February 2017, Vol. 244, No. 2

Government

Timeframe, Wording at Issue in Underground Facility Safety Rule

The compliance start date for the new federal safety requirement on underground gas storage facilities doesn’t go into effect for one year, but arrival of the Trump administration could extend that deadline. That is the hope of groups such as the Interstate Natural Gas Association of America (INGAA) and the American Petroleum Institute (API). While they generally support part of the incorporation of industry voluntary standards into federal pipeline safety laws, they claim the 12-month implementation deadline is too short.

The industry hopes the Pipeline and Hazardous Materials Safety Administration (PHMSA) will realize the problem and change it on its own. If not, there could be industry-sponsored litigation. The PHMSA interim final rule (IFR) issued in December has wiggle room allowing it to make changes based on public comments, which were due Feb. 17.

Don Santa, president and CEO of INGAA, says, “INGAA strongly supports PHMSA regulation of natural gas storage based on consensus standards. We are quite concerned the 12-month implementation period outlined in the interim final rule is unrealistic. Extensive effort will be required to implement a structured and documented integrity management program across the roughly 400 underground gas storage facilities in the United States.” The standards will directly apply to 197 interstate facilities and 203 intrastate facilities. INGAA’s board last February supported voluntary adoption of these consensus standards.

While the timetable for implementation is the big concern for industry groups, some players such as the American Gas Association (AGA) want additional changes. Christina Sames, vice president of operations and engineering for AGA, says AGA, which fully supports incorporating by reference the API’s Recommended Practices 1170 and 1171 into federal law, also wants a change in the timetable as well as a reversal of the IFR’s language which makes all non-mandatory provisions in the Recommended Practices mandatory.

Perhaps not surprisingly, environmentalists think the IFR stops short of needed protections in the wake of the Aliso Canyon gas storage field leak, which prompted Congress to enact the new safety requirements which PHMSA is implementing. “The new standards offer scant or no detail on many safety precautions, creating immediate challenges for the state and federal regulators enforcing these new policies,” argues Adam Peltz, attorney, Climate and Energy Program, Environmental Defense Fund. “To bridge this gap, PHMSA will need to both beef up the rule and rely on state expertise to ensure all gas storage wells are held to uniformly high standards.”

Nor does he consider the implementation deadline onerous. “Since the PHMSA rule is essentially the industry’s own consensus standards, one would think compliance would be relatively straightforward,” he explains. “If PHMSA had adopted a more rigorous rule, we might be sympathetic to calls to extend the deadline, but at this juncture we are not persuaded that the industry needs longer than a year.”

PHMSA issued the IFR in December to take effect Jan. 18, 2017. But interstate and intrastate pipeline facilities do not have to comply with its requirements until Jan. 18, 2018. Given what are likely to be changes in the attitudes of federal regulatory agencies under the Trump administration, it is entirely possible PHMSA will rethink the implementation deadline, which may also come under pressure from congressional Republicans.

The IFR incorporates the API’s Recommended Practices 1170 and 1171 by reference into the pipeline safety regulations. Recommended Practices 1170 and 1171 outline standards for the design and operation of solution-mined salt caverns used for natural gas storage, and functional integrity of natural gas storage in depleted hydrocarbon reservoirs and aquifer reservoirs.

PHMSA has safety regulations which apply to the surface piping at underground gas storage facilities. There are no federal regulations covering downhole facilities – such as wells, wellbore tubing, and casing – or the operations, maintenance, integrity management, public awareness, and emergency response activities associated with these downhole facilities. The Aliso Canyon well leak is believed to have originated from downhole well casing.

Many states have laws setting minimum standards for the material integrity testing of components to ascertain an intrastate well’s condition. But most lack specific and consistent regulations that include operating procedures and remediation for operations, maintenance, integrity demonstration and verification, monitoring, threat and hazard identification, assessment, remediation, site security, emergency response and preparedness, and recordkeeping requirements. The IFR would set a minimum federal standard in those areas for all state regulatory programs.

Some states may have regulations which cover some downhole operations. But none of the 197 interstate facilities would be similarly covered by those. That is a particular concern because the pipe at these facilities is threaded, rather than welded like a pipeline, making the pipe more susceptible to breaks. A broken pipe at any facility would allow gas to escape at a much higher rate and would be more likely to catch fire, leading to a greater risk to life and property.

Operators will be permitted to deviate from the API RPs if they provide a sufficient technical and safety justification in their program or procedural manuals as to why compliance with a provision of the recommended practice is neither practicable nor necessary for the safety of a particular facility.

PHMSA will evaluate these justifications as part of its compliance inspection process, taking into account whether the operator’s procedures reflect sound engineering principles and achieved acceptable performance as demonstrated by annual reports and incident data. PHMSA will incorporate lessons learned from these compliance reviews of underground storage facility operations into inspection protocols and inspector training programs.

Corps Ignores Pleas to Restrict Pipeline Construction Permits

The Army Corps of Engineers rejected efforts by environmental groups to limit availability of nationwide permits (NWPs) that pipelines use when they want to build facilities that cross streams and tributaries but cause insubstantial environmental damage. The Corps issued its revisions to 50 NWPs last month, including changes to NWP 12, which is used by gas and oil pipeline companies.

Activities eligible for NWPs, which allow companies to begin construction faster than if they had to apply for an individual permit, cover discharges of dredged or fill material that cause only minimal adverse environmental effects. NWP 12 covers utility projects that would have up to a half acre of “loss of waters of the U.S.”

Key issues were whether to adjust the half-acre limit, whether NWPs should be available for one large pipeline project which crosses many water bodies, and how quickly a Corps district office must respond to a preconstruction notice (PCN) which a pipeline company must submit in order to obtain an NWP. A PCN is required when the project meets one of seven factors. NWP 12, like other NWPs, lists numerous “general conditions” which must be adhered to before a project qualifies for a NWP.

Environmental groups had pressed the Corps to allow NWP 12 to expire without reissuance. The Corps ignored that request. INGAA said elimination of NWP 12 would be contrary to congressional intent and raise costs for pipeline construction dramatically. One study cited by INGAA concluded that, on average, it takes an extra 475 days to obtain an individual permit vs. an NWP. That same study concluded the average cost to prepare an NWP application is $28,915 vs. an individual permit application, which, on average, costs over $271,596, excluding cost of mitigation, design changes, costs of carrying capital, and other costs.

The fallback position of the Sierra Club and its allies was to ask the Corps to change the wording of NWP 12 so that a pipeline company could not use it for large projects such as TransCanada’s Gulf Coast Pipeline – the southern half of the Keystone XL pipeline – which crossed 2,227 waters over many miles. “This marked the first time the Corps had approved a major project in this way using NWP 12,” said numerous environmental groups under the Sierra Club’s leadership.

The environmental groups alleged that since using NWP 12 to permit the Gulf Coast Pipeline in 2012, the Corps has verified several other major pipelines in the same way. For example, four Corps district offices verified the 600-mile Flanagan South crude oil pipeline through 1,950 waterways in four states under NWP 12. The Corps verified the 1,168-mile Dakota Access Pipeline through North Dakota, South Dakota, Iowa, and Illinois using NWP 12.

“Simply put, the Congress did not intend the NWP program to be used to streamline major infrastructure projects like the Gulf Coast Pipeline, the Flanagan South Pipeline, and the Dakota Access Pipeline. Pipeline projects like these should undergo an individual Section 404 permit review under the Clean Water Act,” the groups wrote.

The Corps turned a deaf ear to that request, too. In allowing the use of NWP 12 for major projects the Corps explicated its interpretation of the meaning of “separate and distant crossing of waters of the United States.” The utility line activities authorized by NWP 12 are similar in nature because they involve linear pipes, cables, or wires to transport physical substances or electromagnetic energy from a point of origin to a terminal point, the Corps explained.

The Corps also stood fast on the half-acre threshold. INGAA had supported its continued application, arguing it and the PCN requirements are “appropriate, well-supported by the record, and fully ensure that activities authorized by those NWPs will result in no more than minimal individual and cumulative adverse effects.”