Natural Gas Intelligence
One week after the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a pre-publication version of proposed rules governing natural gas transmission and gathering lines, experts agree that it will take some time for producers, pipeline companies, trade associations, state regulators and other stakeholders to sort through the federal agency’s proposals.
But early indications are that stakeholders will focus on the cost of implementing the proposed new rules, and determining how they affect existing state and federal regulations.
‘A Very Significant Rule’
Shortly after PHMSA issued its 549-page notice of proposed rulemaking (NPRM) on March 17 (seeDaily GPI, March 21), James Curry and Keith Coyle — attorneys with Babst, Calland, Clements and Zomnir PC in Washington, DC — issued a three-page white paper outlining several areas of the proposal that operators and other stakeholders may wish to investigate further.
According to Curry and Coyle, key changes include new materials verification requirements for certain onshore gas transmission lines; modified maximum allowable operating pressure (MAOP) requirements for all gas pipelines; strict requirements for verifying the MAOP of certain pipelines, and modified regulations for onshore gas gathering lines. Other rules address corrosion control; integrity management; new assessment and repair requirements for pipeline outside of high consequence areas (HCA), and the newly-defined moderate consequence areas (MCA).
“It’s fair to say that it’s a very significant rule, but it’s not unprecedented,” Curry told NGI. “But if you’re talking about expansion in terms of pipelines being covered that weren’t before, the biggest effect of the rule will be on gathering.”
Curry and Coyle said PHMSA is proposing to change the definition of an onshore gas gathering line and would partially repeal a longstanding exemption for rural gathering lines. The agency also plans to extend federal reporting requirements to include all gas gathering lines, whether regulated or not.
“While the new proposal for determining whether a pipeline qualifies as a gathering line appears to draw on many of the concepts in the existing regulations, two important changes are notable,” Curry and Coyle wrote. “First, the gathering function would begin at a point closer to the wellhead in many cases, thereby narrowing the extent of exempt production operations. Second, new restrictions would be imposed on the use of the incidental gathering designation, potentially expanding the universe of transmission lines in the midstream sector.”
Curry and Coyle added that under the NPRM, PHMSA would regulate certain rural gathering lines for the first time. “Gathering lines in Class 1 areas that are eight inches or more in diameter and that have an MAOP that produces a hoop stress of 20% or more of specified minimum yield strength for metallic lines, or more than 125 psig for non-metallic lines, would be regulated under Part 192 [of federal pipeline safety regulations]. These lines, designated by PHMSA as ‘Type A, Area 2’ gathering lines, would be subject to the same safety standards that currently apply to lower-stress, ‘Type B’ gathering lines, as well as the emergency response requirements in Part 192.”
Coyle said the proposed changes to gathering “are almost entirely driven by the dramatic changes that have occurred in U.S. oil gas development since the late 2000s. Prior to that time, you didn’t see pipelines that are of the size and operating pressure that you have now. You used to have vertical wells and smaller-diameter, lower-pressure gathering lines that didn’t present the kind of risk profile that you have now.
“Now you have horizontal drilling, hydraulic fracturing and much larger volumes of gas being put into much larger pipelines. That was the main driver on the gathering [rules].”
Curry and Coyle added that while changing the definition of what constitutes a gathering line will make more pipelines potentially subject to regulation — and that some production lines may be reclassified as gathering lines — the changes would impact companies differently.
“It will depend on where you sit as an operator,” Curry said. “For the gathering companies, this will be significant for them. It will be for some producers too, because PHMSA’s proposed to move the [starting points] of gathering around. But I think other parts of the rule are going to more significant. For example, the materials and MAOP verification provisions will be big things for transmission companies.”
Stakeholders May Need More Time
Although a 60-day public comment period began for the proposed rule upon publication in the Federal Register, Curry and Coyle believe stakeholders could eventually ask for more time to review the numerous proposals.
“It’s hard to say whether they will or not, but we think most, if not all, of the trade associations will ask for an extension,” Curry said. “The rule is just so long and complicated, 60 days to review it will be pretty difficult.”
Curry added that other analytical material — including a regulatory impact analysis (RIA) and a cost-benefit analysis — have not yet been released. “That should tell us a lot more about where they’re coming from,” he said.
An RIA would also provide some regulatory insight as to whether the new design requirements could even be applied to many existing pipelines. Curry and Coyle wrote that anti-retroactivity provisions in existing federal pipeline safety laws prohibit “the imposition of design, construction and initial testing requirements to pipelines constructed before those requirements were put in place.”
“It would be a big question whether PHMSA could somehow retroactively apply these design testing requirements to a pipeline that was in the ground years before the federal rules were first adopted,” Coyle said. “I don’t see how that would survive under the non-retroactivity provision, which was put in the statute for the express purpose of preventing PHMSA from applying new design testing requirements to pipes that were already in the ground, at least for additional testing, because of the cost and the impractical ability of complying.
“You would basically have to rebuild the pipeline every time PHMSA came out with a new design rule, and that’s why the provision is in the statute — to not allow that to happen.”
But the attorneys emphasized that they were not taking a position on whether the proposed rules would survive a legal challenge or not. The purpose of their white paper, they said, was just to serve as an informational guide for the various stakeholders.
Deadlines to comply with the rules should vary, Curry and Coyle said. Compliance with some of the rules could be mandated within one year of the rules being adopted; other rules could take effect in as many as seven or eight years.
“There are some companies that are better positioned from a compliance perspective, or that have fewer obligations under the proposed rule,” Coyle said. “If you have newer pipe with really good records, you’re probably in a much better position than if you’re a legacy system that doesn’t have a lot of records. It’s going impact different kinds of operators in different ways. That will also factor into who ends up the higher costs from the proposals.”
Industry to Calculate Costs
Gregory Wagner, special counsel with Baker Botts LLP in Washington, DC, said determining how to recover the costs for compliance will be high on the gas industry’s list of issues.
“One of the things we are anticipating is not only how much will it cost, but how are these pipelines going to go about recovering those costs both on the regulated side — meaning the rate regulated interstate transmission lines at FERC– and the gathering lines that are not FERC regulated,” Wagner told NGI on Thursday.
Last April, the Federal Energy Regulatory Commission issued a policy statement stating pipeline companies can recover modernization costs through surcharge or tracker mechanisms (see Daily GPI, April 16, 2015).
“On the federal side, this should increase rate litigation at FERC,” Wagner said. “One of the things FERC will look at, when allowing those surcharges, is if the pipeline has been exposed recently to a full rate review. A lot of the larger interstate lines don’t make a habit of going in for rate cases. So depending on where the people that are studying this come down on the costs, for a pipeline that has a lot of its rates at a cost-of-service basis, as opposed to negotiated, this could push them over the edge to want to go with FERC — either for a surcharge or even a full rate case.
“On the unregulated side, I think one of the issues for the gathering lines in that these are often nominally state regulated for rate issues, but it’s sort of on a complaint basis, and complaints are few and far between. These are generally worked out between the pipelines and the shippers. I think that this has the potential at least to make that a more active area at the state utility commission level — ratemaking for gathering lines.”
Wagner added that companies will also be tasked with going out to identify how many of their pipelines will now lie in the newly-defined MCAs, and whether their plans for expansion or extension will also include those areas.
“There are some unknowns there,” Wagner said. “Another issue is the de-grandfathering of the pre-1970 pipes. These are systems that don’t necessarily have the recordkeeping or operational systems in place to comply with these [new rules].”
Regulators with the Railroad Commission of Texas and the Pennsylvania Department of Environmental Protection declined to comment on the proposed rules, as did analysts with Genscape and Jefferies LLC. Representatives of the Oklahoma Corporation Commission and Spectra Energy Corp. did not return calls seeking comment. A spokesman for Kinder Morgan Inc. referred questions to the Interstate Natural Gas Association of America (INGAA).
“At this stage, we are still looking through the proposed rule to determine how closely it matches our voluntary pipeline safety commitments,” INGAA spokeswoman Catherine Landry said Tuesday. “There are a few things we are looking at in particular.” She said those topics include the expansion of integrity management to include the new MCAs, and how PHMSA will handle class locations and deal with integrity verification. INGAA also plans to conduct its own cost-benefit analysis.
“For all of these things, the devil is in the details,” Landry said. “Because it’s a long and complex rule, we have teams of technical people trying to figure out what exactly PHMSA has proposed and what that proposal means to us.”
PHMSA said its proposed regulations would meet four congressional mandates from the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, one recommendation by the Government Accountability Office, and six recommendations from the NTSB, including one that more modern testing be performed on pipelines built before 1970. PHMSA officials said approximately 57% of all onshore gas transmission pipelines were constructed before 1970.
