On June 7, a panel assembled for the Energy Bar Association’s spring meeting in Washington D.C. focused on gas pipeline safety issues in an era of unusually high regulatory activity and accompanying uncertainty. The dialogue also took place in a week of relevant Congressional action (the House passed a Pipeline Safety Act reauthorization bill on June 8, see adjacent article), and at a time when the industry is entering the home stretch in preparing comments (due in early July) on a major PHMSA notice of proposed rulemaking (NOPR) to implement statutory mandates dating from 2011.
The program’s panelists were:
- Susan Olenchuk – Partner, Van Ness, Feldman LLP;
- Robin Rorick – Group Director, Midstream and Industry Operations, American Petroleum Institute (API);
- Elke Hodson – Office of Climate, Environment, and Efficiency/Energy Policy and Systems Analysis, U.S. Department of Energy (DOE); and
Karol Newman, a partner at Wilkinson Barker Knauer, served as the panel’s moderator.
Pipeline Safety Act: Past Implementation and Rising Concerns about “Legacy” Pipe. Olenchuk kicked off the discussion by backgrounding the audience on the Pipeline Safety Act, underscoring that this law, dating from 1968, comes up for reauthorization every 4-5 years and is typically amended on those occasions by Congress. As an example of a “federal-state partnership,” the statutory scheme calls for implementation by state agency employees, subject to “oversight” by federal personnel.
PHMSA’s jurisdictional grant under the Act is especially broad; unlike FERC’s Natural Gas Act jurisdiction, which is confined to pipelines engaging in “interstate commerce,” PHMSA’s jurisdiction is applicable to pipelines “in or affecting” interstate commerce, thereby sweeping in not only interstate systems but also intrastate pipelines, gathering lines, distribution lines, and underground storage facilities. However, noted Olenchuk, PHMSA has not exerted the full extent of its statutory authority; still, it is “very broad,” covering about 2.6 million miles of line.
With respect to PHMSA’s primary work product – safety regulations (the first set of which was adopted in 1970) – Olenchuk stressed an important distinction between new and existing pipelines. The design, construction, installation, testing, and initial inspection regulations did not apply to existing pipelines. Nonetheless, PHMSA is concerned about the “unseen” or “legacy” systems – in other words, the pipe that was installed prior to 1970. Its concerns range from previously undetected manufacturing and construction defects and “problematic” materials and construction methods to the general challenges of “aging infrastructure.” The scope of the “legacy” issue is considerable, since over 60% of the pipelines in this country were built before the 1970 onset of PHMSA’s oversight, Olenchuk reported.
PHMSA’s concern is also directed at a new facet of the industry – namely, the “proliferation” of gathering infrastructure built in the last decade to serve the multiregional gas shale plays. Olenchuk added that the agency’s agenda is further influenced by major accidents, along with attention from Congress, the DOT’s Inspector General, the National Transportation Safety Board (NTSB), and the media, among other pressures.
As a case in point, Olenchuk highlighted the fatality-causing 2010 explosion of PG&E’s 30-inch diameter steel line in a residential part of San Bruno, California along with its aftermath. The NTSB’s post-event analysis included recommendations that (1) pressure testing records be “traceable, verifiable, and complete”; (2) PHMSA eliminate the “grandfather clause” that did not require any pressure testing of pre-1970 pipe to determine a safe maximum operating pressure; (3) the agency should mandate hydro-testing of pre-1970 pipe (as well as a “spike” test); and (4) manufacturing/construction defects be considered “stable” only if they pass a pressure test at 125%of maximum operating pressure (which exceeds current requirements).
2011 Reauthorization with Toughened Testing; PHMSA’s April 2016 NOPR. Congress, also mindful of lessons learned from the 2010 California accident, required in the 2011 reauthorization that gas transmission line operators in “certain populated areas” (1) confirm their maximum allowable operating pressure; and (2) assure that their records accurately reflect the pipe’s physical and operating characteristics. The 2011 reenactment also obligated PHMSA to require operators to reconfirm their maximum allowable operating pressures for lines with “insufficient” records and to determine appropriate interim safety actions until those maximum pressures are confirmed. Moreover, Congress required “material strength testing” for untested lines. PHMSA was tasked to develop regulations to implement these increased requirements.
On 4/8/16, PHMSA at long last came out with a NOPR (with comments due July 7) to implement the revised statutory requirements. Olenchuk described the proposal as “long and complex” and averred that practitioners who have been studying it “for a long time” are still coming up with “new nuances to be explored.”
Olenchuk focused on two aspects of the NOPR with pervasive impacts. One of these is a broad program of “records verification” for all existing pipelines. While interstate pipelines have not historically been required to maintain these types of records, if the regulations are imposed as proposed, they will have to verify the existence of (or make anew) “reliable, traceable, verifiable, and complete” records on original steel pipeline manufacturing, design, and components. For systems lacking existing records that meet these criteria, explained Olenchuk, this will require an extensive documentation development program with procedures for verifying physical attributes and “destructive and non-destructive” testing.
The second area of the NOPR Olenchuk thought worth underscoring revolves around “maximum allowable operating pressure” (MAOP) verification. It applies to (1) pipelines in more populated areas that lack MAOP testing records meeting the law’s criteria (traceable, reliable, etc.); (2) pipelines where there has been an incident since the last pressure test attributable to an original construction defect; and (3) “grandfathered” pipe located in more populated area or what is called a “moderate consequence” area (provided the pipe is “piggable”).
The MAOP testing regulations would require a number of alternative measures, including pressure testing, spike tests for “legacy” pipe, pressure reduction, internal inspection, or pipe replacement. This must be completed within 15 years for all “affected” pipe (within 8 years for 50% of affected pipe).
Rural Gas Gathering Lines. Olenchuk explained that PHMSA does not generally regulate gas gathering lines in rural areas; but, with the recent proliferation of high-pressure, large-diameter lines to enable the export of production from shale gas plays, it has become sufficiently concerned to take a step in this direction. Under the proposed rule, gathering lines in rural areas with a diameter 8 inches or greater will be subject to “limited” regulation, consisting of (1) corrosion control; (2) MAOP requirements; (3) emergency response; (4) damage prevention; (5) line markers; (6) leakage surveys; and (7) public education.
What’s not obvious until you look more closely, Olenchuk pointed out, is that previously unregulated gathering lines will be subject to records verification and enhanced corrosion requirements, including verification of MAOP and various pipeline attributes.
Industry Concerns. Olenchuk then turned to a list of industry concerns stirred up by the April NOPR. The extensive applicability of the records development and retention requirements, applying to virtually all gas transmission lines, raises the issue of conflict with the “anti-retroactivity” provisions of the law for pre-1970 pipelines, by requiring operators to “produce records they had never been previously required to keep.” She also identified as a concern that PHMSA had apparently not consulted with FERC or state regulators regarding the impact of materials strength testing, timetables for taking lines out of service, and the effects of this activity on service. Moreover, she noted that PHMSA has not appeared to consider the costs versus benefits or the environmental impacts, since taking a line out of service for pressure testing entails releasing “a lot of methane” as well as putting “a strain on water supplies.”
2016 Pipeline Safety Act Reauthorization. Olenchuk finished her presentation by taking a glance at the legislative reauthorization which passed the House that week and was expected to clear the Senate shortly thereafter. Noteworthy provisions include:
- Regulation of underground natural gas storage facilities: PHMSA will be required to adopt regulations addressing the safety of underground gas storage facilities. These facilities are currently under state regulation only, but Congress is now requiring that the “gap” in federal regulation be closed, in the wake of the leakage at the Aliso Canyon storage field discovered by Southern California Gas Co. employees in October 2015.
- Emergency order authority. Under this provision, PHMSA would be empowered to issue industry-wide directives to address “imminent hazards,” defined as a “pipeline condition presenting a substantial likelihood of death, illness, endangerment to health, property, or the environment. In keeping with the “emergency” concept, there would be no prior notice or opportunity for a hearing in advance, although there would be provisions for administrative review and/or “expedited judicial review.” The chief concern of the industry is to guard against this extraordinary remedy turning into a “knee-jerk reaction,” without industry input or weighing the effect of an emergency measure on customer service.
API’s Views on Pending PHMSA Regulations. Rorick, API’s midstream operations director, began his comments by emphasizing that oil and gas will remain cornerstone fuels in this country for many years to come. For validation, he cited the U.S. Energy Information Administration’s forecast that, in 2040, oil and gas will still be supplying 60% of the nation’s energy needs. Rorick also informed the audience that, while API is best known as an industry advocacy organization, it devotes considerable resources to technical standards-setting, recommended practices, and certifications: about 65% of its 275-strong staff, based in Washington D.C. and various states, is involved in this separately funded realm of activity.
Rorick then focused mostly on the pending PHMSA Hazardous Liquid Pipelines safety rule and underground storage safety developments. While API does not have as many concerns about the hazardous liquids rule as it does about natural gas pipeline NOPR, it does have “a couple of major concerns.”
Hazardous Liquid Pipeline Rule. The proposed regulations for hazardous liquid pipelines stems, like PHMSA’s natural gas pipeline NOPR, from Congress’s 2011 reauthorization of the Pipeline Safety Act. API’s first area of concern involves PHMSA’s proposed requirements for “post-extreme weather event” safety inspections. The subject entity’s obligations are defined by “a lot of vague terms,” his member companies believe, that could lead to “litigious issues on the back side” absent clarification.
The second area of concern is PHMSA’s position on assessment methods for “low-risk” pipeline segments. Rorick suggested that the agency has so far been “rigid” regarding the prescribed method, whereas API believes the industry should have “a number of tools at its disposal.” By imposing a singular method instead of affording latitude, PHMSA may be forcing a pipeline to make a less effective choice, API believes.
API’s critique of the agency’s proposed changes in pipe repair criteria follows a similar mold: PHMSA, says Rorick, has proposed a “fairly rigid program” for addressing “dents and cracks,” whereas API “wants to make sure it has a mechanism to conduct a thorough analysis,” with “some capability to work with PHMSA to select the appropriate tools” to address dents or cracks.
Operator Qualification and Natural Gas Pipeline Rules. Yet another PHMSA regulation API is tracking and commenting on is the “Operator Qualification” rule. Here, Rorick highlighted two main bones of contention: (1) concerns about clarity of the rule’s definition of a “Confirmed Discovery”; and (2) PHMSA’s plan to replace the existing “four-part test” for an operator’s qualification (PHMSA wants to introduce an entirely new definition of the test, while API believes any specific concerns the agency has about the four-part test should be addressed more narrowly, in lieu of wholesale replacement).
Rorick largely deferred to Olenchuk’s discussion of the natural gas pipeline NOPR and the industry’s concerns. But he did pause to characterize PHMSA’s 500-page proposal as “a beast” raising a “lot of concerns” for his members. As to the agency’s proposal for expanding its regulation to gathering lines, Rorick acknowledged that there is a case for such regulation, since gathering lines have begun to be designed much like long-line, high-pressure lines. Nonetheless, API deems “arbitrary” the proposed 8-inch diameter threshold for coverage of the new regulations, and generally views the “extent of” and “tipping point” for such coverage as matters for discussion and debate.
Rorick also suggested that the cost/benefit analysis in the NOPR is insufficiently robust, and hence is a target of industry concern and comment.
Underground Storage. Rorick echoed Olenchuk’s observation that there has been a good deal of activity on this front since the Aliso Canyon incident. He touched on two “recommended practice” standards API has issued relevant to underground storage safety, one devoted to salt caverns and the other to depleted hydrocarbon reservoirs. In February, PHMSA issued an advisory bulletin encouraging industry members to follow these practices (which, he stressed, are now voluntary). But PHMSA is considering developing an “interim final rule” based on these recommended practices, and the discussion, he indicated, will be turning to “what extent and when” the agency will be requiring companies to come into compliance with API’s storage facility guidance.
Compliance with the storage facility recommended practices “may sound fairly simple,” Rorick allowed, but he stressed that they provide “a whole framework, and a whole culture” for safety management of underground storage, and many companies will have to adjust their current practices substantially to fully embrace them. Moreover, he noted that there are some provisions in the 2016 Pipeline Safety Act reauthorization before Congress requiring PHMSA to move forward on underground storage, so API is following this development closely. Meanwhile, API is teaming up with AGA and INGAA in doing a pair of white papers on the technical aspects to contribute to PHMSA’s analysis.
A Comprehensive Pipeline Safety Management System. Rorick also described a major API effort to provide the midstream segment of the industry with a new framework for establishing a “safety culture.” RP 1173, a response to another of the NTSB’s recommendations, sets up a “whole safety management system,” he explained, for both natural gas and liquids pipelines, similar to that of the airline industry. Rorick mused that “it sounds wonky – and it is,” but lauded the initiative for establishing the “bedrock” of a complete safety culture, ranging from worker “slips and falls” to creating a “remediation program.”
API has drafted the nuts and bolts of the process itself, and is now engaged in developing an implementation plan. The PHMSA Administrator, Rorick added, appears to be putting a good deal of stock in this program as well, bringing it up in all her public speeches. He related that similar programs already exist for the exploration/production and refining ends of the industry, but it is “a huge lift” when companies go to work adopting it. That said, the construct is “flexible enough,” API believes, to assist those new to safety management systems, and “scalable” to all sizes of operators. Rorick promised that “you’ll see huge shifts” in the industry as RP 1173 gets implemented over the next couple of years.
Hodson Surveys Government’s Growing Agenda for Methane Emissions Control. Now a DOE policy analyst and, by training, a scientist, Hodson focused her remarks on (1) quantifying the emissions sources to help guide government and private reduction efforts; and (2) the regulatory aspects – that is, working on “the pieces of the puzzle.” The goal, she added, is to use resources efficiently and treat the environment responsibly.
Methane emissions can come from many parts of the natural gas infrastructure chain, either from “normal operations or leaks.” Taking “inventory” of current, human-caused sources of methane emissions, Hodson presented 2014 data, which indicated that the U.S. natural gas production and delivery sectors are collectively responsible for “about a quarter” of total emissions. This came with the caveat that an emissions inventory is “a work in progress” and that, in the last year, there has been a “significant uptick” in the amount of emissions coming from production, while less has come from the transmission and distribution infrastructure.
Hodson then turned the spotlight on the Administration’s “Climate Change Action Plan,” of which methane emissions reduction is a key component. At the President’s behest, the DOE participated in developing a “comprehensive Interagency Methane Strategy” completed in March 2014. The strategy adopted a year 2025 emissions reduction target for the oil and gas sector of 40-45% (compared with 2012 levels), and rests on three “pillars”:
- Assessing current emissions data and addressing “data gaps”;
- Identifying the “best practices” and technology solutions for reducing methane emissions;
- Identifying “existing authorities” and “incentive-based opportunities” for reducing emissions.
In reviewing “existing authorities” available to address methane emissions, Hodson first observed that traditional pipeline regulation by FERC (as well as distribution system regulation by state commissions) has focused on cost – not environmental protection – and hence the cost of methane escaping into the atmosphere has been recoverable as “lost and unaccounted-for gas.” However, Hodson holds a very positive view of FERC’s recent policy statement supporting cost recovery mechanisms for pipeline modernization projects (which advance safety and the environment).
Continuing her survey of “existing authorities,” Hodson noted PHMSA’s mandate is to protect against the danger from pipeline leaks and explosions, although their programs also have indirect environmental benefits. From a strict environmental standpoint, however, only EPA has authority to address methane-driven air pollution. In the past, she noted, EPA has only indirectly regulated methane while relying on voluntary programs for more direct attention; but that changed this May, when EPA finalized regulations directly addressing methane emissions from “new sources.” Hodson also touched on the Bureau of Land Management’s authority to regulate “oil and gas activities” on federal and tribal lands, as well as the DOE’s engagement on the research and development front.
Natural gas storage safety is another focus of DOE through an interagency task force. Co-chaired by DOE and PHMSA with technical support from EPA, FERC, and other agencies, it is aimed at identifying “best practices” to support (1) well integrity; (2) proper response plans; and (3) safe operations of storage facilities. In addition, the task force is looking at the “potential vulnerabilities” to energy reliability posed by losses of storage facility usage.
 The panel bore the title, Known Knowns and Known Unknowns: Sifting through Regulatory Changes in the Gas Pipeline Industry.
 PHMSA is the acronym for the Pipeline and Hazardous Materials Safety Administration, a branch of the U.S. Department of Transportation (DOT).
 Once a state is certified, its regulatory enforcement becomes primary under this “partnership.” Olenchuk noted that all 48 contiguous states have been certified by PHMSA for natural gas pipeline safety.
 Despite this impressive statistic, noted Olenchuk, 80% of the pipelines in this country are subject to state safety regulation.
 It found that PG&E’s record-keeping fell short of this standard.
 The law also required coordination of testing time frames with FERC and state regulators, consideration of safety and environmental impacts, and the minimization of cost and service disruptions associated with pipeline testing.
 However, PHMSA would be required to consult with other appropriate agencies with expertise in the matter.
 These papers, which Rorick hopes to complete in a few weeks, pertain to (1) subsurface valves; and (2) well integrity.
 Hodson is an MIT graduate and has authored numerous technical papers.
 In addition, the U.S. and Canada committed in March of this year to taking “coordinated domestic actions” to reduce methane emissions from their oil and gas sectors. Canada has adopted the same reduction target of 40-45%.
 The regulation of volatile organic compounds or VOCs by EPA has indirectly constrained methane emissions.
 FR No. 3100, pp 1-4.
 DOE activities on this front include: a DOE-NARUC partnership for technical assistance (launched this February); a website dubbed the “Natural Gas Modernization Clearinghouse”; the provision of technical assistance to EPA’s voluntary “Methane Challenge Program” (launched in March); a program (“ARPA-E”) funding 11 new projects for developing low-cost methane sensing devices for the oil and gas sector; and a $12 million funding program (FY 2016) to support Methane Emissions Mitigation and Methane Emissions Quantification, under the aegis of the Office of Fossil Energy.
Copyright © 2016 by Concentric Energy Publications, Inc. All rights reserved.