The Pipeline and Hazardous Materials Safety Administration (“PHMSA” or the “Agency”) published a Notice of Proposed Rulemaking (“NPRM” or the “Proposed Rule”) that provides increased flexibility to gas transmission pipelines that experience a certain change in population surrounding the pipeline (from a Class 1 to Class 3 location). These changes have been the subject of numerous Special Permit approvals for some time, and the industry has long requested that PHMSA codify this process to avoid unnecessary pipe replacements of short segments. If finalized, the Proposed Rule would provide operators an alternative option to implement integrity management (“IM”) requirements to ensure that a pipe segment is subject to appropriate class location safety factors and thereby avoid unnecessary and costly pipe replacements or pressure reductions. Comments are due by December 14, 2020.


Under current regulations, a pipeline operator that experiences a change in class location is required under 49 C.F.R. § 192.611 to confirm design factors and recalculate the maximum allowable operating pressure (“MAOP”) of the pipeline segment. In certain instances, a pipeline operator of a pipeline segment that experiences a class location may be required to (1) lower the pipeline’s MAOP to reduce stress levels in the pipe, (2) replace the existing pipe with pipe that has thicker walls or higher yield strength to yield a lower operating stress at the same MAOP, or (3) pressure test the pipeline at a higher test pressure. If these requirements are impractical, an operator’s only option is to seek a Special Permit. While the Agency has traditionally granted class location special permits and exempted pipeline segments where operators can demonstrate that implementing certain IM measures will ensure that the pipeline is protective of public safety, the process is time consuming.

For some time, industry members have requested that the Agency codify regulations based on previously issued class location Special Permits to provide an alternative to existing class location change requirements. Advancements in technology have eliminated the necessity for the costly pipe replacement that is often required under the existing regulations. That said, the relief anticipated under the Proposed Rule would be limited to pipeline segments that experience a change from a Class 1 to a Class 3 segment after the Proposed Rule is finalized. Pipeline segments that have already experienced a class location change will be unable to utilize the IM alternative described more fully below. While not expressly discussed in the NPRM, it appears that segments subject to existing class location Special Permits would not be eligible under the Proposed Rule as it would apply to class location changes that occur after the effective date of the Proposed Rule.

Applicability Criteria

The Proposed Rule would only apply to pipeline segments (1) that meet specific criteria under a new regulation to be codified at 49 C.F.R. § 192.618, and (2) where class location changes from Class 1 to Class 3. Further, a pipeline segment can only be eligible for the IM alternative under the Proposed Rule if the pipeline segment has a documented successful eight-hour, Part 192, Subpart J, pressure test to a minimum of 1.25 times MAOP. If a pipeline segment cannot satisfy these criteria, the owner or operator of the segment must comply with existing class location change regulations.

As a means of defining eligible pipeline segments, the NPRM sets forth a lengthy list of attributes that would exclude pipeline segments from the IM alternative, as follows:

  • Bare pipe;
  • Pipe with wrinkle bends;
  • Pipe that does not have traceable, verifiable, and complete pipe material property records for diameter, wall thickness, grade, seam type, yield strength, and tensile strength;
  • Pipe that is uprated under Subpart K (unless it has been pressure tested within 24 months of the class location change and prior to uprating or increasing MAOP);
  • Pipe that has not been pressure tested per Subpart J (unless it has been pressure tested within 24 months of the class location change);
  • Pipe that has certain seam types (DC, LF-ERW, EFW, or lap-welded seams, or pipe with a joint factor below 1.0);
  • Evidence of body, seam, or girth-weld cracking in or within five miles of pipe segment at issue (depending on the circumstances);
  • Pipe with “poor” external coating (requiring a minimum negative cathodic protection shift of 100 mv or linear anodes) or with tape wraps or shrink sleeves;
  • A leak or failure within five miles of the pipeline segment;
  • Pipe transporting gas that is not of suitable completion and quality for sale to gas distribution customers (including certain H2S or CO2 pipelines);
  • Certain pipe operated in accordance with § 192.619(c) (the grandfather clause) or (d) (alternative MAOP); and
  • A pipeline segment, ILI segment, or portion of it that has been previously denied by the Special Permit process.

Under certain circumstances, it is unclear where exactly PHMSA expects to draw the line with respect to the above exclusionary attributes, whether they are all appropriate limitations on this allowance, or whether PHMSA has consistently applied them under the Special Permit precedent that informs this rulemaking. As such, it is likely that certain of these attributes will be the subject of industry comment.

Additionally, PHMSA clarifies that it is “not proposing any revisions to the clustering methodology” under 49 C.F.R. § 192.5(c), which was not clear based on the Agency’s advanced notice of proposed rulemaking.


If a pipeline segment is eligible, the Proposed Rule would allow an operator of a segment to forgo the existing regulations and implement the IM requirements in Part 192, Subpart O and additional requirements to provide a “consistent-or-higher level of safety for the life of the pipeline.”

In order to maintain MAOP with a Class 1 location safety factor under the Proposed Rule, these additional requirements for applicable segments include requiring in-line inspections (ILI), external pipeline coating surveys, cathodic protection surveys, certain pipeline repair criteria, and remote-controlled or automatic shutoff valves. The Proposed Rule would also require implementation of certain preventive and mitigative measures. These measures include performing additional coating, interference, and corrosion surveys; remediating defined anomalies; installing line-of-sight markers; performing depth of cover surveys and remediation; clearing shorted casings; performing additional right-of-way patrols and leakage surveys; and using a supervisory control and data acquisition (SCADA) system. These requirements would apply to the entire pipeline segment. An operator that elects to utilize the IM alternative would be required to notify the Agency 60 days prior to implementing the IM measures.

Similar to the exclusionary attributes listed by PHMSA in the Proposed Rule, PHMSA’s anticipated application of the additional IM requirements in practice and under certain circumstances is not clear under the NPRM. Operators should consider commenting and requesting clarifications and revisions to requirements that may not be justified under the circumstances or which are not supported by prior Special Permit precedent. According to the NPRM, PHMSA is particularly interested in comments that address whether there are additional, feasible measures that should be implemented to ensure that pipeline segments are protective of public safety.