In This Issue

PHMSA Final Rule: Safety of Gas Transmission Pipelines (RIN2)

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

Note that the following is intended to provide a synopsis of the rule making and should not be used as the sole source of compliance planning or associated activities.


On August 4th, PHMSA sent to the Federal Register for publication a final rule revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This rule update (the Rule), commonly referred to as “RIN 2, Gas Mega Rule,” is related to the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments rule making issued October 1, 2019, that was driven by the September 9, 2010, Pacific Gas and Electric Company incident that occurred in San Bruno, California. Amendments include clarification of certain integrity management requirements, the codification of the management of change process, the update of gas transmission pipeline corrosion control requirements, the inspection of pipelines after extreme weather events, adjust high consequence area repair requirements, and adds new requirements for non-high consequence area segments. These regulatory updates were negotiated with various stakeholders including the pipeline industry, the public, and advocacy groups through a series of public Gas Pipeline Advisory Committee (GPAC) Meetings. The following provides an overview of key provisions of the rule making.

With the update, operators are required to development and implement a management of change process that is consistent with ASME/ANSI B31.8S, Section 11 (incorporated by reference, § 192.7). As management of change is already required for segments subject to the integrity management requirements in Subpart O, Gas Transmission Pipeline Integrity Management, operators having pipelines subject to integrity management are expected to have a management of change process meeting these requirements for their covered segments. Compliance with this provision is required for other pipelines no later than February 2024. Operators may request an extension for up to 1 year by submitting a notification to PHMSA at least 90 days prior to the compliance date (February 2024). As with any extension request, operators must submit a reasonable and technically justified basis for the request.

As expected, and discussed in GPAC meetings, PHMSA has established that operators conducting projects that involve 1,000 feet or more of continuous backfill will conduct an assessment to determine if any coating damage exists and to ensure integrity of the coating using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or other technology that provides comparable insights.

Mirroring the hazardous liquids rule making issued on October 1, 2019 ([Docket No. PHMSA–2010–0229; Amdt. No. 195–102] RIN 2137–AE66), PHMSA has updated Part 192 to include a new paragraph (c) to 192.613 that establishes requirements for inspection of pipeline assets following an extreme weather event or natural disaster that could result in damage to pipelines. Extreme weather events include named tropical storms, hurricanes, floods, landslides, or earthquakes.

PHMSA updated requirements for predicted failure pressure to include critical strain level, and a new paragraph establishes robust requirements for operators to develop procedures to evaluate and repair dents and other mechanical damage.

One of the more anticipated provisions of the new rule is the establishment of new repair criteria for pipelines not subject to Gas Transmission Pipeline Integrity Management (Subpart O). Criteria for the following condition types are established:

  • Immediate repairs
  • Two-year conditions
  • Monitored conditions

Similar to pipeline segments subject to integrity management (Subpart O,) operators will be required to evaluate and properly categorize anomalies found as a result of integrity assessments.

Integrity management updates provide additional prescription for the risk-based regulation. It is noteworthy that a number of these code additions are not entirely new, as most of the additions were already provided in ASME/ANSI B31.8S (incorporated by reference).

Data integration requirements have been updated to add specificity pertaining to data required for risk assessment; a similar approach was taken for hazardous liquids integrity requirements in October 2019. Updates also underscore PHMSA’s expectation that they do not merely integrate data in a geospatial system. Rather, operators must effectively analyze relationships through vigorous and validated risk assessments.

Gas transmission pipeline operator’s risk assessments must now specifically consider the consequences of a pipeline failure in its risk modeling. Merely stating that the area is a covered segment will not be sufficient, as PHMSA will expect operators to consider specific impacts and consequences for each high consequence area.

Threat analysis specifically requires that operators analyze the likelihood of failure due to each individual threat and each combination of threats that interact or simultaneously contribute to risk at a common location. The common practices of applying global threat interactions will now be insufficient, as operators must address threat interaction at each location along the pipeline segment.

To address unknown data and assumptions used in risk modeling that the potential for those data sets to skew risk results, operators must also account for and compensate for uncertainties or “null values” and/or assumptions employed their risk models.

Consistent with the hazardous liquids rule update that was published in October 2019, this Section was updated to includes a provision requiring that operators notify PHMSA if discovery cannot be made within the required 180-day period.  Most noteworthy PHMSA updates to this Section include the addition of repair criteria for:

  • Immediate conditions
  • One-year conditions
  • Monitored conditions

With the objective of driving more robust processes and effective preventive and mitigative measures, PHMSA updated to require that operators must consider results from their risk assessments and specific potential activities for risk reduction.


While much of the regulatory language presented in RIN 2, Gas Mega Rule, is consistent with expected updates and modifications, numerous small, but impactful, additions have been made. Also noteworthy, but not presented in this summary are the updates to internal corrosion direct assessment and direct assessment for stress corrosion cracking. With compliance expected in February 2024, operators should immediately consider each code change and carefully craft updates to their Operations and Maintenance procedures and Integrity Management Programs.

For a copy of PHMSA’s Final Rule: Safety of Gas Transmission Pipelines (RIN2), contact Jessica Foley. Or, to request a copy of the full version of this Final Rule Summary compiled by RCP’s SME, click here.