PHMSA’s Mega Rule Is Complete: Here’s What You Should Know
The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) recently released the final rule in a rulemaking trilogy collectively known as the “Mega Rule” — a set of regulations designed to improve pipeline safety by reducing the frequency of pipeline failures. Collectively, these rulemakings address lessons learned following the highly publicized Pacific Gas and Electric Company rupture and release in San Bruno, California, in September 2010. This final rule, Pipeline Safety: Safety of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments, applies to onshore gas transmission pipelines and clarifies integrity management regulations, expands corrosion control requirements, mandates inspection after extreme weather events, and updates existing repair criteria for both HCA and non-HCA pipelines.
The following summarizes the final rule’s major requirements and highlights some substantive changes between the rule’s proposed and final versions.
Mega Rule Parts I & II
In response to several pipeline incidents, as well as Congressional directives, in August 2011, PHMSA published an Advanced Notice of Proposed Rulemaking (“ANPRM”) to revise the pipeline safety regulations for gas gathering and gas transmission pipelines. Based on comments received in response to the ANPRM, PHMSA published a Notice of Proposed Rulemaking (“NPRM”) in April 2016. PHMSA then determined, given the number of comments received and the breadth of the proposed changes, to split the “Mega Rule” into three separate rules, the first of which was finalized in October 2019. This rule primarily concerned maximum operating pressure and integrity management near High Consequence Areas (“HCAs”) for onshore gas transmission pipelines. PHMSA promulgated the second rule in November 2021, extending federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures.1
Mega Rule Part III
PHMSA released its third and final rule to the public on August 4, 2022, but formally published it later, on August 24, 2022. This regulation is largely the product of negotiations with a diverse group of stakeholders including industry, citizens groups, and industry trade groups. While the rule will generally be met with broad acceptance in many quarters, certain aspects either required PHMSA to choose between competing views or to reach judgments that leave all stakeholders somewhat unhappy. The bulk of the rule’s substantive requirements takes effect on May 24, 2023.2
Management of Change
PHMSA expanded the requirements to have a Management of Change (“MOC”) process beyond operators subject to the Subpart I Integrity Management Requirements and applied those obligations more broadly. The regulations updated Section 192.13 to add ASME/ANSI B31.8S, limited the requirement to “significant changes that pose a risk to safety or the environment,” specified that the MOC requirements are only applicable to “[e]ach operator of a gas transmission pipeline” (not gathering or distribution pipelines), and confirmed that they do not apply retroactively. Additionally, the final rule provides operators of non-HCA pipeline segments with eighteen (18) months to fully incorporate the MOC process, and the possibility of a further one-year extension if a written request is submitted “at least 90 days before” the effective date of February 26, 2024.
The final rule expands corrosion control requirements for gas transmission pipelines but explicitly exempts gathering and distribution pipelines from these new requirements for now. The corrosion control requirements, among others, include:
- Installation of Pipe in the Ditch and Coating Surveys: The final rule requires operators to perform indirect above-ground assessments (Alternating Current Voltage Gradient (“ACVG”) or Direct Current Voltage Gradient (“DCVG”) surveys) to identify locations of suspected damage promptly after backfilling segments greater than 1,000 feet in length, followed by remediation of any moderate or severe coating damage. An operator may use other technologies and methods (besides ACVG or DCVG) in this effort after notification to PHMSA unless objected to, and any remediation identified must be completed within six (6) months of the assessment.
- Interference Surveys: The final rule requires operators to perform interference surveys “when electrical potential monitoring indicates a significant increase in stray current or new potential stray current sources are introduced,” and remediate any issues found within fifteen (15) months, or longer should the operator encounter delays in permitting.
- External Corrosion: PHMSA has set a one-year timeline for repairing any deficiencies identified in the monitoring of cathodic protection and now also requires annual test station readings to determine whether cathodic protection meets the standards of Subpart I. The new regulations mandate certain follow-up depending on whether the results indicate systemic or non-systemic problems.
- Internal Corrosion: Operators must now monitor for harmful gas stream constituents at points where gas with potentially corrosive contaminants enters the pipeline once per calendar year, not to exceed fifteen (15) months. Operators must also review their internal corrosion monitoring and mitigation program annually, but not longer than fifteen (15)-month intervals, and adjust as necessary in light of information learned about any corrosive contaminants entering the system.
Inspections Following Extreme Weather Events
PHMSA adopted regulations for gas pipelines that mirror the requirements already applicable to hazardous liquids pipelines. This new provision requires operators, following an “extreme weather event” (e.g., hurricanes, landslides, earthquakes, flooding exceeding the high-water mark), to inspect all potentially affected pipeline facilities to ensure that no conditions exist that could adversely affect the safe operation of the pipeline. Upon detection of a condition that could adversely affect the safe operation of the pipeline, an operator must take prompt remedial action.
An operator must commence this inspection within seventy-two (72) hours after the point in time when the operator “reasonably determines that the affected area can be safely accessed by personnel and equipment, and the necessary personnel and equipment required to perform such an inspection are available.” In other words, the seventy-two (72)-hour clock starts ticking when the operator reasonably determines that (1) the affected area can be safely accessed by personnel and equipment, and (2) the necessary personnel and equipment are in fact available. In the preamble to the final rule, PHMSA encourages operators to consult with pipeline and public safety officials when making this determination. If an operator is unable to commence an inspection due to the unavailability of personnel or equipment, the operator is required to notify the appropriate PHMSA Region Director as soon as practicable.
Repair Criteria for HCAs and non-HCAs
These regulations adopt repair criteria for non-HCAs that use a similar structure to those applicable to HCAs. In the final rule, PHMSA drew a hard line in rejecting public comments arguing that applying the same repair criteria for non-HCA segments as to HCA segments would conflict with the customary practice of prioritizing repairing conditions discovered on HCA segments. PHMSA insists that operators need to immediately address any indication that a pipe is at the point of failure, regardless of whether the segment affects an HCA or not.
For non-HCAs, the rule sets the following repair categories: immediate, two-year, and monitored. The criteria for assessing non-HCAs are similar to and based upon repair criteria for HCA pipelines, notably, structure, anomaly types, and repair timeframes. Like operators of segments subject to Subpart O, operators must implement a pressure reduction per criteria specified in the regulations. The conditions that qualify as immediate repair conditions under the new Section 192.714 are the same as those for HCAs. On the other hand, anomalies that require a one-year response on HCA pipeline segments are subject to a two-year response time for non-HCA segments.
For both HCAs and non-HCAs, PHMSA added to the list of immediate repair conditions to address metal loss, cracks, and dents. As proposed, PHMSA was going to add and define the terms “significant seam cracking” and “significant stress corrosion cracking” (“SCC”). Further, PHMSA proposed to add immediate repair conditions for “any indication of” significant seam cracking or significant SCC. In the final rule, however, PHMSA has chosen not to adopt those new terms. Instead, PHMSA removes these proposed repair criteria and combines them into a “more general cracking criteria,” somewhat ameliorating industry’s concern that “any indication of” significant SCC would trigger the need for immediate repairs. Additional rules for assessing SCC are addressed elsewhere in Section 192.929.
PHMSA’s third and final gas pipeline safety rule concludes a decade-long effort to heighten the safety requirements applicable to natural gas transmission pipelines. Many of the requirements codify changes that were already in place through ASME/ANSI B31.8S, but other changes that appear smaller in nature may have significant impacts on the industry. The implementation date for many requirements is eighteen (18) months from the effective date, or May 24, 2023, so the time for reviewing how these changes may affect operators’ programs is now. The industry should expect the agency to vigorously enforce these requirements, given that PHMSA has stated that it believes the final rule’s requirements are necessary to protect public safety, reduce threats to the environment, and promote environmental justice for those communities located near interstate gas transmission pipelines.
1 V&E has previously discussed the second rule’s new requirements. See Mega Rule Part III: PHMSA Expands Its Regulations and Imposes New Requirements for Onshore Gas Gathering Lines, V&E Energy Update (Nov. 22, 2021).
2 Note that, under the final rule, the management of change process evaluations must be implemented by February 26, 2024.
This information is provided by Vinson & Elkins LLP for educational and informational purposes only and is not intended, nor should it be construed, as legal advice.