determine the repair 
criteria for metal loss anomalies that do not meet the ``immediate'' 
threshold. To address this gap, PHMSA is including certain metal loss 
anomalies in the list of 1-year conditions. These changes make the gas 
transmission repair criteria more consistent with the hazardous liquid 
repair criteria at 49 CFR 195.452(h).
    PHMSA is also incorporating safety factors commensurate with the 
class location in which the pipeline is located to make 1-year 
conditions anomalies where the predicted failure pressure is less than 
or equal to 1.39 times MAOP in Class 2 locations, and 1.50 times MAOP 
in Class 3 and Class 4 locations in HCAs. Operators must continue to 
use ASME/ANSI B31.8S, Figure 4 for corrosion metal loss anomalies in 
Class 1 locations.
    Additionally, the NTSB recommended that PHMSA revise the 
``discovery of condition'' at 49 CFR 195.452(h)(2) to require, in cases 
where a determination about pipeline threats has not been obtained 
within 180 days following the date of inspection, that pipeline 
operators notify PHMSA and provide an expected date when adequate 
information will become available.\55\ PHMSA incorporated this NTSB 
recommendation into Sec. Sec.  195.416(f) and 195.452(h)(2) of the 
``Safety of Hazardous Liquid Pipelines'' final rule, which was 
published on October 1, 2019.\56\
---------------------------------------------------------------------------

    \55\ NTSB Recommendation P-12-4, available at https://www.ntsb.gov/safety/safety-recs/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-12-004.
    \56\ See 84 FR 52260.
---------------------------------------------------------------------------

    Although the NTSB made the recommendation for hazardous liquid 
pipelines regulated under part 195, the issue applies to gas 
transmission pipelines regulated under part 192 as well. Accordingly, 
PHMSA has

[[Page 52262]]

amended paragraph (b) of Sec.  192.933 to require that operators notify 
PHMSA whenever the operator cannot obtain sufficient information to 
determine if a condition presents a potential threat to the integrity 
of the pipeline within 180 days of completing the assessment.
    PHMSA is also finalizing requirements for the in situ evaluation of 
cracks and crack-like defects using in-the-ditch tools whenever an 
operator discovers conditions that need to be repaired, such as when an 
ILI, an SCCDA, a pressure test failure, or another assessment 
identifies such anomalies. This applies to IM pipelines the same 
requirement adopted in Sec.  192.714(g) for non-IM pipelines.

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

    Section 192.935 requires an operator to take additional measures 
beyond those already required by part 192 to prevent a pipeline failure 
and to mitigate the consequences of a pipeline failure in an HCA. An 
operator must conduct a risk analysis to identify the additional 
measures to protect the HCA and improve public safety. As discussed 
earlier, PHMSA is amending Sec.  192.917 to clarify the guidance for 
risk analyses operators use to evaluate and select additional P&M 
measures. This final rule also adds specific enhanced measures for 
operators to use for managing internal and external corrosion in HCAs 
and expands the list of P&M measures operators must consider when 
providing for public safety.
    Specifically, operators must explicitly consider the following P&M 
measures:

    (i) Correcting the root causes of past incidents in order to 
prevent recurrence;
    (ii) O&M processes that maintain safety and the pipeline MAOP;
    (iii) Adequate resources for the successful execution of these 
activities within the required timeframe;
    (iv) Pressure transmitters that communicate with the pipeline 
control center on both sides of automatic shut-off valves and 
remote-control valves;
    (v) Additional right-of-way patrols;
    (vi) Hydrostatic tests in areas where pipeline material has 
quality issues or records that are not traceable, verifiable, and 
complete;
    (vii) Tests to determine unknown material, mechanical, or 
chemical properties that are needed to ensure pipeline integrity or 
substantiate MAOP, including material property tests from removed 
pipe that is representative of the in-service pipeline;
    (viii) The re-coating of damaged, poorly performing, or 
disbonded coatings, and
    (ix) Additional depth-of-cover surveys at roads, streams, and 
rivers, among other areas.

    These P&M measures do not alter the fundamental requirement for 
operators to identify and implement P&M measures; rather, they provide 
additional guidance and clarify PHMSA's expectations with this 
important aspect of IM.
    Section 29 of the 2011 Pipeline Safety Act requires operators to 
consider seismicity when evaluating threats. In the 2019 Gas 
Transmission Rule, PHMSA revised Sec.  192.917 to include seismicity as 
a potential threat for operators to identify and evaluate. In this 
final rule, PHMSA is revising this section to require operators 
consider the seismicity of the area when evaluating additional P&M 
measures against the threat of outside force damage.

Section 192.941 What is a low stress reassessment?

    Section 192.941 specifies that, to address the threat of external 
corrosion on cathodically protected pipe in an HCA segment, an operator 
must perform an electrical survey (i.e., with an indirect examination 
tool or method) at least every 7 years. In this final rule, PHMSA is 
replacing the term ``electrical survey'' with ``indirect assessment'' 
to accommodate other techniques that are comparably effective.

V. Standards Incorporated by Reference

A. Summary of New and Revised Standards

    Consistent with the amendments in this document, PHMSA is 
incorporating by reference into the PSR several standards as described 
below. Some of these standards are already incorporated by reference 
into the PSR and are being extended to other sections of the 
regulations. Other standards provide a technical basis for 
corresponding regulatory changes in this final rule.
     NACE Standard Practice 0204-2008, ``Stress Corrosion 
Cracking (SCC) Direct Assessment Methodology'' (Sept. 18, 2008).
    This standard addresses the situation in which a portion of a 
pipeline has been identified as an area of interest with respect to SCC 
based on its history, operations, and risk assessment process, and it 
has been decided that direct assessment is an appropriate approach for 
integrity assessment. The incorporation of this standard into the PSR 
would provide guidance for managing SCC through the selection of 
potential pipeline segments, selecting dig sites within those segments, 
inspecting the pipe, collecting and analyzing data during the dig, 
establishing a mitigation program, defining the re-evaluation interval, 
and evaluating the effectiveness of the SCCDA process.
     NACE Standard Practice 0206-2006, ``Internal Corrosion 
Direct Assessment Methodology for Pipelines Carrying Normally Dry 
Natural Gas'' (DG-ICDA) (Dec. 1, 2006).
    This standard practice formalizes an internal corrosion direct 
assessment method (DG-ICDA) that can be used to help ensure pipeline 
integrity for pipelines carrying normally dry natural gas. The method 
is applicable to natural gas pipelines that normally carry dry gas but 
that may suffer from infrequent, short-term upsets of liquid water (or 
other electrolyte). This standard is intended for use by pipeline 
operators and others who manage pipeline integrity. The basis of DG-
ICDA is a detailed examination of locations along a pipeline where 
water would first accumulate and provides information about the 
downstream condition of the pipeline. If the locations along a length 
of pipe most likely to accumulate water have not corroded, other 
downstream locations less likely to accumulate water may be considered 
free from corrosion. The presence of extensive corrosion found at many 
locations during the evaluation suggests that the transported gas was 
not normally dry, and this standard would not be considered applicable.
     ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing 
System Integrity of Gas Pipelines'' (Jan. 14, 2005).
    This standard covers onshore gas pipeline systems constructed with 
ferrous materials, including pipe, valves, appurtenances attached to 
pipe, compressor units, metering stations, regulator stations, delivery 
stations, holders, and fabricated assemblies. ASME/ANSI B31.8S is 
specifically designed to provide the operator with the information 
necessary to develop and implement an effective IM program using proven 
industry practices and processes. Effective system management can 
decrease repair and replacement costs, prevent malfunctions, and 
minimize system downtime.
    The incorporation by reference of ASME/ANSI B31.8S-2004 was 
approved for Sec. Sec.  192.921 and 192.937 as of January 14, 2004. 
That approval is unaffected by the section revisions in this final 
rule.
     ANSI/NACE Standard Practice 0502-2010, ``Pipeline External 
Corrosion Direct Assessment Methodology'' (June 24, 2010).
    This standard covers the NACE external corrosion direct assessment 
(ECDA) process, which assesses and

[[Page 52263]]

reduces the impact of external corrosion on pipeline integrity. ECDA is 
a continuous-improvement process providing the advantages of locating 
areas where defects can form in the future, not just areas where 
defects have already formed, thereby helping to prevent future external 
corrosion damage. This standard covers the four components of ECDA: 
Pre-Assessment, Indirect Inspections, Direct Examinations, and Post-
Assessment.
    The incorporation by reference of ANSI/NACE Standard Practice 0502-
2010 was approved for Sec. Sec.  192.923, 192.925, 192.931, 192.935, 
and 192.939 as of March 6, 2015. That approval is unaffected by the 
section revisions in this final rule.
    The incorporation by reference of R-STRENG and ASME/ANSI B31G in 
certain sections of this rule was approved July 1, 2020, and remains 
unaffected by the revisions in this final rule.

B. 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 developing 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 to implement section 12(d) of the NTTAA relative 
to the utilization of consensus technical standards by Federal 
agencies.\57\ This circular provides guidance for agencies 
participating in voluntary consensus standards bodies and describes 
procedures for satisfying the reporting requirements in the NTTAA.
---------------------------------------------------------------------------

    \57\ 81 FR 4673 (Jan. 27, 2016).
---------------------------------------------------------------------------

    Accordingly, PHMSA has the responsibility 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. 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.
    Pursuant to 49 U.S.C. 60102(p), PHMSA may not issue PSR amendments 
that incorporate by reference any documents or portions thereof unless 
the documents or portions thereof are made available to the public, 
free of charge. Further, the Office of the Federal Register issued a 
rulemaking on November 7, 2014, revising 1 CFR 51.5(b) to require that 
agencies detail in the preamble of a final rulemaking the ways the 
materials it incorporates by reference are reasonably available to 
interested parties, and how interested parties can obtain those 
materials.\58\
---------------------------------------------------------------------------

    \58\ 79 FR 66278.
---------------------------------------------------------------------------

    To meet its statutory obligation for this rulemaking, PHMSA 
negotiated agreements with SDOs to provide free online access to 
standards that are incorporated by reference or proposed to be 
incorporated by reference. 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: [email protected]; please include your phone number, 
physical address, and an email address and PHMSA will respond within 5 
business days and provide access to the standard. 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.

VI. Regulatory Analysis and Notices

A. Statutory/Legal Authority for This Rulemaking

    This final rule is published under the existing authorities of the 
Secretary of Transportation delegated to the PHMSA Administrator 
pursuant to 49 CFR 1.97. Among the statutory authorities delegated to 
PHMSA are section 60102 of the Federal Pipeline Safety Statutes (49 
U.S.C. 60101 et seq.) (authorizing issuance of regulations governing 
design, installation, inspection, emergency plans and procedures, 
testing, construction, extension, operation, replacement, and 
maintenance of pipeline facilities) and section 28 of the Mineral 
Leasing Act, as amended (30 U.S.C. 185(w)(3)). For a complete listing 
of authorities, see 49 CFR 1.97.

B. Executive Order 12866 and DOT Regulatory Policies and Procedures

    Executive Order 12866 (``Regulatory Planning and Review'') \59\ 
requires that agencies ``should assess all costs and benefits of 
available regulatory alternatives, including the alternative of not 
regulating.'' Agencies should consider quantifiable measures and 
qualitative measures of costs and benefits that are difficult to 
quantify. Further, Executive Order 12866 requires that agencies 
``should maximize net benefits (including potential economic, 
environmental, public health and safety, and other advantages; 
distributive impacts; and equity), unless a statute requires another 
regulatory approach.'' Similarly, DOT Order 2100.6A (``Rulemaking and 
Guidance Procedures'') requires that regulations issued by PHMSA and 
other DOT Operating Administrations should consider an assessment of 
the potential benefits, costs, and other important impacts of the 
proposed action and should quantify (to the extent practicable) the 
benefits, costs, and any significant distributional impacts, including 
any environmental impacts. The Federal Pipeline Safety Statutes at 49 
U.S.C. 60102(b)(5) further authorize only those safety requirements 
whose benefits (including safety and environmental benefits) have been 
determined to justify their costs.
---------------------------------------------------------------------------

    \59\ 58 FR 51735 (Oct. 4, 1993).
---------------------------------------------------------------------------

    This action has been determined to be significant under Executive 
Order 12866. It is also considered significant under DOT Order 2100.6A 
because of significant congressional, State, industry, and public 
interest in pipeline safety. The final rule has been reviewed by the 
Office of Management and Budget in accordance with Executive Order 
12866 and is consistent with the requirements of Executive Order 12866, 
49 U.S.C. 60102(b)(5), and DOT Order 2100.6. The Office of Information 
and Regulatory Affairs (OIRA) has not designated this rule as a ``major 
rule'' as defined by the Congressional Review Act (5 U.S.C. 801 et 
seq.).
    Executive Order 12866 and DOT Order 2100.6A also require PHMSA to 
provide a meaningful opportunity for public participation, which also 
reinforces requirements for notice and comment under the Administrative 
Procedure Act (5 U.S.C. 551 et seq.). Therefore, in the NPRM, PHMSA 
sought public comment on its proposed revisions to the PSR and the 
preliminary cost and benefit analyses in the PRIA, as

[[Page 52264]]

well as any information that could assist in quantifying the costs and 
benefits of this rulemaking. Those comments are addressed in this final 
rule, and additional discussion about the costs and benefits of the 
final rule are provided within the RIA posted in the rulemaking docket.
    The table below summarizes the annualized costs for the provisions 
in the final rule. These estimates reflect the timing of the compliance 
actions taken by operators and are annualized, where applicable, over 
20 years and discounted using rates of 3 percent and 7 percent. PHMSA 
estimates incremental costs for the final requirements in section 5 of 
the RIA. The costs of this final rule reflect MOC process improvements, 
additional corrosion control requirements, programmatic changes related 
to inspections following extreme weather events, and compliance with 
the revised repair criteria. PHMSA finds that the other final rule 
requirements will not result in an incremental cost. PHMSA estimates 
the annualized cost of this rule is $16.7 million at a 7 percent 
discount rate.

       Table 1--Annualized Cost of the Final Rule, Year 1-Year 20
                          [$2019 USD thousands]
------------------------------------------------------------------------
                                                   Discount rate
                Provision                -------------------------------
                                                3%              7%
------------------------------------------------------------------------
Integrity Management Process                          $0              $0
 Improvements *.........................
Management of Change Process                       1,194           1,223
 Improvements...........................
Corrosion Control.......................           8,662           8,998
Extreme Weather.........................              55              78
Repair Criteria.........................           2,725           6,357
                                         -------------------------------
    Total...............................          12,637          16,656
------------------------------------------------------------------------
* No incremental costs are estimated for this topic area.

    The benefits of the final rule consist of improved safety and 
avoided environmental harms (including greenhouse gas emissions) from 
reduction of risk of incidents on natural gas pipelines and will depend 
on the degree to which compliance actions result in additional safety 
measures, relative to the baseline, and the effectiveness of these 
measures in preventing or mitigating future pipeline releases or other 
incidents. PHMSA changed its benefit analysis approach for the RIA 
relative to the PRIA. The PRIA quantified and monetized the NPRM's 
benefits, while the RIA does not monetize this final rule's benefits. 
PHMSA chose not to monetize benefits in the RIA based on the public 
comments received in response to the PRIA and the uncertainty 
associated with quantifying changes in incident rates that can be 
explicitly attributed to the final rule's provisions.
    For more information, please see the RIA posted in the rulemaking 
docket.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) requires 
agencies to prepare a Final Regulatory Flexibility Analysis (FRFA) for 
any final rule subject to notice-and-comment rulemaking under the APA 
unless the agency head certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
This final rule was developed in accordance with Executive Order 13272 
(``Proper Consideration of Small Entities in Agency Rulemaking'') \60\ 
to promote compliance with the Regulatory Flexibility Act and to ensure 
that the potential impacts of the rulemaking on small entities has been 
properly considered.
---------------------------------------------------------------------------

    \60\ 68 FR 7990 (Feb. 19, 2003).
---------------------------------------------------------------------------

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

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

    PHMSA analyzed this final rule per the principles and criteria in 
Executive Order 13175 (``Consultation and Coordination with Indian 
Tribal Governments'') \61\ and DOT Order 5301.1 (``Department of 
Transportation Policies, Programs, and Procedures Affecting American 
Indians, Alaska Natives, and Tribes''). Executive Order 13175 requires 
agencies to assure meaningful and timely input from Tribal Government 
representatives in the development of rules that significantly or 
uniquely affect Tribal communities by imposing ``substantial direct 
compliance costs'' or ``substantial direct effects'' on such 
communities or the relationship and distribution of power between the 
Federal Government and Tribes.
---------------------------------------------------------------------------

    \61\ 65 FR 67249 (Nov. 6, 2000).
---------------------------------------------------------------------------

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

E. Paperwork Reduction Act

    Under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.), 
no person is required to respond to an information collection unless it 
has been approved by OMB and displays a valid OMB control number. 
Pursuant to implementing regulations at 5 CFR 1320.8(d), PHMSA is 
required to provide interested members of the public and affected 
agencies with an opportunity to comment on information collection and 
recordkeeping requests.
    On April 8, 2016, PHMSA published an NPRM seeking public comments 
on proposed revisions of the PSR

[[Page 52265]]

applicable to the safety of gas transmission pipelines and gas 
gathering pipelines. Based on the provisions in the NPRM, PHMSA 
proposed corresponding changes to information collections. PHMSA 
determined it would be more effective to first advance a rulemaking 
that focused on the mandates from the 2011 Pipeline Safety Act and 
subsequently split out the other provisions contained in the NPRM into 
three separate rules. As such, in this rulemaking, PHMSA has removed 
all references to the changes in the information collections covered in 
those other rulemakings. PHMSA will submit information collection 
revision requests to OMB based on the requirements contained within 
this final rule.
    PHMSA estimates that the proposals in this final rule will involve 
new and amended information collections as described below. 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. Relevant information collections consist 
of the following:
    1. Title: Record Keeping Requirements for Gas Pipeline Operators.
    OMB Control Number: 2137-0049.
    Current Expiration Date: 3/31/2025.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to maintain records, make reports, and provide 
information to the Secretary of Transportation upon request. Based on 
the proposed revisions in this final rule, 16 new recordkeeping 
requirements are being added to the pipeline safety regulations for 
owners and operators of gas transmission pipelines. PHMSA expects these 
new mandatory recordkeeping requirements to result in 1,902 responses 
and 9,530 burden hours.
    Affected Public: Gas Transmission Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,863,374.
    Total Annual Burden Hours: 1,686,560.
    Frequency of Collection: On occasion.
    2. Title: Notification Requirements for Gas Transmission Pipelines.
    OMB Control Number: 2137-0636.
    Current Expiration Date: 01/31/2023.
    Abstract: A person owning or operating a natural gas pipeline 
facility is required to provide information to the Secretary of 
Transportation at the Secretary's request in accordance with 49 U.S.C. 
60117. The regulations in 49 CFR part 192 require operators to make 
various notifications upon the occurrence of certain events. Based on 
the proposed revisions in this final rule, 6 new notification 
requirements are being added to the PSR for owners and operators of gas 
transmission pipelines. PHMSA expects these revisions to result in 268 
additional responses and 290 additional burden hours for this 
information collection. These mandatory notification requirements are 
necessary to ensure safe operation of transmission pipelines, ascertain 
compliance with gas pipeline safety regulations, and to provide a 
background for incident investigations.
    Affected Public: Gas Transmission Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 990.
    Total Annual Burden Hours: 1,360.
    Frequency of Collection: On occasion.
    3. Title: Annual Reports for Gas Pipeline Operators
    OMB Control Number: 2137-0522.
    Current Expiration Date: 3/31/2025.
    Abstract: This information collection covers the collection of 
annual report data from natural gas pipeline operators. PHMSA is 
revising the Gas Transmission and Gas Gathering Annual Report (form 
PHMSA F7 100.2-1) to collect more granular data on conditions being 
repaired outside of HCA segments. Operators currently provide the 
number of anomalies outside of HCAs based on assessment methods, 
however, PHMSA requires operators to further categorize the data in 
accordance with 49 CFR 192.713. Based on the proposed revisions, PHMSA 
estimates that it will take an additional 30 minutes per report to 
include the newly required data--increasing the burden for completing 
each annual report to 47.5 hours. This change results in an overall 
burden increase of 905 hours for this information collection.
    Affected Public: Natural Gas Pipeline Operators.
    Annual Reporting and Recordkeeping Burden:
    Total Annual Responses: 3,053.
    Total Annual Burden Hours: 95,521.
    Frequency of Collection: On occasion.
    Requests for copies of these information collections should be 
directed to Angela Hill or Cameron Satterthwaite, Office of Pipeline 
Safety (PHP-30), Pipeline Hazardous Materials Safety Administration 
(PHMSA), 2nd Floor, 1200 New Jersey Avenue, SE, Washington, DC 20590-
0001, Telephone (202) 366-4595.

F. Unfunded Mandates Reform Act of 1995

    The 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, 
or by the private sector 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.
    As explained in the RIA, PHMSA determined that this final rule does 
not impose enforceable duties on State, local, or Tribal governments or 
on the private sector of $100 million or more (in 1996 dollars) in any 
one year. A copy of the RIA is available for review in the docket.

G. National Environmental Policy Act

    The National Environmental Policy Act of 1969 (42 U.S.C. 4321 et 
seq., NEPA), requires Federal agencies to consider the consequences of 
major Federal actions and prepare a detailed statement on actions 
significantly affecting the quality of the human environment. The 
Council on Environmental Quality implementing regulations (40 CFR parts 
1500-1508) require Federal agencies to conduct an environmental review 
considering (1) the need for the action, (2) alternatives to the 
action, (3) probable environmental impacts of the action and 
alternatives, and (4) the agencies and persons consulted during the 
consideration process. DOT Order 5610.1C (``Procedures for Considering 
Environmental Impacts'') establishes departmental procedures for 
evaluation of environmental impacts under NEPA and its implementing 
regulations.
    PHMSA has completed its NEPA analysis. Based on the environmental 
assessment, PHMSA determined that an environmental impact statement is 
not required for this rulemaking because it will not have a significant 
impact on the human environment. The final EA and Finding of No 
Significant Impact have been placed into the docket addressing the 
comments received.

H. Executive Order 13132

    PHMSA analyzed this final rule in accordance with Executive Order 
13132 (``Federalism'').\62\ Executive Order

[[Page 52266]]

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.''
---------------------------------------------------------------------------

    \62\ 64 FR 43255 (Aug.10, 1999).
---------------------------------------------------------------------------

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

I. Executive Order 13211

    Executive Order 13211 (``Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use'') \63\ 
requires Federal agencies to prepare a Statement of Energy Effects for 
any ``significant energy action.'' Executive Order 13211 defines a 
``significant energy action'' as any action by an agency (normally 
published in the Federal Register) that promulgates, or is expected to 
lead to the promulgation of, a final rule or regulation that (1)(i) is 
a significant regulatory action under Executive Order 12866 or any 
successor order and (ii) is likely to have a significant adverse effect 
on the supply, distribution, or use of energy (including a shortfall in 
supply, price increases, and increased use of foreign supplies); or (2) 
is designated by the Administrator of the OIRA as a significant energy 
action.
---------------------------------------------------------------------------

    \63\ 66 FR 28355 (May 18, 2001).
---------------------------------------------------------------------------

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

J. Privacy Act Statement

    Anyone may search the electronic form of all comments received for 
any of our dockets. You may review DOT's complete Privacy Act Statement 
\64\ at: https://www.govinfo.gov/content/pkg/FR-2000-04-11/pdf/00-8505.pdf.
---------------------------------------------------------------------------

    \64\ 65 FR 19476 (Apr. 11, 2000).
---------------------------------------------------------------------------

K. Executive Order 13609 and International Trade Analysis

    Executive Order 13609 (``Promoting International Regulatory 
Cooperation'') \65\ requires agencies consider whether the impacts 
associated with significant variations between domestic and 
international regulatory approaches are unnecessary or may impair the 
ability of American business to export and compete internationally. In 
meeting shared challenges involving health, safety, labor, security, 
environmental, and other issues, international regulatory cooperation 
can identify approaches that are at least as protective as those that 
are or would be adopted in the absence of such cooperation. 
International regulatory cooperation can also reduce, eliminate, or 
prevent unnecessary differences in regulatory requirements.
---------------------------------------------------------------------------

    \65\ 77 FR 26413 (May 4, 2012).
---------------------------------------------------------------------------

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

L. Environmental Justice

    DOT Order 5610.2(b) and Executive Orders 12898 (``Federal Actions 
to Address Environmental Justice in Minority Populations and Low-Income 
Populations''),\66\ 13985 (``Advancing Racial Equity and Support for 
Underserved Communities Through the Federal Government''),\67\ 13990 
(``Protecting Public Health and the Environment and Restoring Science 
To Tackle the Climate Crisis''),\68\ and 14008 (``Tackling the Climate 
Crisis at Home and Abroad'') \69\ require DOT operational 
administrations to achieve environmental justice as part of their 
mission by identifying and addressing, as appropriate, 
disproportionately high and adverse human health or environmental 
effects, including interrelated social and economic effects, of their 
programs, policies, and activities on minority populations, low-income 
populations, and other underserved disadvantaged communities.
---------------------------------------------------------------------------

    \66\ 59 FR 7629 (Feb. 16, 1994).
    \67\ 86 FR 7009 (Jan. 20, 2021).
    \68\ 86 FR 7037 (Jan. 20, 2021).
    \69\ 86 FR 7619 (Feb. 1, 2021).
---------------------------------------------------------------------------

    PHMSA has evaluated this final rule under DOT Order 5610.2(b) and 
the Executive Orders listed above and determined it would not cause 
disproportionately high and adverse human health and environmental 
effects on minority populations, low-income populations, and other 
underserved and disadvantaged communities. The rulemaking is facially 
neutral and national in scope; it is neither directed toward a 
particular population, region, or community, nor is it expected to 
adversely impact any particular population, region, or community. And 
insofar as PHMSA expects the rulemaking would reduce the safety and 
environmental risks associated with natural gas transmission pipelines, 
many of which are located in the vicinity of environmental justice 
communities,\70\ PHMSA expects the regulatory amendments introduced by 
this final rule would reduce adverse human health and environmental 
risks for minority populations, low-income populations, and other 
underserved and other disadvantaged communities in the vicinity of 
those pipelines. Lastly, as

[[Page 52267]]

explained in the final EA, PHMSA expects that the regulatory amendments 
in this final rule will yield GHG emissions reductions, thereby 
reducing the risks posed by anthropogenic climate change to minority, 
low-income, underserved, and other disadvantaged populations and 
communities.
---------------------------------------------------------------------------

    \70\ See Ryan Emmanuel, et al., ``Natural Gas Gathering and 
Transmission Pipelines and Social Vulnerability in the United 
States,'' 5:6 GeoHealth (June 2021), https://agupubs.onlinelibrary.wiley.com/toc/24711403/2021/5/6 (concluding 
that natural gas gathering and transmission infrastructure is 
disproportionately sited in socially-vulnerable communities).
---------------------------------------------------------------------------

List of Subjects in 49 CFR Part 192

    Corrosion control, Incorporation by reference, Installation of pipe 
in a ditch, Integrity management, Internal inspection device, 
Management of change, Pipeline safety, Repair criteria, Surveillance.
    In consideration of the foregoing, PHMSA amends 49 CFR part 192 as 
follows:

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

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

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

0
2. In Sec.  192.3:
0
a. Add definitions for ``Close interval survey'', ``Distribution 
center'', ``Dry gas or dry natural gas'', ``Hard spot'', ``In-line 
inspection (ILI)'', and ``In-line inspection tool or instrumented 
internal inspection device'' in alphabetical order;
0
b. Revise the definition for ``Transmission line''; and
0
c. Add the definition ``Wrinkle bend'' in alphabetical order.
    The additions and revision read as follows:

Sec.  192.3   Definitions.

* * * * *
    Close interval survey means a series of closely and properly spaced 
pipe-to-electrolyte potential measurements taken over the pipe to 
assess the adequacy of cathodic protection or to identify locations 
where a current may be leaving the pipeline that may cause corrosion 
and for the purpose of quantifying voltage (IR) drops other than those 
across the structure electrolyte boundary, such as when performed as a 
current interrupted, depolarized, or native survey.
* * * * *
    Distribution center means the initial point where gas enters piping 
used primarily to deliver gas to customers who purchase it for 
consumption, as opposed to customers who purchase it for resale, for 
example:
    (1) At a metering location;
    (2) A pressure reduction location; or
    (3) Where there is a reduction in the volume of gas, such as a 
lateral off a transmission line.
* * * * *
    Dry gas or dry natural gas means gas above its dew point and 
without condensed liquids.
* * * * *
    Hard spot means an area on steel pipe material with a minimum 
dimension greater than two inches (50.8 mm) in any direction and 
hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or 
Vickers 345 HV10).
* * * * *
    In-line inspection (ILI) means an inspection of a pipeline from the 
interior of the pipe using an inspection tool also called intelligent 
or smart pigging. This definition includes tethered and self-propelled 
inspection tools.
    In-line inspection tool or instrumented internal inspection device 
means an instrumented device or vehicle that uses a non-destructive 
testing technique to inspect the pipeline from the inside in order to 
identify and characterize flaws to analyze pipeline integrity; also 
known as an intelligent or smart pig.
* * * * *
    Transmission line means a pipeline or connected series of 
pipelines, other than a gathering line, that:
    (1) Transports gas from a gathering pipeline or storage facility to 
a distribution center, storage facility, or large volume customer that 
is not down-stream from a distribution center;
    (2) Has an MAOP of 20 percent or more of SMYS;
    (3) Transports gas within a storage field; or
    (4) Is voluntarily designated by the operator as a transmission 
pipeline.
    Note 1 to transmission line. A large volume customer may receive 
similar volumes of gas as a distribution center, and includes 
factories, power plants, and institutional users of gas.
* * * * *
    Wrinkle bend means a bend in the pipe that:
    (1) Was formed in the field during construction such that the 
inside radius of the bend has one or more ripples with:
    (i) An amplitude greater than or equal to 1.5 times the wall 
thickness of the pipe, measured from peak to valley of the ripple; or
    (ii) With ripples less than 1.5 times the wall thickness of the 
pipe and with a wrinkle length (peak to peak) to wrinkle height (peak 
to valley) ratio under 12.
    (2)(i) If the length of the wrinkle bend cannot be reliably 
determined, then wrinkle bend means a bend in the pipe where (h/D)*100 
exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100 
exceeds for psi [ for MPa] when S is greater than 37,000 psi (255 MPa) 
but less than 47,000 psi (324 MPa), and where (h/D)*100 exceeds 1 when 
S is 47,000 psi (324 MPa) or more.
    (ii) Where:

    (A) D = Outside diameter of the pipe, in. (mm);
    (B) h = Crest-to-trough height of the ripple, in. (mm); and
    (C) S = Maximum operating hoop stress, psi (S/145, MPa).

0
3. In Sec.  192.7:
0
a. Revise paragraphs (a) and (c)(6);
0
b. Redesignate paragraph (h)(1) as paragraph (h)(4) and paragraph 
(h)(2) as paragraph (h)(1);
0
c. Add new paragraph (h)(2) and paragraph (h)(3); and
0
d. Revise newly redesignated paragraph (h)(4).
    The revisions and additions read as follows:

Sec.  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. All approved material is available for 
inspection at the 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 at 
the National Archives and Records Administration (NARA). For 
information on the availability of this material at NARA, email 
[email protected], or go to www.archives.gov/federal-register/cfr/ibr-locations.html. It is also available from the sources in the 
following paragraphs of this section.
* * * * *
    (c) * * *
    (6) ASME/ANSI B31.8S-2004, ``Supplement to B31.8 on Managing System 
Integrity of Gas Pipelines,'' approved January 14, 2005, (ASME/ANSI 
B31.8S), IBR approved for Sec. Sec.  192.13(d); 192.714(c) and (d); 
192.903 note to potential impact radius; 192.907 introductory text and 
(b); 192.911 introductory text, (i), and (k) through (m); 192.913(a) 
through (c); 192.917(a) through (e); 192.921(a); 192.923(b); 
192.925(b); 192.927(b) and (c); 192.929(b); 192.933(c) and (d); 
192.935(a) and (b); 192.937(c); 192.939(a); and 192.945(a).
* * * * *

[[Page 52268]]

    (h) * * *
    (2) NACE SP0204-2008, Standard Practice, ``Stress Corrosion 
Cracking (SCC) Direct Assessment Methodology,'' reaffirmed September 
18, 2008, (NACE SP0204); IBR approved for Sec. Sec.  192.923(b); 
192.929(b) introductory text, (b)(1) through (3), (b)(5) introductory 
text, and (b)(5)(i).
    (3) NACE SP0206-2006, Standard Practice, ``Internal Corrosion 
Direct Assessment Methodology for Pipelines Carrying Normally Dry 
Natural Gas (DG-ICDA),'' approved December 1, 2006, (NACE SP0206), IBR 
approved for Sec. Sec.  192.923(b); 192.927(b), (c) introductory text, 
and (c)(1) through (4).
    (4) ANSI/NACE SP0502-2010, Standard Practice, ``Pipeline External 
Corrosion Direct Assessment Methodology,'' revised June 24, 2010, (NACE 
SP0502), IBR approved for Sec. Sec.  192.319(f); 192.461(h); 
192.923(b); 192.925(b); 192.931(d); 192.935(b); and 192.939(a).
* * * * *

0
4. In Sec.  192.9, paragraphs (b), (c), (d)(1) and (2), and (e)(1)(i) 
and (ii) are revised to read as follows:

Sec.  192.9   What requirements apply to gathering pipelines?

* * * * *
    (b) Offshore lines. An operator of an offshore gathering line must 
comply with requirements of this part applicable to transmission lines, 
except the requirements in Sec. Sec.  192.13(d), 192.150, 192.285(e), 
192.319(d) through (g), 192.461(f) through (i), 192.465(d) and (f), 
192.473(c), 192.478, 192.485(c), 192.493, 192.506, 192.607, 192.613(c), 
192.619(e), 192.624, 192.710, 192.712, and 192.714 and in subpart O of 
this part.
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part 
applicable to transmission lines, except the requirements in Sec. Sec.  
192.13(d), 192.150, 192.285(e), 192.319(d) through (g), 192.461(f) 
through (i), 192.465(d) and (f), 192.473(c), 192.478, 192.485(c) 
192.493, 192.506, 192.607, 192.613(c), 192.619(e), 192.624, 192.710, 
192.712, and 192.714 and in subpart O of this part. However, an 
operator of a Type A regulated onshore gathering line in a Class 2 
location may demonstrate compliance with subpart N of this part by 
describing the processes it uses to determine the qualification of 
persons performing operations and maintenance tasks.
    (d) * * *
    (1) If a line is new, replaced, relocated, or otherwise changed, 
the design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines. Compliance with Sec. Sec.  192.67, 192.127, 
192.179(e) and (f), 192.205, 192.227(c), 192.285(e), 192.319(d) through 
(g), 192.506, 192.634, and 192.636 is not required;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission 
lines, except the requirements in Sec. Sec.  192.461(f) through (i), 
192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
* * * * *
    (e) * * *
    (1) * * *
    (i) Except as provided in paragraph (h) of this section for pipe 
and components made with composite materials, the design, installation, 
construction, initial inspection, and initial testing of a new, 
replaced, relocated, or otherwise changed Type C gathering line, must 
be done in accordance with the requirements in subparts B through G and 
J of this part applicable to transmission lines. Compliance with 
Sec. Sec.  192.67, 192.127, 192.179(e) and (f), 192.205, 192.227(c), 
192.285(e), 192.319(d) through (g), 192.506, 192.634, and 192.636 is 
not required;
    (ii) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission 
lines, except the requirements in Sec. Sec.  192.461(f) through (i), 
192.465(d) and (f), 192.473(c), 192.478, 192.485(c), and 192.493;
* * * * *

0
5. In Sec.  192.13, paragraph (d) is added to read as follows:

Sec.  192.13   What general requirements apply to pipelines regulated 
under this part?

* * * * *
    (d) Each operator of an onshore gas transmission pipeline must 
evaluate and mitigate, as necessary, significant changes that pose a 
risk to safety or the environment through a management of change 
process. Each operator of an onshore gas transmission pipeline must 
develop and follow a management of change process, as outlined in ASME/
ANSI B31.8S, section 11 (incorporated by reference, see Sec.  192.7), 
that addresses technical, design, physical, environmental, procedural, 
operational, maintenance, and organizational changes to the pipeline or 
processes, whether permanent or temporary. A management of change 
process must include the following: reason for change, authority for 
approving changes, analysis of implications, acquisition of required 
work permits, documentation, communication of change to affected 
parties, time limitations, and qualification of staff. For pipeline 
segments other than those covered in subpart O of this part, this 
management of change process must be implemented by February 26, 2024. 
The requirements of this paragraph (d) do not apply to gas gathering 
pipelines. Operators may request an extension of up to 1 year by 
submitting a notification to PHMSA at least 90 days before February 26, 
2024, in accordance with Sec.  192.18. The notification must include a 
reasonable and technically justified basis, an up-to-date plan for 
completing all actions required by this section, the reason for the 
requested extension, current safety or mitigation status of the 
pipeline segment, the proposed completion date, and any needed 
temporary safety measures to mitigate the impact on safety.

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

Sec.  192.18  How to notify PHMSA.

* * * * *
    (c) Unless otherwise specified, if an operator submits, pursuant to 
Sec.  192.8, Sec.  192.9, Sec.  192.13, Sec.  192.179, Sec.  192.319, 
Sec.  192.461, Sec.  192.506, Sec.  192.607, Sec.  192.619, Sec.  
192.624, Sec.  192.632, Sec.  192.634, Sec.  192.636, Sec.  192.710, 
Sec.  192.712, Sec.  192.714, Sec.  192.745, Sec.  192.917, Sec.  
192.921, Sec.  192.927, Sec.  192.933, or Sec.  192.937, a notification 
for use of a different integrity assessment method, analytical method, 
compliance period, sampling approach, pipeline material, or technique 
(e.g., ``other technology'' or ``alternative equivalent technology'') 
than otherwise prescribed in those sections, that notification must be 
submitted to PHMSA for review at least 90 days in advance of using the 
other method, approach, compliance timeline, or technique. An operator 
may proceed to use the other method, approach, compliance timeline, or 
technique 91 days after submitting the notification unless it receives 
a letter from the Associate Administrator for Pipeline Safety informing 
the operator that PHMSA objects to the proposal or that PHMSA requires 
additional time and/or more information to conduct its review.

0
7. In Sec.  192.319, paragraphs (d) through (g) are added to read as 
follows:

Sec.  192.319   Installation of pipe in a ditch.

* * * * *
    (d) Promptly after a ditch for an onshore steel transmission line 
is backfilled (if the construction project involves 1,000 feet or more 
of continuous backfill length along the

[[Page 52269]]

pipeline), but not later than 6 months after placing the pipeline in 
service, the operator must perform an assessment to assess any coating 
damage and ensure integrity of the coating using direct current voltage 
gradient (DCVG), alternating current voltage gradient (ACVG), or other 
technology that provides comparable information about the integrity of 
the coating. Coating surveys must be conducted, except in locations 
where effective coating surveys are precluded by geographical, 
technical, or safety reasons.
    (e) An operator must notify PHMSA in accordance with Sec.  192.18 
at least 90 days in advance of using other technology to assess 
integrity of the coating under paragraph (d) of this section.
    (f) An operator must repair any coating damage classified as severe 
(voltage drop greater than 60 percent for DCVG or 70 dB[micro]V for 
ACVG) in accordance with section 4 of NACE SP0502 (incorporated by 
reference, see Sec.  192.7) within 6 months after the pipeline is 
placed in service, or as soon as practicable after obtaining necessary 
permits, not to exceed 6 months after the receipt of permits.
    (g) An operator of an onshore steel transmission pipeline must make 
and retain for the life of the pipeline records documenting the coating 
assessment findings and remedial actions performed under paragraphs (d) 
through (f) of this section.

0
8. In Sec.  192.461, paragraph (a)(4) is revised and paragraphs (f) 
through (i) are added to read as follows:

Sec.  192.461  External corrosion control: Protective coating.

    (a) * * *
    (4) Have sufficient strength to resist damage due to handling 
(including, but not limited to, transportation, installation, boring, 
and backfilling) and soil stress; and
* * * * *
    (f) Promptly after the backfill of an onshore steel transmission 
pipeline ditch following repair or replacement (if the repair or 
replacement results in 1,000 feet or more of backfill length along the 
pipeline), but no later than 6 months after the backfill, the operator 
must perform an assessment to assess any coating damage and ensure 
integrity of the coating using direct current voltage gradient (DCVG), 
alternating current voltage gradient (ACVG), or other technology that 
provides comparable information about the integrity of the coating. 
Coating surveys must be conducted, except in locations where effective 
coating surveys are precluded by geographical, technical, or safety 
reasons.
    (g) An operator must notify PHMSA in accordance with Sec.  192.18 
at least 90 days in advance of using other technology to assess 
integrity of the coating under paragraph (f) of this section.
    (h) An operator of an onshore steel transmission pipeline must 
develop a remedial action plan and apply for any necessary permits 
within 6 months of completing the assessment that identified the 
deficiency. The operator must repair any coating damage classified as 
severe (voltage drop greater than 60 percent for DCVG or 70 dB[micro]V 
for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by 
reference, see Sec.  192.7) within 6 months of the assessment, or as 
soon as practicable after obtaining necessary permits, not to exceed 6 
months after the receipt of permits.
    (i) An operator of an onshore steel transmission pipeline must make 
and retain for the life of the pipeline records documenting the coating 
assessment findings and remedial actions performed under paragraphs (f) 
through (h) of this section.

0
9. In Sec.  192.465, the section heading and paragraph (d) are revised 
and paragraph (f) is added to read as follows:

Sec.  192.465  External corrosion control: Monitoring and remediation.

* * * * *
    (d) Each operator must promptly correct any deficiencies indicated 
by the inspection and testing required by paragraphs (a) through (c) of 
this section. For onshore gas transmission pipelines, each operator 
must develop a remedial action plan and apply for any necessary permits 
within 6 months of completing the inspection or testing that identified 
the deficiency. Remedial action must be completed promptly, but no 
later than the earliest of the following: prior to the next inspection 
or test interval required by this section; within 1 year, not to exceed 
15 months, of the inspection or test that identified the deficiency; or 
as soon as practicable, not to exceed 6 months, after obtaining any 
necessary permits.
* * * * *
    (f) An operator must determine the extent of the area with 
inadequate cathodic protection for onshore gas transmission pipelines 
where any annual test station reading (pipe-to-soil potential 
measurement) indicates cathodic protection levels below the required 
levels in appendix D to this part.
    (1) Gas transmission pipeline operators must investigate and 
mitigate any non-systemic or location-specific causes.
    (2) To address systemic causes, an operator must conduct close 
interval surveys in both directions from the test station with a low 
cathodic protection reading at a maximum interval of approximately 5 
feet or less. An operator must conduct close interval surveys unless it 
is impractical based upon geographical, technical, or safety reasons. 
An operator must complete close interval surveys required by this 
section with the protective current interrupted unless it is 
impractical to do so for technical or safety reasons. An operator must 
remediate areas with insufficient cathodic protection levels, or areas 
where protective current is found to be leaving the pipeline, in 
accordance with paragraph (d) of this section. An operator must confirm 
the restoration of adequate cathodic protection following the 
implementation of remedial actions undertaken to mitigate systemic 
causes of external corrosion.

0
10. In Sec.  192.473, paragraph (c) is added to read as follows:

Sec.  192.473  External corrosion control: Interference currents.

* * * * *
    (c) For onshore gas transmission pipelines, the program required by 
paragraph (a) of this section must include:
    (1) Interference surveys for a pipeline system to detect the 
presence and level of any electrical stray current. Interference 
surveys must be conducted when potential monitoring indicates a 
significant increase in stray current, or when new potential stray 
current sources are introduced, such as through co-located pipelines, 
structures, or high voltage alternating current (HVAC) power lines, 
including from additional generation, a voltage up-rating, additional 
lines, new or enlarged power substations, or new pipelines or other 
structures;
    (2) Analysis of the results of the survey to determine the cause of 
the interference and whether the level could cause significant 
corrosion, impede safe operation, or adversely affect the environment 
or public;
    (3) Development of a remedial action plan to correct any instances 
where interference current is greater than or equal to 100 amps per 
meter squared or if it impedes the safe operation of a pipeline, or if 
it may cause a condition that would adversely impact the environment or 
the public; and
    (4) Application for any necessary permits within 6 months of 
completing the interference survey that identified

[[Page 52270]]

the deficiency. An operator must complete remedial actions promptly, 
but no later than the earliest of the following: within 15 months after 
completing the interference survey that identified the deficiency; or 
as soon as practicable, but not to exceed 6 months, after obtaining any 
necessary permits.

0
11. Section 192.478 is added to read as follows:

Sec.  192.478  Internal corrosion control: Onshore transmission 
monitoring and mitigation.

    (a) Each operator of an onshore gas transmission pipeline with 
corrosive constituents in the gas being transported must develop and 
implement a monitoring and mitigation program to mitigate the corrosive 
effects, as necessary. Potentially corrosive constituents include, but 
are not limited to: carbon dioxide, hydrogen sulfide, sulfur, microbes, 
and liquid water, either by itself or in combination. An operator must 
evaluate the partial pressure of each corrosive constituent, where 
applicable, by itself or in combination, to evaluate the effect of the 
corrosive constituents on the internal corrosion of the pipe and 
implement mitigation measures as necessary.
    (b) The monitoring and mitigation program described in paragraph 
(a) of this section must include:
    (1) The use of gas-quality monitoring methods at points where gas 
with potentially corrosive contaminants enters the pipeline to 
determine the gas stream constituents.
    (2) Technology to mitigate the potentially corrosive gas stream 
constituents. Such technologies may include product sampling, inhibitor 
injections, in-line cleaning pigging, separators, or other technology 
that mitigates potentially corrosive effects.
    (3) An evaluation at least once each calendar year, at intervals 
not to exceed 15 months, to ensure that potentially corrosive gas 
stream constituents are effectively monitored and mitigated.
    (c) An operator must review its monitoring and mitigation program 
at least once each calendar year, at intervals not to exceed 15 months, 
and based on the results of its monitoring and mitigation program, 
implement adjustments, as necessary.

0
12. In Sec.  192.485, paragraph (c) is revised to read as follows:

Sec.  192.485   Remedial measures: Transmission lines.

* * * * *
    (c) Calculating remaining strength. Under paragraphs (a) and (b) of 
this section, the strength of pipe based on actual remaining wall 
thickness must be determined and documented in accordance with Sec.  
192.712.

0
13. In Sec.  192.613, paragraph (c) is added to read as follows:

Sec.  192.613   Continuing surveillance.

* * * * *
    (c) Following an extreme weather event or natural disaster that has 
the likelihood of damage to pipeline facilities by the scouring or 
movement of the soil surrounding the pipeline or movement of the 
pipeline, such as a named tropical storm or hurricane; a flood that 
exceeds the river, shoreline, or creek high-water banks in the area of 
the pipeline; a landslide in the area of the pipeline; or an earthquake 
in the area of the pipeline, an operator must inspect all potentially 
affected onshore transmission pipeline facilities to detect conditions 
that could adversely affect the safe operation of that pipeline.
    (1) An operator must assess the nature of the event and the 
physical characteristics, operating conditions, location, and prior 
history of the affected pipeline in determining the appropriate method 
for performing the initial inspection to determine the extent of any 
damage and the need for the additional assessments required under this 
paragraph (c)(1).
    (2) An operator must commence the inspection required by paragraph 
(c) of this section within 72 hours after the point in time when the 
operator reasonably determines that the affected area can be safely 
accessed by personnel and equipment, and the personnel and equipment 
required to perform the inspection as determined by paragraph (c)(1) of 
this section are available. If an operator is unable to commence the 
inspection due to the unavailability of personnel or equipment, the 
operator must notify the appropriate PHMSA Region Director as soon as 
practicable.
    (3) An operator must take prompt and appropriate remedial action to 
ensure the safe operation of a pipeline based on the information 
obtained as a result of performing the inspection required by paragraph 
(c) of this section. Such actions might include, but are not limited 
to:
    (i) Reducing the operating pressure or shutting down the pipeline;
    (ii) Modifying, repairing, or replacing any damaged pipeline 
facilities;
    (iii) Preventing, mitigating, or eliminating any unsafe conditions 
in the pipeline right-of-way;
    (iv) Performing additional patrols, surveys, tests, or inspections;
    (v) Implementing emergency response activities with Federal, State, 
or local personnel; or
    (vi) Notifying affected communities of the steps that can be taken 
to ensure public safety.

0
14. In Sec.  192.710, paragraph (f) is revised as follows:

Sec.  192.710  Transmission lines: Assessments outside of high 
consequence areas.

* * * * *
    (f) Remediation. An operator must comply with the requirements in 
Sec. Sec.  192.485, 192.711, 192.712, 192.713, and 192.714, where 
applicable, if a condition that could adversely affect the safe 
operation of a pipeline is discovered.
* * * * *

0
15. In Sec.  192.711, paragraph (b)(1) is revised to read as follows:

Sec.  192.711  Transmission lines: General requirements for repair 
procedures.

* * * * *
    (b) * * *
    (1)(i) Non-integrity management repairs for gathering lines and 
offshore transmission lines: For gathering lines subject to this 
section in accordance with Sec.  192.9 and for offshore transmission 
lines, an operator must make permanent repairs as soon as feasible.
    (ii) Non-integrity management repairs for onshore transmission 
lines: Except for gathering lines exempted from this section in 
accordance with Sec.  192.9 and offshore transmission lines, after May 
24, 2023, whenever an operator discovers any condition that could 
adversely affect the safe operation of a pipeline segment not covered 
by an integrity management program under subpart O of this part, it 
must correct the condition as prescribed in Sec.  192.714.
* * * * *

0
16. In Sec.  192.712, the section heading and paragraph (b) are revised 
and paragraphs (c) and (h) are added to read as follows:

Sec.  192.712  Analysis of predicted failure pressure and critical 
strain level.

* * * * *
    (b) Corrosion metal loss. When analyzing corrosion metal loss under 
this section, an operator must use a suitable remaining strength 
calculation method including, ASME/ANSI B31G (incorporated by 
reference, see Sec.  192.7); R-STRENG (incorporated by reference, see 
Sec.  192.7); or an alternative equivalent method of remaining strength 
calculation that will provide an equally conservative result.
    (1) If an operator would choose to use a remaining strength 
calculation method that could provide a less conservative result than 
the methods listed in

[[Page 52271]]

paragraph (b) introductory text, the operator must notify PHMSA in 
advance in accordance with Sec.  192.18(c).
    (2) The notification provided for by paragraph (b)(1) of this 
section must include a comparison of its predicted failure pressures to 
R-STRENG or ASME/ANSI B31G, all burst pressure tests used, and any 
other technical reviews used to qualify the calculation method(s) for 
varying corrosion profiles.
    (c) Dents and other mechanical damage. To evaluate dents and other 
mechanical damage that could result in a stress riser or other 
integrity impact, an operator must develop a procedure and perform an 
engineering critical assessment as follows:
    (1) Identify and evaluate potential threats to the pipe segment in 
the vicinity of the anomaly or defect, including ground movement, 
external loading, fatigue, cracking, and corrosion.
    (2) Review high-resolution magnetic flux leakage (HR-MFL) high-
resolution deformation, inertial mapping, and crack detection inline 
inspection data for damage in the dent area and any associated weld 
region, including available data from previous inline inspections.
    (3) Perform pipeline curvature-based strain analysis using recent 
HR-Deformation inspection data.
    (4) Compare the dent profile between the most recent and previous 
in-line inspections to identify significant changes in dent depth and 
shape.
    (5) Identify and quantify all previous and present significant 
loads acting on the dent.
    (6) Evaluate the strain level associated with the anomaly or defect 
and any nearby welds using Finite Element Analysis, or other technology 
in accordance with this section. Using Finite Element Analysis to 
quantify the dent strain, and then estimating and evaluating the damage 
using the Strain Limit Damage (SLD) and Ductile Failure Damage 
Indicator (DFDI) at the dent, are appropriate evaluation methods.
    (7) The analyses performed in accordance with this section must 
account for material property uncertainties, model inaccuracies, and 
inline inspection tool sizing tolerances.
    (8) Dents with a depth greater than 10 percent of the pipe outside 
diameter or with geometric strain levels that exceed the lessor of 10 
percent or exceed the critical strain for the pipe material properties 
must be remediated in accordance with Sec.  192.713, Sec.  192.714, or 
Sec.  192.933, as applicable.
    (9) Using operational pressure data, a valid fatigue life 
prediction model that is appropriate for the pipeline segment, and 
assuming a reassessment safety factor of 5 or greater for the 
assessment interval, estimate the fatigue life of the dent by Finite 
Element Analysis or other analytical technique that is technically 
appropriate for dent assessment and reassessment intervals in 
accordance with this section. Multiple dent or other fatigue models 
must be used for the evaluation as a part of the engineering critical 
assessment.
    (10) If the dent or mechanical damage is suspected to have cracks, 
then a crack growth rate assessment is required to ensure adequate life 
for the dent with crack(s) until remediation or the dent with crack(s) 
must be evaluated and remediated in accordance with the criteria and 
timing requirements in Sec.  192.713, Sec.  192.714, or Sec.  192.933, 
as applicable.
    (11) An operator using an engineering critical assessment 
procedure, other technologies, or techniques to comply with paragraph 
(c) of this section must submit advance notification to PHMSA, with the 
relevant procedures, in accordance with Sec.  192.18.
* * * * *
    (h) Reassessments. If an operator uses an engineering critical 
assessment method in accordance with paragraphs (c) and (d) of this 
section to determine the maximum reevaluation intervals, the operator 
must reassess the anomalies as follows:
    (1) If the anomaly is in an HCA, the operator must reassess the 
anomaly within a maximum of 7 years in accordance with Sec.  
192.939(a), unless the safety factor is expected to go below what is 
specified in paragraph (c) or (d) of this section.
    (2) If the anomaly is outside of an HCA, the operator must perform 
a reassessment of the anomaly within a maximum of 10 years in 
accordance with Sec.  192.710(b), unless the anomaly safety factor is 
expected to go below what is specified in paragraph (c) or (d) of this 
section.

0
17. Section 192.714 is added to read as follows:

Sec.  192.714  Transmission lines: Repair criteria for onshore 
transmission pipelines.

    (a) Applicability. This section applies to onshore transmission 
pipelines not subject to the repair criteria in subpart O of this part, 
and which do not operate under an alternative MAOP in accordance with 
Sec. Sec.  192.112, 192.328, and 192.620. Pipeline segments that are 
located in high consequence areas, as defined in Sec.  192.903, must 
comply with the applicable actions specified by the integrity 
management requirements in subpart O. Pipeline segments operating under 
an alternative MAOP in accordance with Sec. Sec.  192.112, 192.328, and 
192.620 must comply with Sec.  192.620(d)(11).
    (b) General. Each operator must, in repairing its pipeline systems, 
ensure that the repairs are made in a safe manner and are made to 
prevent damage to persons, property, and the environment. A pipeline 
segment's operating pressure must be less than the predicted failure 
pressure determined in accordance with Sec.  192.712 during repair 
operations. Repairs performed in accordance with this section must use 
pipe and material properties that are documented in traceable, 
verifiable, and complete records. If documented data required for any 
analysis, including predicted failure pressure for determining MAOP, is 
not available, an operator must obtain the undocumented data through 
Sec.  192.607.
    (c) Schedule for evaluation and remediation. An operator must 
remediate conditions according to a schedule that prioritizes the 
conditions for evaluation and remediation. Unless paragraph (d) of this 
section provides a special requirement for remediating certain 
conditions, an operator must calculate the predicted failure pressure 
of anomalies or defects and follow the schedule in ASME/ANSI B31.8S 
(incorporated by reference, see Sec.  192.7), section 7, Figure 4. If 
an operator cannot meet the schedule for any condition, the operator 
must document the reasons why it cannot meet the schedule and how the 
changed schedule will not jeopardize public safety. Each condition that 
meets any of the repair criteria in paragraph (d) of this section in an 
onshore steel transmission pipeline must be--
    (1) Removed by cutting out and replacing a cylindrical piece of 
pipe that will permanently restore the pipeline's MAOP based on the use 
of Sec.  192.105 and the design factors for the class location in which 
it is located; or
    (2) Repaired by a method, shown by technically proven engineering 
tests and analyses, that will permanently restore the pipeline's MAOP 
based upon the determined predicted failure pressure times the design 
factor for the class location in which it is located.
    (d) Remediation of certain conditions. For onshore transmission 
pipelines not located in high consequence areas, an operator must 
remediate a listed condition according to the following criteria:
    (1) Immediate repair conditions. An operator must repair the 
following conditions immediately upon discovery:
    (i) Metal loss anomalies where a calculation of the remaining 
strength of the pipe at the location of the anomaly

[[Page 52272]]

shows a predicted failure pressure, determined in accordance with Sec.  
192.712(b), of less than or equal to 1.1 times the MAOP.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless an engineering analysis performed in accordance with 
Sec.  192.712(c) demonstrates critical strain levels are not exceeded.
    (iii) Metal loss greater than 80 percent of nominal wall regardless 
of dimensions.
    (iv) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or has a 
longitudinal joint factor less than 1.0, and the predicted failure 
pressure determined in accordance with Sec.  192.712(d) is less than 
1.25 times the MAOP.
    (v) A crack or crack-like anomaly meeting any of the following 
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of 
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection 
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.25 times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person 
designated by the operator to evaluate the assessment results, requires 
immediate action.
    (2) Two-year conditions. An operator must repair the following 
conditions within 2 years of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless an 
engineering analysis performed in accordance with Sec.  192.712(c) 
demonstrates critical strain levels are not exceeded.
    (ii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or at a longitudinal or 
helical (spiral) seam weld, unless an engineering analysis performed in 
accordance with Sec.  192.712(c) demonstrates critical strain levels 
are not exceeded.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions 
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless an engineering analysis performed in accordance with 
Sec.  192.712(c) demonstrates critical strain levels are not exceeded.
    (iv) For metal loss anomalies, a calculation of the remaining 
strength of the pipe shows a predicted failure pressure, determined in 
accordance with Sec.  192.712(b) at the location of the anomaly, of 
less than 1.39 times the MAOP for Class 2 locations, or less than 1.50 
times the MAOP for Class 3 and 4 locations. For metal loss anomalies in 
Class 1 locations with a predicted failure pressure greater than 1.1 
times MAOP, an operator must follow the remediation schedule specified 
in ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7), 
section 7, Figure 4, as specified in paragraph (c) of this section.
    (v) Metal loss that is located at a crossing of another pipeline, 
is in an area with widespread circumferential corrosion, or could 
affect a girth weld, and that has a predicted failure pressure, 
determined in accordance with Sec.  192.712(b), less than 1.39 times 
the MAOP for Class 1 locations or where Class 2 locations contain Class 
1 pipe that has been uprated in accordance with Sec.  192.611, or less 
than 1.50 times the MAOP for all other Class 2 locations and all Class 
3 and 4 locations.
    (vi) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that 
has a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure determined in accordance with Sec.  192.712(d) is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (vii) A crack or crack-like anomaly that has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (3) Monitored conditions. An operator must record and monitor the 
following conditions during subsequent risk assessments and integrity 
assessments for any change that may require remediation.
    (i) A dent that is located between the 4 o'clock and 8 o'clock 
positions (bottom \1/3\ of the pipe) with a depth greater than 6 
percent of the pipeline diameter (greater than 0.50 inches in depth for 
a pipeline diameter less than NPS 12).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than NPS 12), and where an engineering analysis performed 
in accordance with Sec.  192.712(c) determines that critical strain 
levels are not exceeded.
    (iii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or longitudinal or 
helical (spiral) seam weld, and where an engineering analysis of the 
dent and girth or seam weld, performed in accordance with Sec.  
192.712(c), demonstrates critical strain levels are not exceeded. These 
analyses must consider weld mechanical properties.
    (iv) A dent that has metal loss, cracking, or a stress riser, and 
where an engineering analysis performed in accordance with Sec.  
192.712(c) demonstrates critical strain levels are not exceeded.
    (v) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or that 
has a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure, determined in accordance with Sec.  192.712(d), is 
greater than or equal to 1.39 times the MAOP for Class 1 locations or 
where Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or is greater than or equal to 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) A crack or crack-like anomaly for which the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than or equal to 1.39 times the MAOP for Class 1 locations or where 
Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or is greater than or equal to 1.50 
times the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (e) Temporary pressure reduction. (1) Immediately upon discovery 
and until an operator remediates the condition specified in paragraph 
(d)(1) of this section, or upon a determination by an

[[Page 52273]]

operator that it is unable to respond within the time limits for the 
conditions specified in paragraph (d)(2) of this section, the operator 
must reduce the operating pressure of the affected pipeline to any one 
of the following based on safety considerations for the public and 
operating personnel:
    (i) A level not exceeding 80 percent of the operating pressure at 
the time the condition was discovered;
    (ii) A level not exceeding the predicted failure pressure times the 
design factor for the class location in which the affected pipeline is 
located; or
    (iii) A level not exceeding the predicted failure pressure divided 
by 1.1.
    (2) An operator must notify PHMSA in accordance with Sec.  192.18 
if it cannot meet the schedule for evaluation and remediation required 
under paragraph (c) or (d) of this section and cannot provide safety 
through a temporary reduction in operating pressure or other action. 
Notification to PHMSA does not alleviate an operator from the 
evaluation, remediation, or pressure reduction requirements in this 
section.
    (3) When a pressure reduction, in accordance with paragraph (e) of 
this section, exceeds 365 days, an operator must notify PHMSA in 
accordance with Sec.  192.18 and explain the reasons for the 
remediation delay. This notice must include a technical justification 
that the continued pressure reduction will not jeopardize the integrity 
of the pipeline.
    (4) An operator must document and keep records of the calculations 
and decisions used to determine the reduced operating pressure and the 
implementation of the actual reduced operating pressure for a period of 
5 years after the pipeline has been repaired.
    (f) Other conditions. Unless another timeframe is specified in 
paragraph (d) of this section, an operator must take appropriate 
remedial action to correct any condition that could adversely affect 
the safe operation of a pipeline system in accordance with the 
criteria, schedules, and methods defined in the operator's operating 
and maintenance procedures.
    (g) In situ direct examination of crack defects. Whenever an 
operator finds conditions that require the pipeline to be repaired, in 
accordance with this section, an operator must perform a direct 
examination of known locations of cracks or crack-like defects using 
technology that has been validated to detect tight cracks (equal to or 
less than 0.008 inches crack opening), such as inverse wave field 
extrapolation (IWEX), phased array ultrasonic testing (PAUT), 
ultrasonic testing (UT), or equivalent technology. ``In situ'' 
examination tools and procedures for crack assessments (length, depth, 
and volumetric) must have performance and evaluation standards, 
including pipe or weld surface cleanliness standards for the 
inspection, confirmed by subject matter experts qualified by knowledge, 
training, and experience in direct examination inspection for accuracy 
of the type of defects and pipe material being evaluated. The 
procedures must account for inaccuracies in evaluations and fracture 
mechanics models for failure pressure determinations.
    (h) Determining predicted failure pressures and critical strain 
levels. An operator must perform all determinations of predicted 
failure pressures and critical strain levels required by this section 
in accordance with Sec.  192.712.

0
18. In Sec.  192.911, paragraph (k) is revised to read as follows:

Sec.  192.911   What are the elements of an integrity management 
program?

* * * * *
    (k) A management of change process as required by Sec.  192.13(d).
* * * * *

0
19. In Sec.  192.917, paragraphs (a) through (d) are revised to read as 
follows:

Sec.  192.917   How does an operator identify potential threats to 
pipeline integrity and use the threat identification in its integrity 
program?

    (a) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see 
Sec.  192.7), section 2, which are grouped under the following four 
threat categories:
    (1) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (2) Stable threats, such as manufacturing, welding, fabrication, or 
construction defects;
    (3) Time independent threats, such as third party damage, 
mechanical damage, incorrect operational procedure, weather related and 
outside force damage, to include consideration of seismicity, geology, 
and soil stability of the area; and
    (4) Human error, such as operational or maintenance mishaps, or 
design and construction mistakes.
    (b) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must 
gather and integrate existing data and information on the entire 
pipeline that could be relevant to the covered segment. In performing 
data gathering and integration, an operator must follow the 
requirements in ASME/ANSI B31.8S, section 4.
    Operators must begin to integrate all pertinent data elements 
specified in this section starting on May 24, 2023, with all available 
attributes integrated by February 26, 2024. An operator may request an 
extension of up to 1 year by submitting a notification to PHMSA at 
least 90 days before February 26, 2024, in accordance with Sec.  
192.18. The notification must include a reasonable and technically 
justified basis, an up-to-date plan for completing all actions required 
by this paragraph (b), the reason for the requested extension, current 
safety or mitigation status of the pipeline segment, the proposed 
completion date, and any needed temporary safety measures to mitigate 
the impact on safety. An operator must gather and evaluate the set of 
data listed in paragraph (b)(1) of this section. The evaluation must 
analyze both the covered segment and similar non-covered segments, and 
it must:
    (1) Integrate pertinent information about pipeline attributes to 
ensure safe operation and pipeline integrity, including information 
derived from operations and maintenance activities required under this 
part, and other relevant information, including, but not limited to:
    (i) Pipe diameter, wall thickness, seam type, and joint factor;
    (ii) Manufacturer and manufacturing date, including manufacturing 
data and records;
    (iii) Material properties including, but not limited to, grade, 
specified minimum yield strength (SMYS), and ultimate tensile strength;
    (iv) Equipment properties;
    (v) Year of installation;
    (vi) Bending method;
    (vii) Joining method, including process and inspection results;
    (viii) Depth of cover;
    (ix) Crossings, casings (including if shorted), and locations of 
foreign line crossings and nearby high voltage power lines;
    (x) Hydrostatic or other pressure test history, including test 
pressures and test leaks or failures, failure causes, and repairs;
    (xi) Pipe coating methods (both manufactured and field applied), 
including the method or process used to apply girth weld coating, 
inspection reports, and coating repairs;
    (xii) Soil, backfill;

[[Page 52274]]

    (xiii) Construction inspection reports, including but not limited 
to:
    (A) Post backfill coating surveys; and
    (B) Coating inspection (``jeeping'' or ``holiday inspection'') 
reports;
    (xiv) Cathodic protection installed, including, but not limited to, 
type and location;
    (xv) Coating type;
    (xvi) Gas quality;
    (xvii) Flow rate;
    (xviii) Normal maximum and minimum operating pressures, including 
maximum allowable operating pressure (MAOP);
    (xix) Class location;
    (xx) Leak and failure history, including any in-service ruptures or 
leaks from incident reports, abnormal operations, safety-related 
conditions (both reported and unreported) and failure investigations 
required by Sec.  192.617, and their identified causes and 
consequences;
    (xxi) Coating condition;
    (xxii) Cathodic protection (CP) system performance;
    (xxiii) Pipe wall temperature;
    (xxiv) Pipe operational and maintenance inspection reports, 
including, but not limited to:
    (A) Data gathered through integrity assessments required under this 
part, including, but not limited to, in-line inspections, pressure 
tests, direct assessments, guided wave ultrasonic testing, or other 
methods;
    (B) Close interval survey (CIS) and electrical survey results;
    (C) CP rectifier readings;
    (D) CP test point survey readings and locations;
    (E) Alternating current, direct current, and foreign structure 
interference surveys;
    (F) Pipe coating surveys, including surveys to detect coating 
damage, disbonded coatings, or other conditions that compromise the 
effectiveness of corrosion protection, including, but not limited to, 
direct current voltage gradient or alternating current voltage gradient 
inspections;
    (G) Results of examinations of exposed portions of buried pipelines 
(e.g., pipe and pipe coating condition, see Sec.  192.459), including 
the results of any non-destructive examinations of the pipe, seam, or 
girth weld (i.e. bell hole inspections);
    (H) Stress corrosion cracking excavations and findings;
    (I) Selective seam weld corrosion excavations and findings;
    (J) Any indication of seam cracking; and
    (K) Gas stream sampling and internal corrosion monitoring results, 
including cleaning pig sampling results;
    (xxv) External and internal corrosion monitoring;
    (xxvi) Operating pressure history and pressure fluctuations, 
including an analysis of effects of pressure cycling and instances of 
exceeding MAOP by any amount;
    (xxvii) Performance of regulators, relief valves, pressure control 
devices, or any other device to control or limit operating pressure to 
less than MAOP;
    (xxviii) Encroachments;
    (xxix) Repairs;
    (xxx) Vandalism;
    (xxxi) External forces;
    (xxxii) Audits and reviews;
    (xxxiii) Industry experience for incident, leak, and failure 
history;
    (xxxiv) Aerial photography; and
    (xxxv) Exposure to natural forces in the area of the pipeline, 
including seismicity, geology, and soil stability of the area.
    (2) Use validated information and data as inputs, to the maximum 
extent practicable. If input is obtained from subject matter experts 
(SME), an operator must employ adequate control measures to ensure 
consistency and accuracy of information. Control measures may include 
training of SMEs or the use of outside technical experts (independent 
expert reviews) to assess the quality of processes and the judgment of 
SMEs. An operator must document the names and qualifications of the 
individuals who approve SME inputs used in the current risk assessment.
    (3) Identify and analyze spatial relationships among anomalous 
information (e.g., corrosion coincident with foreign line crossings or 
evidence of pipeline damage where overhead imaging shows evidence of 
encroachment).
    (4) Analyze the data for interrelationships among pipeline 
integrity threats, including combinations of applicable risk factors 
that increase the likelihood of incidents or increase the potential 
consequences of incidents.
    (c) Risk assessment. An operator must conduct a risk assessment 
that follows ASME/ANSI B31.8S, section 5, and that analyzes the 
identified threats and potential consequences of an incident for each 
covered segment. An operator must ensure the validity of the methods 
used to conduct the risk assessment considering the incident, leak, and 
failure history of the pipeline segments and other historical 
information. Such a validation must ensure the risk assessment methods 
produce a risk characterization that is consistent with the operator's 
and industry experience, including evaluations of the cause of past 
incidents, as determined by root cause analysis or other equivalent 
means, and include sensitivity analysis of the factors used to 
characterize both the likelihood of loss of pipeline integrity and 
consequences of the postulated loss of pipeline integrity. An operator 
must use the risk assessment to determine additional preventive and 
mitigative measures needed for each covered segment in accordance with 
Sec.  192.935 and periodically evaluate the integrity of each covered 
pipeline segment in accordance with Sec.  192.937. Beginning February 
26, 2024, the risk assessment must:
    (1) Analyze how a potential failure could affect high consequence 
areas;
    (2) Analyze the likelihood of failure due to each individual threat 
and each unique combination of threats that interact or simultaneously 
contribute to risk at a common location;
    (3) Account for, and compensate for, uncertainties in the model and 
the data used in the risk assessment; and
    (4) Evaluate the potential risk reduction associated with candidate 
risk reduction activities, such as preventive and mitigative measures, 
and reduced anomaly remediation and assessment intervals.
    (5) In conjunction with Sec.  192.917(b), an operator may request 
an extension of up to 1 year for the requirements of this paragraph by 
submitting a notification to PHMSA at least 90 days before February 26, 
2024, in accordance with Sec.  192.18. The notification must include a 
reasonable and technically justified basis, an up-to-date plan for 
completing all actions required by this paragraph (c)(5), the reason 
for the requested extension, current safety or mitigation status of the 
pipeline segment, the proposed completion date, and any needed 
temporary safety measures to mitigate the impact on safety.
    (d) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must assess the threats to each covered segment 
using the information in sections 4 and 5 of ASME B31.8S and consider 
any threats unique to the integrity of plastic pipe, such as poor joint 
fusion practices, pipe with poor slow crack growth (SCG) resistance, 
brittle pipe, circumferential cracking, hydrocarbon softening of the 
pipe, internal and external loads, longitudinal or lateral loads, 
proximity to elevated heat sources, and point loading.
* * * * *

0
20. In Sec.  192.923, paragraphs (b)(2) and (3) are revised to read as 
follows:

Sec.  192.923   How is direct assessment used and for what threats?

* * * * *

[[Page 52275]]

    (b) * * *
    (2) Section 192.927 and NACE SP0206 (incorporated by reference, see 
Sec.  192.7), if addressing internal corrosion (IC).
    (3) Section 192.929 and NACE SP0204 (incorporated by reference, see 
Sec.  192.7), if addressing stress corrosion cracking (SCC).
* * * * *

0
21. In Sec.  192.927, paragraphs (b) and (c) are revised to read as 
follows:

Sec.  192.927   What are the requirements for using Internal Corrosion 
Direct Assessment (ICDA)?

* * * * *
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in NACE SP0206 
(incorporated by reference, see Sec.  192.7). The Dry Gas Internal 
Corrosion Direct Assessment (DG-ICDA) process described in this section 
applies only for a segment of pipe transporting normally dry natural 
gas (see Sec.  192.3) and not for a segment with electrolytes normally 
present in the gas stream. If an operator uses ICDA to assess a covered 
segment operating with electrolytes present in the gas stream, the 
operator must develop a plan that demonstrates how it will conduct ICDA 
in the segment to address internal corrosion effectively and must 
notify PHMSA in accordance with Sec.  192.18. In the event of a 
conflict between this section and NACE SP0206, the requirements in this 
section control.
    (c) The ICDA plan. An operator must develop and follow an ICDA plan 
that meets NACE SP0206 (incorporated by reference, see Sec.  192.7) and 
that implements all four steps of the DG-ICDA process, including pre-
assessment, indirect inspection, detailed examination at excavation 
locations, and post-assessment evaluation and monitoring. The plan must 
identify the locations of all ICDA regions within covered segments in 
the transmission system. An ICDA region is a continuous length of pipe 
(including weld joints), uninterrupted by any significant change in 
water or flow characteristics, that includes similar physical 
characteristics or operating history. An ICDA region extends from the 
location where liquid may first enter the pipeline and encompasses the 
entire area along the pipeline where internal corrosion may occur until 
a new input introduces the possibility of water entering the pipeline. 
In cases where a single covered segment is partially located in two or 
more ICDA regions, the four-step ICDA process must be completed for 
each ICDA region in which the covered segment is partially located to 
complete the assessment of the covered segment.
    (1) Preassessment. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7) in conducting the 
preassessment step of the ICDA process.
    (2) Indirect inspection. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7), and the following 
additional requirements, in conducting the Indirect Inspection step of 
the ICDA process. An operator must explicitly document the results of 
its feasibility assessment as required by NACE SP0206, section 3.3 
(incorporated by reference, see Sec.  192.7); if any condition that 
precludes the successful application of ICDA applies, then ICDA may not 
be used, and another assessment method must be selected. When 
performing the indirect inspection, the operator must use actual 
pipeline-specific data, exclusively. The use of assumed pipeline or 
operational data is prohibited. When calculating the critical 
inclination angle of liquid holdup and the inclination profile of the 
pipeline, the operator must consider the accuracy, reliability, and 
uncertainty of the data used to make those calculations, including, but 
not limited to, gas flow velocity (including during upset conditions), 
pipeline elevation profile survey data (including specific profile at 
features with inclinations such as road crossings, river crossings, 
drains, valves, drips, etc.), topographical data, and depth of cover. 
An operator must select locations for direct examination and establish 
the extent of pipe exposure needed (i.e., the size of the bell hole), 
to account for these uncertainties and their cumulative effect on the 
precise location of predicted liquid dropout.
    (3) Detailed examination. An operator must comply with NACE SP0206 
(incorporated by reference, see Sec.  192.7) in conducting the detailed 
examination step of the ICDA process. When an operator first uses ICDA 
for a covered segment, an operator must identify a minimum of two 
locations for excavation within each covered segment associated with 
the ICDA region and must perform a detailed examination for internal 
corrosion at each location using ultrasonic thickness measurements, 
radiography, or other generally accepted measurement techniques that 
can examine for internal corrosion or other threats that are being 
assessed. One location must be the low point (e.g., sag, drip, valve, 
manifold, dead-leg) within the covered segment nearest to the beginning 
of the ICDA region. The second location must be further downstream, 
within the covered segment, near the end of the ICDA region. Whenever 
corrosion is found during ICDA at any location, the operator must:
    (i) Evaluate the severity of the defect (remaining strength) and 
remediate the defect in accordance with Sec.  192.933 if the condition 
is in a covered segment, or in accordance with Sec. Sec.  192.485 and 
192.714 if the condition is not in a covered segment;
    (ii) Expand the detailed examination program to determine all 
locations that have internal corrosion within the ICDA region, and 
accurately characterize the nature, extent, and root cause of the 
internal corrosion. In cases where the internal corrosion was 
identified within the ICDA region but outside the covered segment, the 
expanded detailed examination program must also include at least two 
detailed examinations within each covered segment associated with the 
ICDA region, at the location within the covered segment(s) most likely 
to have internal corrosion. One location must be the low point (e.g., 
sags, drips, valves, manifolds, dead-legs, traps) within the covered 
segment nearest to the beginning of the ICDA region. The second 
location must be further downstream, within the covered segment. In 
instances of first use of ICDA for a covered segment, where these 
locations have already been examined in accordance with paragraph 
(c)(3) of this section, two additional detailed examinations must be 
conducted within the covered segment; and
    (iii) Expand the detailed examination program to evaluate the 
potential for internal corrosion in all pipeline segments (both covered 
and non-covered) in the operator's pipeline system with similar 
characteristics to the ICDA region in which the corrosion was found and 
remediate identified instances of internal corrosion in accordance with 
either Sec.  192.933 or Sec. Sec.  192.485 and 192.714, as appropriate.
    (4) Post-assessment evaluation and monitoring. An operator must 
comply with NACE SP0206 (incorporated by reference, see Sec.  192.7) in 
performing the post assessment step of the ICDA process. In addition to 
NACE SP0206, the evaluation and monitoring process must also include--
    (i) An evaluation of the effectiveness of ICDA as an assessment 
method for addressing internal corrosion and determining whether a 
covered segment should be reassessed at more frequent intervals than 
those specified in Sec.  192.939. An operator must carry out this 
evaluation within 1 year of conducting an ICDA;

[[Page 52276]]

    (ii) Validation of the flow modeling calculations by comparison of 
actual locations of discovered internal corrosion with locations 
predicted by the model (if the flow model cannot be validated, then 
ICDA is not feasible for the segment); and
    (iii) Continuous monitoring of each ICDA region that contains a 
covered segment where internal corrosion has been identified by using 
techniques such as coupons or ultrasonic (UT) sensors or electronic 
probes, and by periodically drawing off liquids at low points and 
chemically analyzing the liquids for the presence of corrosion 
products. An operator must base the frequency of the monitoring and 
liquid analysis on results from all integrity assessments that have 
been conducted in accordance with the requirements of this subpart and 
risk factors specific to the ICDA region.
    At a minimum, the monitoring frequency must be two times each 
calendar year, but at intervals not exceeding 7\1/2\ months. If an 
operator finds any evidence of corrosion products in the ICDA region, 
the operator must take prompt action in accordance with one of the two 
following required actions, and remediate the conditions the operator 
finds in accordance with Sec.  192.933 or Sec. Sec.  192.485 and 
192.714, as applicable.
    (A) Conduct excavations of, and detailed examinations at, locations 
downstream from where the electrolytes might have entered the pipe to 
investigate and accurately characterize the nature, extent, and root 
cause of the corrosion, including the monitoring and mitigation 
requirements of Sec.  192.478; or
    (B) Assess the covered segment using another integrity assessment 
method allowed by this subpart.
    (5) Other requirements. The ICDA plan must also include the 
following:
    (i) Criteria an operator will apply in making key decisions 
(including, but not limited to, ICDA feasibility, definition of ICDA 
regions and sub-regions, and conditions requiring excavation) in 
implementing each stage of the ICDA process; and
    (ii) Provisions that the analysis be carried out on the entire 
pipeline in which covered segments are present, except that application 
of the remediation criteria of Sec.  192.933 may be limited to covered 
segments.

0
22. Section 192.929 is revised to read as follows:

Sec.  192.929   What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking?

    (a) Definition. A Stress Corrosion Cracking Direct Assessment 
(SCCDA) is a process to assess a covered pipeline segment for the 
presence of stress corrosion cracking (SCC) by systematically gathering 
and analyzing excavation data from pipe having similar operational 
characteristics and residing in a similar physical environment.
    (b) General requirements. An operator using direct assessment as an 
integrity assessment method for addressing SCC in a covered pipeline 
segment must develop and follow an SCCDA plan that meets NACE SP0204 
(incorporated by reference, see Sec.  192.7) and that implements all 
four steps of the SCCDA process, including pre-assessment, indirect 
inspection, detailed examination at excavation locations, and post-
assessment evaluation and monitoring. As specified in NACE SP0204, 
SCCDA is complementary with other inspection methods for SCC, such as 
in-line inspection or hydrostatic testing with a spike test, and it is 
not necessarily an alternative or replacement for these methods in all 
instances. Additionally, the plan must provide for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data for all covered 
pipeline segments to identify whether the conditions for SCC are 
present and to prioritize the covered pipeline segments for assessment 
in accordance with NACE SP0204, sections 3 and 4, and Table 1 
(incorporated by reference, see Sec.  192.7). This process must also 
include gathering and evaluating data related to SCC at all sites an 
operator excavates while conducting its pipeline operations (both 
within and outside covered segments) where the criteria in NACE SP0204 
(incorporated by reference, see Sec.  192.7) indicate the potential for 
SCC. This data gathering process must be conducted in accordance with 
NACE SP0204, section 5.3 (incorporated by reference, see Sec.  192.7), 
and must include, at a minimum, all data listed in NACE SP0204, Table 2 
(incorporated by reference, see Sec.  192.7). Further, the following 
factors must be analyzed as part of this evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including 
the implications of any factors that promote the production of a 
carbonate-bicarbonate environment, such as soil temperature, moisture, 
the presence or generation of carbon dioxide, or cathodic protection 
(CP);
    (ii) The effects of cyclic loading conditions on the susceptibility 
and propagation of SCC in both high-pH and near-neutral-pH 
environments;
    (iii) The effects of variations in applied CP, such as 
overprotection, CP loss for extended periods, and high negative 
potentials;
    (iv) The effects of coatings that shield CP when disbonded from the 
pipe; and
    (v) Other factors that affect the mechanistic properties associated 
with SCC, including, but not limited to, historical and present-day 
operating pressures, high tensile residual stresses, flowing product 
temperatures, and the presence of sulfides.
    (2) Indirect inspection. In addition to NACE SP0204, the plan's 
procedures for indirect inspection must include provisions for 
conducting at least two above ground surveys using the complementary 
measurement tools most appropriate for the pipeline segment based on an 
evaluation of integrated data.
    (3) Direct examination. In addition to NACE SP0204, the plan's 
procedures for direct examination must provide for an operator 
conducting a minimum of three direct examinations for SCC within the 
covered pipeline segment spaced at the locations determined to be the 
most likely for SCC to occur.
    (4) Remediation and mitigation. If SCC is discovered in a covered 
pipeline segment, an operator must mitigate the threat in accordance 
with one of the following applicable methods:
    (i) Removing the pipe with SCC; remediating the pipe with a Type B 
sleeve; performing hydrostatic testing in accordance with paragraph 
(b)(4)(ii) of this section; or by grinding out the SCC defect and 
repairing the pipe. If an operator uses grinding for repair, the 
operator must also perform the following as a part of the repair 
procedure: nondestructive testing for any remaining cracks or other 
defects; a measurement of the remaining wall thickness; and a 
determination of the remaining strength of the pipe at the repair 
location that is performed in accordance with Sec.  192.712 and that 
meets the design requirements of Sec. Sec.  192.111 and 192.112, as 
applicable. The pipe and material properties an operator uses in 
remaining strength calculations must be documented in traceable, 
verifiable, and complete records. If such records are not available, an 
operator must base the pipe and material properties used in the 
remaining strength calculations on properties determined and documented 
in accordance with Sec.  192.607, if applicable.
    (ii) Performing a spike pressure test in accordance with Sec.  
192.506 based upon the class location of the pipeline segment. The MAOP 
must be no greater than the test pressure specified in

[[Page 52277]]

Sec.  192.506(a) divided by: 1.39 for Class 1 locations and Class 2 
locations that contain Class 1 pipe that has been uprated in accordance 
with Sec.  192.611; and 1.50 for all other Class 2 locations and all 
Class 3 and Class 4 locations. An operator must repair any test 
failures due to SCC by replacing the pipe segment and re-testing the 
segment until the pipe passes the test without failures (such as pipe 
seam or gasket leaks, or a pipe rupture). At a minimum, an operator 
must repair pipe segments that pass the pressure test but have SCC 
present by grinding the segment in accordance with paragraph (b)(4)(i) 
of this section.
    (5) Post assessment. An operator's procedures for post-assessment, 
in addition to the procedures listed in NACE SP0204, sections 6.3, 
``periodic reassessment,'' and 6.4, ``effectiveness of SCCDA,'' must 
include the development of a reassessment plan based on the 
susceptibility of the operator's pipe to SCC as well as the mechanistic 
behavior of identified cracking. An operator's reassessment intervals 
must comply with Sec.  192.939. The plan must include the following 
factors, in addition to any factors the operator determines 
appropriate:
    (i) The evaluation of discovered crack clusters during the direct 
examination step in accordance with NACE SP0204, sections 5.3.5.7, 5.4, 
and 5.5 (incorporated by reference, see Sec.  192.7);
    (ii) Conditions conducive to the creation of a carbonate-
bicarbonate environment;
    (iii) Conditions in the application (or loss) of CP that can create 
or exacerbate SCC;
    (iv) Operating temperature and pressure conditions, including 
operating stress levels on the pipe;
    (v) Cyclic loading conditions;
    (vi) Mechanistic conditions that influence crack initiation and 
growth rates;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and
    (ix) Disbonded coatings that shield CP from the pipe.

0
23. In Sec.  192.933, paragraphs (a) introductory text, (a)(1), (b), 
and (d) are revised and paragraph (e) is added read as follows:

Sec.  192.933   What actions must be taken to address integrity issues?

    (a) General requirements. An operator must take prompt action to 
address all anomalous conditions the operator discovers through the 
integrity assessment. In addressing all conditions, an operator must 
evaluate all anomalous conditions and remediate those that could reduce 
a pipeline's integrity. An operator must be able to demonstrate that 
the remediation of the condition will ensure the condition is unlikely 
to pose a threat to the integrity of the pipeline until the next 
reassessment of the covered segment. Repairs performed in accordance 
with this section must use pipe and material properties that are 
documented in traceable, verifiable, and complete records. If 
documented data required for any analysis is not available, an operator 
must obtain the undocumented data through Sec.  192.607.
    (1) Temporary pressure reduction. (i) If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other action that ensures the safety of the 
covered segment. An operator must reduce the operating pressure to one 
of the following:
    (A) A level not exceeding 80 percent of the operating pressure at 
the time the condition was discovered;
    (B) A level not exceeding the predicted failure pressure times the 
design factor for the class location in which the affected pipeline is 
located; or
    (C) A level not exceeding the predicted failure pressure divided by 
1.1.
    (ii) An operator must determine the predicted failure pressure in 
accordance with Sec.  192.712. An operator must notify PHMSA in 
accordance with Sec.  192.18 if it cannot meet the schedule for 
evaluation and remediation required under paragraph (c) or (d) of this 
section and cannot provide safety through a temporary reduction in 
operating pressure or other action. The operator must document and keep 
records of the calculations and decisions used to determine the reduced 
operating pressure, and the implementation of the actual reduced 
operating pressure, for a period of 5 years after the pipeline has been 
remediated.
* * * * *
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. For the purposes of this section, a condition that presents a 
potential threat includes, but is not limited to, those conditions that 
require remediation or monitoring listed under paragraphs (d)(1) 
through (3) of this section. An operator must promptly, but no later 
than 180 days after conducting an integrity assessment, obtain 
sufficient information about a condition to make that determination, 
unless the operator demonstrates that the 180-day period is 
impracticable. In cases where a determination is not made within the 
180-day period, the operator must notify PHMSA, in accordance with 
Sec.  192.18, and provide an expected date when adequate information 
will become available. Notification to PHMSA does not alleviate an 
operator from the discovery requirements of this paragraph (b).
* * * * *
    (d) Special requirements for scheduling remediation--(1) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must follow ASME/ANSI B31.8S, section 7 (incorporated by reference, see 
Sec.  192.7) in providing for immediate repair conditions. To maintain 
safety, an operator must temporarily reduce operating pressure in 
accordance with paragraph (a) of this section or shut down the pipeline 
until the operator completes the repair of these conditions. An 
operator must treat the following conditions as immediate repair 
conditions:
    (i) A metal loss anomaly where a calculation of the remaining 
strength of the pipe shows a predicted failure pressure determined in 
accordance with Sec.  192.712(b) less than or equal to 1.1 times the 
MAOP at the location of the anomaly.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless engineering analyses performed in accordance with Sec.  
192.712(c) demonstrate critical strain levels are not exceeded.
    (iii) Metal loss greater than 80 percent of nominal wall regardless 
of dimensions.
    (iv) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or with 
a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure determined in accordance with Sec.  192.712(d) is less 
than 1.25 times the MAOP.
    (v) A crack or crack-like anomaly meeting any of the following 
criteria:
    (A) Crack depth plus any metal loss is greater than 50 percent of 
pipe wall thickness;
    (B) Crack depth plus any metal loss is greater than the inspection 
tool's maximum measurable depth; or
    (C) The crack or crack-like anomaly has a predicted failure 
pressure,

[[Page 52278]]

determined in accordance with Sec.  192.712(d), that is less than 1.25 
times the MAOP.
    (vi) An indication or anomaly that, in the judgment of the person 
designated by the operator to evaluate the assessment results, requires 
immediate action.
    (2) One-year conditions. Except for conditions listed in paragraphs 
(d)(1) and (3) of this section, an operator must remediate any of the 
following within 1 year of discovery of the condition:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions (upper \2/3\ of the pipe) with a depth greater than 6 percent 
of the pipeline diameter (greater than 0.50 inches in depth for a 
pipeline diameter less than Nominal Pipe Size (NPS) 12), unless 
engineering analyses performed in accordance with Sec.  192.712(c) 
demonstrate critical strain levels are not exceeded.
    (ii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or at a longitudinal or 
helical (spiral) seam weld, unless engineering analyses performed in 
accordance with Sec.  192.712(c) demonstrate critical strain levels are 
not exceeded.
    (iii) A dent located between the 4 o'clock and 8 o'clock positions 
(lower \1/3\ of the pipe) that has metal loss, cracking, or a stress 
riser, unless engineering analyses performed in accordance with Sec.  
192.712(c) demonstrate critical strain levels are not exceeded.
    (iv) Metal loss anomalies where a calculation of the remaining 
strength of the pipe at the location of the anomaly shows a predicted 
failure pressure, determined in accordance with Sec.  192.712(b), less 
than 1.39 times the MAOP for Class 2 locations, and less than 1.50 
times the MAOP for Class 3 and 4 locations. For metal loss anomalies in 
Class 1 locations with a predicted failure pressure greater than 1.1 
times MAOP, an operator must follow the remediation schedule specified 
in ASME/ANSI B31.8S (incorporated by reference, see Sec.  192.7), 
section 7, Figure 4, in accordance with paragraph (c) of this section.
    (v) Metal loss that is located at a crossing of another pipeline, 
or is in an area with widespread circumferential corrosion, or could 
affect a girth weld, that has a predicted failure pressure, determined 
in accordance with Sec.  192.712(b), of less than 1.39 times the MAOP 
for Class 1 locations or where Class 2 locations contain Class 1 pipe 
that has been uprated in accordance with Sec.  192.611, or less than 
1.50 times the MAOP for all other Class 2 locations and all Class 3 and 
4 locations.
    (vi) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or with 
a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure, determined in accordance with Sec.  192.712(d), is 
less than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (vii) A crack or crack-like anomaly that has a predicted failure 
pressure, determined in accordance with Sec.  192.712(d), that is less 
than 1.39 times the MAOP for Class 1 locations or where Class 2 
locations contain Class 1 pipe that has been uprated in accordance with 
Sec.  192.611, or less than 1.50 times the MAOP for all other Class 2 
locations and all Class 3 and 4 locations.
    (3) Monitored conditions. An operator is not required by this 
section to schedule remediation of the following less severe conditions 
but must record and monitor the conditions during subsequent risk 
assessments and integrity assessments for any change that may require 
remediation. Monitored indications are the least severe and do not 
require an operator to examine and evaluate them until the next 
scheduled integrity assessment interval, but if an anomaly is expected 
to grow to dimensions or have a predicted failure pressure (with a 
safety factor) meeting a 1-year condition prior to the next scheduled 
assessment, then the operator must repair the condition:
    (i) A dent with a depth greater than 6 percent of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter 
less than NPS 12), located between the 4 o'clock position and the 8 
o'clock position (bottom \1/3\ of the pipe), and for which engineering 
analyses of the dent, performed in accordance with Sec.  192.712(c), 
demonstrate critical strain levels are not exceeded.
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6 percent of the 
pipeline diameter (greater than 0.50 inches in depth for a pipeline 
diameter less than NPS 12), and for which engineering analyses of the 
dent, performed in accordance with Sec.  192.712(c), demonstrate 
critical strain levels are not exceeded.
    (iii) A dent with a depth greater than 2 percent of the pipeline 
diameter (0.250 inches in depth for a pipeline diameter less than NPS 
12) that affects pipe curvature at a girth weld or longitudinal or 
helical (spiral) seam weld, and for which engineering analyses, 
performed in accordance with Sec.  192.712(c), of the dent and girth or 
seam weld demonstrate that critical strain levels are not exceeded.
    (iv) A dent that has metal loss, cracking, or a stress riser, and 
where engineering analyses performed in accordance with Sec.  
192.712(c) demonstrate critical strain levels are not exceeded.
    (v) Metal loss preferentially affecting a detected longitudinal 
seam, if that seam was formed by direct current, low-frequency or high-
frequency electric resistance welding, electric flash welding, or with 
a longitudinal joint factor less than 1.0, and where the predicted 
failure pressure, determined in accordance with Sec.  192.712(d), is 
greater than or equal to 1.39 times the MAOP for Class 1 locations or 
where Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or greater than or equal to 1.50 times 
the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (vi) A crack or crack-like anomaly for which the predicted failure 
pressure, determined in accordance with Sec.  192.712(d), is greater 
than or equal to 1.39 times the MAOP for Class 1 locations or where 
Class 2 locations contain Class 1 pipe that has been uprated in 
accordance with Sec.  192.611, or greater than or equal to 1.50 times 
the MAOP for all other Class 2 locations and all Class 3 and 4 
locations.
    (e) In situ direct examination of crack defects. Whenever an 
operator finds conditions that require the pipeline to be repaired, in 
accordance with this section, an operator must perform a direct 
examination of known locations of cracks or crack-like defects using 
technology that has been validated to detect tight cracks (equal to or 
less than 0.008 inches crack opening), such as inverse wave field 
extrapolation (IWEX), phased array ultrasonic testing (PAUT), 
ultrasonic testing (UT), or equivalent technology. ``In situ'' 
examination tools and procedures for crack assessments (length, depth, 
and volumetric) must have performance and evaluation standards, 
including pipe or weld surface cleanliness standards for the 
inspection, confirmed by subject matter experts qualified by knowledge, 
training, and experience in direct examination inspection for accuracy 
of the type of defects and pipe material being evaluated. The 
procedures must account for inaccuracies in evaluations

[[Page 52279]]

and fracture mechanics models for failure pressure determinations.

0
24. In Sec.  192.935, paragraphs (a) and (d)(3) are revised to read as 
follows:

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

    (a) General requirements. (1) An operator must take additional 
measures beyond those already required by this part to prevent a 
pipeline failure and to mitigate the consequences of a pipeline failure 
in a high consequence area. Such additional measures must be based on 
the risk analyses required by Sec.  192.917. Measures that operators 
must consider in the analysis, if necessary, to prevent or mitigate the 
consequences of a pipeline failure include, but are not limited to:
    (i) Correcting the root causes of past incidents to prevent 
recurrence;
    (ii) Establishing and implementing adequate operations and 
maintenance processes that could increase safety;
    (iii) Establishing and deploying adequate resources for the 
successful execution of preventive and mitigative measures;
    (iv) Installing automatic shut-off valves or remote-control valves;
    (v) Installing pressure transmitters on both sides of automatic 
shut-off valves and remote-control valves that communicate with the 
pipeline control center;
    (vi) Installing computerized monitoring and leak detection systems;
    (vii) Replacing pipe segments with pipe of heavier wall thickness 
or higher strength;
    (viii) Conducting additional right-of-way patrols;
    (ix) Conducting hydrostatic tests in areas where pipe material has 
quality issues or lost records;
    (x) Testing to determine material mechanical and chemical 
properties for unknown properties that are needed to assure integrity 
or substantiate MAOP evaluations, including material property tests 
from removed pipe that is representative of the in-service pipeline;
    (xi) Re-coating damaged, poorly performing, or disbonded coatings;
    (xii) Performing additional depth-of-cover surveys at roads, 
streams, and rivers;
    (xiii) Remediating inadequate depth-of-cover;
    (xiv) Providing additional training to personnel on response 
procedures and conducting drills with local emergency responders; and
    (xv) Implementing additional inspection and maintenance programs.
    (2) Operators must document the risk analysis, the preventive and 
mitigative measures considered, and the basis for implementing or not 
implementing any preventive and mitigative measures considered, in 
accordance with Sec.  192.947(d).
* * * * *
    (d) * * *
    (3) Perform instrumented leak surveys using leak detector equipment 
at least twice each calendar year, at intervals not exceeding 7 \1/2\ 
months. For unprotected pipelines or cathodically protected pipe where 
electrical surveys are impractical, instrumented leak surveys must be 
performed at least four times each calendar year, at intervals not 
exceeding 4 \1/2\ months. Electrical surveys are indirect assessments 
that include close interval surveys, alternating current voltage 
gradient surveys, direct current voltage gradient surveys, or their 
equivalent.
* * * * *

0
25. In Sec.  192.941, paragraph (b)(1) and the introductory text of 
paragraph (b)(2) are revised to read as follows:

Sec.  192.941  What is a low stress reassessment?

* * * * *
    (b) * * *
    (1) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe in a covered segment, an 
operator must perform an indirect assessment on the covered segment at 
least once every 7 calendar years. The indirect assessment must be 
conducted using one of the following means: indirect examination 
method, such as a close interval survey; alternating current voltage 
gradient survey; direct current voltage gradient survey; or the 
equivalent of any of these methods. An operator must evaluate the 
cathodic protection and corrosion threat for the covered segment and 
include the results of each indirect assessment as part of the overall 
evaluation. This evaluation must also include, at a minimum, the leak 
repair and inspection records, corrosion monitoring records, exposed 
pipe inspection records, and the pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where external 
corrosion assessments are impractical. If an external corrosion 
assessment is impractical on the covered segment an operator must--
* * * * *

    Issued in Washington, DC, on August 3, 2022, under authority 
delegated in 49 CFR 1.97.
Tristan H. Brown,
Deputy Administrator.
[FR Doc. 2022-17031 Filed 8-23-22; 8:45 am]
BILLING CODE 4910-60-P