PHMSA proposes significant changes for pipelines

Publication March 2016

On March 17, 2016, the U.S. Department of Transportation, Pipeline and Hazardous Materials Administration (PHMSA) released, ahead of publication in the Federal Register,  an ambitious and long-awaited, 549-page Notice of Proposed Rulemaking (NPRM) applicable to  onshore gas transmission and gathering pipelines.  Among other things, in the NPRM, PHMSA responds to Congressional, Government Accountability Office (GAO) and National Transportation Safety Board recommendations resulting from recent pipeline accidents and fatalities and addresses issues associated with the rapid development of domestic shale gas plays, including increases in the diameter and pressure of gathering lines used for shale gas. 

Through the NPRM, PHMSA proposes several significant changes to the regulatory scheme for gathering lines, including bringing into its regulatory fold, oversight of gathering lines that have traditionally escaped federal regulation.  In this regard, PHMSA notes that, because of burgeoning domestic shale plays and the associated demand for gathering of gas,  gathering lines, ranging in size from 4 to 36 inches in diameter with Maximum Allowable Operating Pressures (MAOP) up to 1,480 psig, are now being used. The largest of these lines have diameters that traditionally are more typical for gas transmission lines and similarly are being operated at much higher pressures than previously seen in gathering lines. Based upon 2011 annual reports submitted to PHMSA, there are approximately 20,281 total miles of PHMSA-regulated Type A, Type B and offshore gathering lines. By contrast,  there are approximately 238,500 miles of unregulated Type A and Type B gathering lines in Class 1 locations.

Expanding the scope of regulated gathering lines

In order to bring a greater proportion of gathering lines under, and clarify the scope of, federal oversight, PHMSA proposes to make the following changes to its current regulatory scheme for gas gathering lines:

  • Apply the Type B gathering line requirements to Type A gathering lines in Class 1 locations when the nominal diameter is 8-inches or greater. PHMSA would create two subdivisions of Type A gathering lines. Type A, Area 1 gathering lines would define those that are already regulated and Type A, Area 2 gathering lines would apply to the new set of gathering lines PHMSA proposes to regulate. Type A, Area 2 gathering lines would need to comply with requirements for corrosion protection, damage prevention, and emergency planning, among other things;
  • Repeal the use of American Petroleum Institute's Recommended Practice 80, which is currently incorporated by reference in 49 C.F.R. Part 192, for determining regulated onshore gathering lines because of the potential for misapplication of this complex standard during an operator's determination of incidental gathering lines;
  • Change the definition of "gathering lines" and "onshore production facility/operation." The new gathering line definition would classify a line as a gathering line earlier in the production process (as compared to API RP 80) and reduce the scenarios within which a line would be considered incidental gathering, rather, than transmission; and,
  • Require all operators of onshore gas gathering lines, unregulated as well as regulated, to file annual, incident, and safety-related conditions reports.

The new definition of "gathering line" would significantly extend PHMSA's  jurisdictional reach. While PHMSA does not propose rulemaking to apply Integrity Management (IM) or internal corrosion requirements to gathering lines at this time, the NPRM leaves that door open in noting that final determinations will be made in the future.

MAOP verification

The NPRM also unveils the agency's integrity verification process (IVP) in accordance with Congressional mandates found in Section 23 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act). This IVP appears primarily to target pipelines in Class 3, Class 4, and High Consequence Areas (HCA) to reconfirm the MAOP for pipelines that established  their MAOPs based upon 49 C.F.R § 619(c).  Based upon this grandfather provision, those pipelines had their MAOP established to the highest actual operating pressure to which they were subjected during the 5 years prior to July 1, 1970 (the initial publication date for the Pipeline Safety Regulations). Unlike many of their modern counterparts, they currently operate at stress levels higher than 72 percent specified minimum yield strength (SMYS) causing potential safety concerns. PHMSA is proposing to require operators to establish and document the MAOP and a pipeline's material if the pipeline segment meets certain criteria described in the proposed regulation. To perform this verification process, PHMSA proposes several methods that an operator may use. In addition, the NPRM proposes requirements to verify pipeline material strength for existing onshore, steel, gas transmission pipelines that are located in a HCA or Class 3 or Class 4 locations if the operator does not have reliable, traceable, verifiable, and complete material documentation for line pipe, valves, flanges and components and the pipeline meets certain criteria. The IVP process may be a costly undertaking, depending on the method selected, for pipeline operators and may subject the pipeline to risks from the required testing.  PHMSA does not describe what would be categorized as "reliable" material documentation. The result of this process may be that, for older pipelines, operators will have to lower the relevant MAOPs in response to the resulting data from the methods prescribed or may need to replace pipeline segments.    

Expansion of integrity management oversight

Further, the NPRM proposes changes to the IM program. The current IM program is intended to increase public confidence by requiring an operator to develop systemic management and mitigation of risks on its pipeline systems. PHMSA is proposing  to expand some of the IM program requirements (namely integrity assessments and remediation of defects) to areas outside HCAs. As proposed, IM program requirements would also apply in newly-defined Moderate Consequence Areas (MCA).   An MCA would include "an onshore area that is within a potential impact circle, as defined in  § 192.903, containing five (5) or more buildings intended for human occupancy, an occupied site, or a right-of-way for a designated interstate, freeway, expressway, and other principal 4-lane arterial roadway as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, and does not meet the definition of [HCA], as defined in § 192.903." Although the same process used to identify HCAs will be employed for MCAs, the threshold for buildings intended for human occupancy and the threshold for persons that occupy other defined sites located within the potential impact radius are lowered.  In these newly defined areas, integrity assessments and remediation of discovered defects, material document verification, and MAOP verification will be required.  Due to the added costs to the industry to implement certain IM requirements in non-HCA areas and the increased utilization of industry resources, PHMSA seeks comments on the potential safety benefits, avoided loss of gas, economic costs and operational considerations involved in longer or shorter compliance period for the initial and future assessments.     

PHMSA also is considering changes to the requirements for internal and external corrosion management programs, including  new regulations related to corrosion control and assessment, stress corrosion cracking and selective seam weld corrosion. Further, PHMSA seeks to strengthen its IM program by creating  more prescriptive requirements to enhance the collection, validation and integration of pipeline safety data. PHMSA is calling upon operators to apply the data obtained through an operator's integrity assessments by proposing to mandate more explicit requirements for evaluations and assessment intervals.

60-day comment period

Finally, despite the breadth of changes and lack of detailed justifications, as noted above, operators will have just 60-days to comment on the proposed rules once the NPRM is published in the Federal Register. It is likely that there will be requests for extension filed since the proposed changes will have a significant impact on pipeline operators' resources and many of the proposed regulations require further clarification or refinement. Given that PHMSA is looking to broaden its regulatory authority and the scope of its regulatory oversight with more prescriptive regulations, it is imperative for gas transmission and gathering operators to comment on the impact of these proposed regulations.   

Update: On April 8, 2016, PHMSA published in the Federal Register, the Notice of Proposed Rulemaking (NPRM) for the Safety of Gas Transmission and Gathering Pipelines. Comments are due on the NPRM by June 7, 2016.


Alisa Chunephisal* recently joined Norton Rose Fulbright's Energy Transactions practice after serving as a Senior Attorney at PHMSA. While at PHMSA, Alisa's practice involved counseling on hazmat and pipeline safety regulations, rulemakings, policy, and proposed legislation.

*Admitted only in Virginia. Practice supervised by principals of the firm admitted in the District of Columbia.

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