PHMSA’s 6 NPRMs

PHMSA has published 6 Notices of Proposed Rulemaking (NPRMs) to the Federal Register covering a variety of topics for consideration by the industry. All comments on these proposed rules must be received back to PHMSA by September 2, 2025. Check out our summary of each NPRM to understand what the implications may be for your pipelines and other assets.

Atmospheric Corrosion Reassessment for Pipeline Replacements

PHMSA is proposing to revise the atmospheric corrosion control requirements in 49 CFR 192.481 for gas distribution systems by replacing the 3-year reassessment interval with a 5-year reassessment interval following pipeline segment or components replacement of in service lines.

49 CFR 192.481(a)(2) generally requires operators to inspect service lines for evidence of atmospheric corrosion on a 5-year interval. If evidence of atmospheric corrosion is found during the most recent inspection operators are required to conduct the next inspection of a service line on a 3-year interval. Also, operators are required to conduct that 3-year reinspection even if the atmospheric corrosion found during the most recent inspection is remediated by replacing the affected portion of the service line.

PHMSA made a preliminary determination that requiring a 3-year reinspection for evidence of atmospheric corrosion is unnecessary and imposes an undue burden if an operator replaces the affected portion of a service line. Atmospheric corrosion presents minimal risk to new service lines, and operators can effectively manage that risk by conducting inspections on the standard 5-year interval. Accordingly, PHMSA is proposing to amend 49 CFR 192.481(d) by providing an exception to the 3-year reinspection interval for replaced service lines.

Codify Enforcement Discretion on Incidental Gathering Lines

PHMSA is proposing to codify a statement of limited enforcement discretion applicable to “incidental gathering” lines.

In November of 2021, PHMSA published a final rule titled “Pipeline Safety: Safety of Gas Gathering Pipelines: Extension of Reporting Requirements, Regulation of Large, High-Pressure Lines, and Other Related Amendments” establishing new reporting and safety requirements for gas gathering pipelines in Class 1 locations. One portion of that final rule  imposed a 10-mile limitation on the historical exception from certain part 192 requirements applicable to gas transmission lines for “incidental gathering” pipeline segments. Operators are required to identify gas gathering pipelines and regulated onshore gathering lines based on the function of that pipeline in accordance with 49 CFR 192.3 and 192.8,and API RP 80. These provisions define the endpoint of an onshore gathering line and the beginning of a transmission or distribution line. API RP 80 also includes an “incidental gathering” designation for piping downstream of the furthermost downstream functional endpoint of gathering that is used to connect to “another pipeline.” The 2021 Gas Gathering Final Rule imposed a new, 10-mile limitation on the use of the incidental gathering line designation in API RP 80. That limitation applies to gathering lines that are “new, replaced, relocated, or otherwise changed” after May 16, 2022, and, if exceeded, requires that the entire length of the pipeline be classified as a gas transmission line.

In 2021 industry groups submitted a petition for reconsideration of the 2021 Gathering Gas Final Rule. In their petition they noted that applying the 10-mile limitation to existing gas gathering lines could require an operator to redesignate the entire length of the line as a gas transmission line in certain scenarios. In April 2022, PHMSA issued a limited exercise of enforcement discretion providing relief from the 10-mile limitation for existing incidental gathering lines in order to provide themselves more time to consider the issue.

PHMSA is now proposing to codify the relief provided in the enforcement discretion under 49 CFR 192.8(a)(5). As a result of this proposed regulatory amendment, the 10-mile restriction on use of the “incidental gathering” designation would no longer apply to portions of an existing pipeline that had been designated as “incidental gathering” on or before May 16, 2022, which are subsequently relocated, replaced, or otherwise changed. Pipelines newly installed after May 16, 2022,would remain subject to the 10-mile limitation on the “incidental gathering” designation in 49 CFR 192.8(a)(5).

Eliminating Burdensome and Duplicative Deadlines for Gas Pipeline Coating Damage Assessments and Remedial Actions

PHMSA is proposing revisions to the regulations related to coating damage assessments and remedial actions for gas transmission pipeline operators by adjusting the timeframe in which operators must perform external anti-corrosion coating assessments and any repairs following an unsatisfactory assessment result.

PHMSA is proposing revisions to the current requirements governing the timelines for operators to perform assessments of external anti-corrosion coating following installation of pipe in a ditch and to complete remedial actions following an unsatisfactory assessment. The existing requirements state that, for certain projects, operators must perform coating damage assessments on the pipeline using DCVG surveys, ACVG surveys, or other technology that provides comparable information about the pipeline's coating “promptly” following the completion of any backfilling of the trench (and no later than 6 months following in-service date of the pipeline). The existing requirements also direct operators to develop remedial action plans, and apply for any necessary permits, within 6 months of completing an assessment that identifies coating deficiencies.

PHMSA preliminarily determined that the approach of linking deadlines to the date of backfill completion is often difficult to implement, as operators cannot always determine when backfilling has officially started or completed.  Similarly, the approach of linking timelines based on the date of application for required permits has also proven challenging in practice. Pipeline projects can involve multiple permits—none of which would be issued by PHMSA—applied for and obtained at different times.

Industry trade associations have noted that implementation challenges arise from the current text for operators who choose to respond to this by erring on the side of caution and performing more coating assessments than may be necessary.

PHMSA proposes to streamline each of the above provisions to address these implementation challenges. With respect to 49 CFR 192.319(d) and 192.461(f), PHMSA proposes to link assessment timelines in each provision to the pipeline segment's in-service date. PHMSA proposes to eliminate references in 49 CFR 192.319(f) and 192.461(h) to permit application dates and instead emphasize the date of the failed coating assessment for calculation of timelines for performing remedial actions.

Exception for In-Plant Piping Systems

This NPRM proposes to codify an exception for in-plant piping systems into the gas pipeline safety regulations. The proposed exception is consistent with prior guidance and a similar provision in the hazardous liquid pipeline safety regulations.

PHMSA's regulations in 49 CFR part 195 for hazardous liquid and CO2 pipelines provide an explicit exception for “in-plant piping systems” at certain facilities. PHMSA's regulations in 49 CFR part 192 for gas pipelines do not explicitly recognize a similar exception, although PHMSA has often applied the same principles in evaluating the regulatory status of in-plant piping systems at gas processing, manufacturing, and industrial facilities.

PHMSA also acknowledged that in-plant piping systems are subject to regulation under other Federal or State programs providing a comparable level of safety requirements. PHMSA further recognized that applying overlapping regulatory programs to in-plant piping systems often results in uncertainty and duplicative or contradictory compliance obligations.

PHMSA is proposing to add an exception to 49 CFR 192.1(b) for in-plant piping systems. PHMSA's proposal includes a definition for in-plant piping systems that aligns with the provisions in part 195, but which establishes a clear point of demarcation between in-plant piping systems and transportation-related pipelines based on prior interpretations. Specifically, PHMSA is proposing to clarify that the point of demarcation for in-plant piping is the inlet of the pressure control device if the pipeline is moving product away from plant grounds, the outlet of the pressure control device if the pipeline is supplying the plant, or, if there is no such device on plant grounds, the plant boundary. By including this clarification, PHMSA intends to minimize the need to reclassify existing facilities among operators that were applying that historical understanding on the boundary between in-plant piping and regulated pipeline facilities.

Harmonize Class Location Change Pressure Test Requirements with Subpart J Pressure Test Requirements

PHMSA is proposing revisions to the regulation for confirming or revising the maximum allowable operating pressure (MAOP) following a class location change. The proposed language clarifies that owners and operators can use certain pressure tests authorized by Subpart J of part 192 for small segments of pipe.

PHMSA proposes amending the requirement in 49 CFR 192.611(a)(1) for confirming or revising the MAOP of gas pipelines where the hoop stress corresponding to the established MAOP of a segment of pipeline is not commensurate with the present class location. Currently, 49 CFR 192.611(a)(1) states that any pipeline segment involved in a class location change that has been previously tested in place for a period of not less than 8 hours must follow certain requirements to confirm or revise the MAOP of that segment. PHMSA adopted the 8-hour pressure test duration requirement in 49 CFR 192.611(a)(1) in the early1970s based on the provisions in a then-current edition of a consensus industry standard, the ASME Standard B31.8 “Gas Transmission and Distribution Piping Systems” (Aug.19, 1970). PHMSA's regulations elsewhere in 49 CFR 192.505 authorize the use of a 4-hour pressure test for short or prefabricated pipeline segments if an8-hour, post-installation test is impractical. These short or prefabricated pipeline segments generally present a lower risk to public safety, which justifies the shorter pressure testing interval.

The current language governing the 8-hour pressure testing requirement in 49 CFR 192.611(a)(1) prevents operators from using an otherwise valid 4-hour test to confirm or revise the MAOP of a segment following a change in class location. PHMSA does not believe this is consistent with the intent of the pressure testing requirement in 49 CFR 192.611(a)(1). PHMSA preliminarily concluded that the regulatory amendment proposed in this NPRM will reduce burdens on operators without adversely affecting safety.

Rationalize Special Permit Conditions

PHMSA is proposing to clarify that the conditions in a special permit must relate directly and substantially to the requirement in the Federal Pipeline Safety Regulations that an applicant is seeking to waive.

Congress has authorized PHMSA to issue an order to the owner or operator of a pipeline facility waiving compliance with any standard prescribed in the Federal Pipeline Safety Regulations “on terms PHMSA considers appropriate if PHMSA determines that the waiver is not inconsistent with pipeline safety.” Congress has also authorized state authorities with a certification or agreement with PHMSA to issue orders to owners or operators of intrastate pipeline facilities “waiv[ing] compliance with a safety standard to which the certification or agreement applies in the same way and to the same extent” as PHMSA.

PHMSA refers to these congressionally authorized waivers as “special permits” and has codified procedures for the issuance of the same in 49 CFR 190.341. The procedures generally state that if a special permit is granted, “[c]onditions may be imposed…if [PHMSA] concludes they are necessary to assure safety, environmental protection, or are otherwise in the public interest,” 49 CFR 190.341(d)(2).

The current language in the special permit procedures provides discretion to PHMSA in determining the conditions that should be included in granting a waiver. PHMSA has in the past imposed conditions that are not directly, related to the requirement in the Federal Pipeline Safety Regulations that the applicant asked to be waived. As a result, operators of pipeline facilities may be unable to predict what types of conditions will be accepted by or imposed by PHMSA in granting a special permit. These uncertain outcomes may discourage owners and operators from applying for special permits or from proposing conditions to address directly potential risks in their applications.

External stakeholders have called on PHMSA to improve alignment between the regulatory provisions being waived and special permit conditions. To address these concerns, PHMSA is proposing amending 49 CFR 190.341 to impose a limitation on the types of conditions that can be included in special permits. The proposal would require that such conditions be directly and substantially related to the provision in the Federal Pipeline Safety Regulations being waived.

Contact Elemental Compliance for additional information, questions on the NPRMs, and to keep your pipeline safety programs up to speed with the rapidly changing regulatory landscape. Also consider signing up for our Regulatory Compliance Newsletter where we provide real time updates on PHMSA and state pipeline safety activities straight to your email. Sign up at https://www.elementalcompliance.com/about.