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

Federal RegisterAug 24, 2022

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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.

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—§§ 192.917(a)-(d), 192.935(a)

i. Threat Identification, Data Collection, and Integration—§ 192.917(a) & (b)

ii. Risk Assessment Functional Requirements—§ 192.917(c)

iii. Threat Assessment for Plastic Pipe—§ 192.917(d)

iv. Preventive and Mitigative Measures—§ 192.935(a)

B. Management of Change—§§ 192.13 & 192.911

C. Corrosion Control—§§ 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—§§ 192.319 & 192.461

iii. Interference Surveys—§ 192.473

iv. Internal Corrosion—§ 192.478

v. Cathodic Protection—§ 192.465 & Appendix D

vi. P&M Measures—§ 192.935(f) & (g)

D. Inspections Following Extreme Weather Events—§ 192.613

E. Strengthening Requirements for Assessment Methods—§§ 192.923, 192.927, 192.929

i. Internal Corrosion Direct Assessment—§§ 192.923, 192.927

ii. Stress Corrosion Cracking Direct Assessment—§§ 192.923(c), 192.929

F. Repair Criteria—§§ 192.714, 192.933

i. Repair Criteria in HCAs—§ 192.933

ii. Repair Criteria in non-HCAs—§ 192.714

iii. Cracking Criteria—§§ 192.714 & 192.933

iv. Dent Criteria—§§ 192.714 & 192.933

v. Corrosion Metal Loss Criteria—§§ 192.714 & 192.933

vi. General Discussion

G. Definitions—§ 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.

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.

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).

NTSB Incident Report on San Bruno at 107-115.

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.

PHMSA published the ANPRM on August 25, 2011.

“Safety of Gas Transmission Pipelines,” 76 FR 53086 (Aug. 25, 2011).

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.

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).

“Safety of Gas Transmission and Gathering Pipelines,” 81 FR 20722 (Apr. 8, 2016).

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).

Provisions related to gas gathering pipelines were addressed in a separate rulemaking.

This rulemaking finalizes the remaining provisions from the NPRM as outlined below.

“Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments,” 84 FR 52180 (Oct. 1, 2019).

“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).

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

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.

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.

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).

ASME/ANSI “B31.8S-2004: Supplement to B31.8 on Managing System Integrity of Gas Pipelines” (Jan. 14, 2005).

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,

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

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.

https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=58.

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.

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.

As PHMSA has noted in another series of Advisory Bulletins, hurricanes are also capable of causing extensive damage to both offshore and inland pipelines.

“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).

“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).

Because of the frequency and severe consequences of these events,

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.

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).

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).

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 §§ 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.

By incorporating by reference the standards subsequently published by NACE International,

PHMSA is ensuring greater consistency, accuracy, and quality when operators perform these assessments.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines): Final Rule,” 68 FR 69778 (Dec. 15, 2003).

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.

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.

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

regulations applicable to gas transmission pipelines. The GPAC convened one time in 2019 to discuss the provisions related specifically to gas gathering pipelines.

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.

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/.

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—§§ 192.917(a)-(d), 192.935(a)

i. Threat Identification, Data Collection, and Integration—§ 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 § 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 § 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.

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.

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 § 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 § 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

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 § 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 § 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 § 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 § 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 § 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 § 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 § 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

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 § 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.

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 § 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—§§ 192.917(a)-(d), 192.935(a)

ii. Risk Assessment Functional Requirements—§ 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 § 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 § 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 § 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 § 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 § 192.917(c) to require operators to “validate” data. These commenters expressed doubts regarding the technical feasibility of implementing the proposed regulations in § 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 § 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.

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.

There was broad support from the committee for the revisions to § 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 § 192.917(c), which seemed to imply PHMSA intended for operators to be using probabilistic risk assessment techniques.

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 § 192.917 (c)(2); and provide a 3-year phase-in period for risk assessments to meet the functional objectives specified in § 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.

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.

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 § 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 § 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 § 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 § 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 § 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—§§ 192.917(a)-(d), 192.935(a)

iii. Threat Assessment for Plastic Pipe—§ 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

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 § 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 § 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 § 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—§§ 192.917(a)-(d), 192.935(a)

iv. Preventive and Mitigative Measures—§ 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 § 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 § 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 § 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—§§ 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 §§ 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.

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 § 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 § 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 § 192.13(d) is not retroactive and applies only to onshore transmission pipelines (

i.e.,

not gathering or distribution pipelines).

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 § 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 § 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—§§ 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 §§ 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 § 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.

The Pipeline Safety Coalition, the Public Service Commission of West Virginia, and the Pennsylvania Public Utility

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

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 § 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 § 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—§§ 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—§§ 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

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 dBμV for ACVG.

“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

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.

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.

This is similar to a proposal in § 192.319 for new construction.

In the NPRM, PHMSA proposed to revise § 192.461(a) to require that pipelines have sufficient coating to protect against damage from being handled. PHMSA also proposed to add § 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 §§ 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 § 192.461(f) should be eliminated.

Industry commenters also stated objections or suggested limitations to the timeframe proposed in § 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

pipeline in existing § 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 § 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 § 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.

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 § 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.

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 §§ 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 §§ 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.

These might include crossings of major interstates or rivers. An operator must document, in accordance with a technically proven

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

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—§§ 192.319, 192.461, 192.465, 192.473, 192.478, and 192.935 and Appendix D

iii. Interference Surveys—§ 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 § 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 § 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 § 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 § 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—§§ 192.319, 192.461, 192.465, 192.473, 192.478, and 192.935 and Appendix D

iv. Internal Corrosion—§ 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

liquids. In the NPRM, PHMSA proposed to add a new § 192.478 to require onshore gas transmission pipeline operators monitor for deleterious gas stream constituents and evaluate gas monitoring data quarterly. The proposed § 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 § 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 § 192.478 should be eliminated for this reason. Atmos Energy Corporation and INGAA asserted that the internal corrosion monitoring timeline proposed in § 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 § 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 § 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.

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.

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—§§ 192.319, 192.461, 192.465, 192.473, 192.478, and 192.935 and Appendix D

v. Cathodic Protection—§ 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 § 192.465(f), specifies requirements for CP of steel, cast iron, and ductile pipelines. Appendix D has not been updated since 1971. The NPRM

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 § 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 § 192.465(d) to require that operators must complete remedial action promptly, but no later than the next monitoring interval specified in § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 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

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

C. Corrosion Control—§§ 192.319, 192.461, 192.465, 192.473, 192.478, and 192.935 and Appendix D

vi. P&M Measures—§ 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 § 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 § 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 § 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, § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 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 § 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

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 § 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 § 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 § 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 § 192.935(f) and (g) and appendix E.

D. Inspections Following Extreme Weather Events—§ 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 § 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 § 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 § 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 § 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 § 192.615 and suggested that to avoid duplicative regulation, PHMSA should instead modify § 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 § 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 § 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.

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 § 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 § 192.3, and the use of that term will likely provide additional clarity.

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

i. Internal Corrosion Direct Assessment (ICDA)—§§ 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 §§ 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 § 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 §§ 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

§ 192.927(c)(4)(ii).

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.

PHMSA regulations at § 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 §§ 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 § 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 § 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 § 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 § 192.903 as “a segment of gas transmission pipeline located in a high consequence area.” The terms “gas” and “transmission line” are defined in § 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 § 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—§§ 192.923(b) & (c), 192.927, 192.929

ii. Stress Corrosion Cracking Direct Assessment (SCCDA)—§§ 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 §§ 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

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 § 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 § 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 § 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 § 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 § 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 § 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 § 192.506,

Transmission lines: Spike hydrostatic pressure test,

in § 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 § 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—§§ 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

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

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

F. Repair Criteria—§§ 192.714, 192.933

i. Repair Criteria in HCAs—§ 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 § 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 § 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 §§ 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 §§ 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 §§ 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 §§ 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 §§ 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 § 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—§§ 192.714, 192.933

ii. Repair Criteria in Non-HCAs—§ 192.714

1. Summary of PHMSA's Proposal

In the NPRM, PHMSA proposed at § 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 § 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 p

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