On April 8 2016 the Department of Transportation's Pipeline and Hazardous Materials Administration (PHMSA) published in the Federal Register an ambitious and long-awaited 549-page notice of proposed rulemaking applicable to onshore gas transmission and gathering pipelines. In the notice, the PHMSA:
- responds to congressional, Government Accountability Office 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 notice, the PHMSA proposes several significant changes to the regulatory scheme for gathering lines, including bringing oversight of gathering lines that have traditionally escaped federal regulation under its jurisdiction.
The PHMSA notes that because of burgeoning domestic shale plays and the associated demand for gathering of gas, gathering lines are now being used that range in size from 4 to 36 inches in diameter with maximum allowable operating pressures (MAOP) of up to 1,480 pounds per square inch gauge. The largest of these lines have diameters that are traditionally more typical for gas transmission lines and are being operated at much higher pressures than previously seen in gathering lines. Based on 2011 annual reports submitted to the PHMSA, there are approximately 20,281 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.
In order to bring a greater proportion of gathering lines under (and clarify the scope of) federal oversight, the PHMSA proposes making the following changes to its existing regulatory scheme for gas gathering lines:
- applying the Type B gathering line requirements to Type A gathering lines in Class 1 locations when the nominal diameter is 8 inches or greater. The 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 that the 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;
- repealing the use of the American Petroleum Institute's Recommended Practice 80 (49 CFR 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;
- changing 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,
- requiring all operators of both unregulated and regulated onshore gas gathering lines to file annual incident and safety-related conditions reports.
The new definition of 'gathering line' would significantly extend the PHMSA's jurisdictional reach. While the PHMSA does not propose rulemaking to apply integrity management or internal corrosion requirements to gathering lines, the notice of proposed rulemaking leaves that possibility open, noting that final determinations will be made in the future.
The notice of proposed rulemaking unveils the agency's integrity verification process in accordance with congressional mandates found in Section 23 of the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. This integrity verification process appears primarily to target pipelines in Class 3, Class 4 and high-consequence areas to reconfirm the MAOP for pipelines that established their MAOPs based on 49 CFR Section 619(c). Based on this grandfather provision, those pipelines had their MAOP established to the highest actual operating pressure to which they were subjected during the five years prior to July 1 1970 (the initial publication date for the Pipeline Safety Regulations). Unlike many of their modern counterparts, they operate at stress levels higher than 72% of the specified minimum yield strength, causing potential safety concerns. The PHMSA proposes requiring operators to establish and document the MAOP and the pipeline's material if the pipeline segment meets certain criteria (described in the proposed regulation). The PHMSA proposes several methods that an operator may use to perform this verification process.
The notice of proposed rulemaking also proposes requirements to verify pipeline material strength for existing onshore, steel and gas transmission pipelines that are located in a high-consequence areas 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.
Depending on the method selected, the integrity verification process may be costly for pipeline operators and may subject the pipeline to risks from the required testing. The PHMSA does not describe what would be categorised 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 data resulting from the methods prescribed or replace pipeline segments.
The notice of proposed rulemaking proposes changes to the integrity management programme. The existing integrity management programme is intended to increase public confidence by requiring an operator to develop systemic management and mitigation of risks on its pipeline systems. The PHMSA proposes to expand some of the integrity management programme requirements (namely, integrity assessments and remediation of defects) to areas outside high-consequence areas. As proposed, integrity management programme requirements would also apply in newly defined moderate-consequence areas. A 'moderate-consequence area' 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 high consequence areas, as defined in § 192.903."
Although the same process used to identify high-consequence areas will be employed for moderate-consequence areas, the threshold for buildings intended for human occupancy and the threshold for persons that occupy other defined sites located within the potential impact radius will be 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 integrity management requirements in non-high-consequence areas and the increased use of industry resources, the 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.
The PHMSA is also considering changes to the requirements for internal and external corrosion management programmes, including new regulations related to corrosion control and assessment, stress corrosion cracking and selective seam weld corrosion. Further, the PHMSA seeks to strengthen its integrity management programme by creating more prescriptive requirements to enhance the collection, validation and integration of pipeline safety data. The PHMSA is calling on operators to apply the data obtained through an operator's integrity assessments by proposing to mandate more explicit requirements for evaluations and assessment intervals.
Despite the breadth of changes and lack of detailed justifications, operators have been given only 60 days from publication of the notice of proposed rulemaking in the Federal Register to comment on the proposed rules. Hence, comments are due by June 7 2016. Requests for extension are likely to be 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 the 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.
For further information on this topic please contact Lisa M Tonery at Norton Rose Fulbright LLP's New York office by telephone (+1 212 318 3000) or email (email@example.com). Alternatively, contact Erik Swenson at Norton Rose Fulbright's Minneapolis office by telephone (+1 612 321 2800) or email (firstname.lastname@example.org). The Norton Rose Fulbright website can be accessed at www.nortonrosefulbright.com.
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