The federal pipeline safety agency is opening a new front in its efforts to improve gas and oil pipeline safety. The integrity verification process (IVP), previewed this summer by the Pipeline and Hazardous Materials Safety Administration (PHMSA), would be an “add-on” to the existing Integrity Management (IM) program, which obligates pipelines to test segments in “high-consequence areas (HCAs).” There are 18,000 miles of pipeline in HCAs.
This IVP would cover nearly 91,000 gas transmission miles (about 30% of the total interstate mileage), including some segments already covered under the IM program. But the brunt of those miles would be in a new classification called moderate-consequence areas (MCAs), which have not been included in the IMP. The idea is for interstate companies to verify characteristics such as maximum allowable operating pressure (MAOP) and construction materials for what are called “grandfathered” pipelines – those coming before 1970, which have never had established MAOP.
Despite being one of the biggest regulatory programs under development by the federal government, the IVP has flown under the congressional radar. That may be in part because neither interstate nor intrastate gas and hazardous liquid companies have been screaming about it. At least not yet, and a final rule appears to be a few years off. But when that final rule arrives, “the integrity management program will probably pale in comparison,” said one industry insider.
“The rule addressing MAOP and grandfathered pipe will be very significant. It is one we are watching very closely, and we plan to be very pro-active about it,” said Eric Amundsen, vice president, Technical Services, Energy Transfer Partners.
About 5,000 miles of ETP’s total 18,000 would fall under the IVP rule.
The American Gas Association (AGA) has estimated testing will cost its members $27.1 billion, three times the cost of the original intrastate IM program. Tal Centers, Jr., division vice president for System Integrity & Operations Support at Center Point Energy-Gas Operations, said the testing will take a “historic effort.”
There is no estimate of what that requirement would cost the interstate natural gas industry. However, the industry has been throwing around informal numbers in the neighborhood of $50 billion. The final cost will depend on the intricacies of the testing requirement.
The PHMSA is developing this new IVP process at the same time it is considering subjecting additional pipelines to the IM program. That has caused some confusion and concern within the interstate pipeline industry with regard to a potentially confusing jumble of new safety requirements.
The MAOP testing requirement stems from the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. This and recommendations from the National Transportation Safety Board (NTSB) led to the PHMSA development of the IVP.
Together, these mandates and recommendations call for removal of the existing “grandfather clause” within PHMSA’s regulations, new pressure testing requirements, integrity verification plans for pipeline segments that do not have complete records establishing their maximum operating pressures and the conversion of all gas transmission pipelines to accommodate inspection by inline inspection (ILI) technology (i.e., smart pigs).
Interstate pipeline companies understand that to the extent the PHMSA is implementing congressional requirements and long-standing NTSB recommendations, the agency’s hands are tied. It needs to move forward, and pipeline companies do not appear to have a problem with that forward movement.
In fact, the industry has already voluntarily undertaken some of the tasks anticipated by the draft PHMSA IVP, including through INGAA’s Fitness for Service (FFS) process for reconfirming MAOP and INGAA’s Integrity Management Continuing Improvement (IMCI) initiative, which extends and improves integrity management beyond current HCAs.
But any number of both interstate and intrastate companies have taken issue with many facets of the way the PHMSA plans to implement the MAOP provisions. For example, in a detailed filing submitted to the PHMSA on Oct. 9, INGAA stated, “INGAA members are concerned that the agency is retroactively imposing recordkeeping requirements. In PHMSA’s first draft IVP chart dated July 9, and in FAQs #13-16, the agency proposes that an operator must have four sets of records in order to properly verify MAOP. Even though PHMSA revised its flow chart on September 10, the notes portion still indicates a similar requirement.”
The PHMSA published a second iteration IVP draft on Sept. 11, and INGAA praised the agency for making improvements from its original draft. But the industry still has a number of not-insignificant bones to pick with the PHMSA second draft. There are differences over how MAOP should be reconfirmed for grandfathered pipe, that is pipeline put in the ground pre-1970, before MAOP recordkeeping requirements were in effect.
Although any IVP will open up the possibility for some sort of regulation of pipeline segments outside current HCAs – about 91,000 miles in the present estimate, 70,000 of that in the new MCAs – some of those miles would be excluded from having to have MAOPs determined.
PHMSA’s approach uses a less than 20% SMYS exclusion for certain MCA Class 1 and 2 locations, while INGAA’s approach uses a less than 30% SMYS exclusion for all MCA locations.
Aside from that difference on “screening,” the PHMSA and INGAA have different ideas on the “actions” required to reconfirm MAOP, such as pressure tests, de-rating, replacing or in-line inspection.
Under the new pipeline law President Obama signed in January 2012, the PHMSA was scheduled to publish a final rule by June to establish testing requirements for MAOP. That rule was not forthcoming and isn’t likely to any time soon because the PHMSA appears to be road-testing the requirement as part of the IVP, which will not be ready for a few years.
This and other delays of implementation of the pipeline law have made some top Democrats hot under the collar. In a letter sent to Transportation Secretary Anthony Foxx on Oct. 31, Rep. John Dingell (D-MI) wrote that a natural gas pipeline explosion in Rosston, OK, and an oil pipeline spill in North Dakota earlier this month underscored the need for the new regulations. Dingell argued that the department appears to have done little to meet the law’s requirements and said it is unclear when new regulations on pipeline testing, data gathering and shut-off valves may be completed.
“The lack of action on this front is not only disturbing to a public that is concerned about the safety of our quickly growing system of pipelines, but it is also unsettling to the industry, which has no certainty as to what the rules will be going forward,” Dingell wrote.
Bill Eliminating State Dept. From Cross Boundary Approvals Draws Fire
A top federal pipeline officials voiced opposition to a new congressional bill that would remove the State Department from the process of approving the construction of pipelines that cross the U.S. borders with Canada and Mexico.
Many energy industry players, and various interest groups, are angry at the State Department for taking so long to finish an environmental review of TransCanada’s Keystone XL pipeline project. Because that pipeline goes from Hardisty, Alberta, and extends south to Steele City, NB, the State Department is required to issue a presidential permit, which in turn requires a detailed environmental review.
But Jeff Wright, the director of the Office of Energy Products for the Federal Energy Regulatory Commission (FERC), opposes the North American Energy Infrastructure Act (H.R. 3301) because it would take the State Department out of the current process, eliminate environmental reviews of potential projects and require FERC, in the case of natural gas pipelines, to approve a project within 120 days.
“A 120-day deadline would not permit construction of an adequate record, enable important agency consultation or allow for meaningful public interaction in arriving at a decision,” he told the House Energy and Commerce Committee in late October.
INGAA supports the bill, however. In a letter to Reps. Fred Upton (R-MI) and Gene Green (D-TX), the sponsors of the bill, INGAA CEO Don Santa wrote, “The laws governing the approval of cross-border energy infrastructure should be updated to reflect the free trade arrangement we have shared with these nations since 1994.”
The Keystone XL isn’t the only inter-North American pipeline project with a delayed presidential permit. John H. Kyles, senior attorney, Plains All American Pipeline, said his company has two permits related to the minor issue of change of ownership that have been stuck in the State Department for years.
Permits must also be approved when a pipeline changes direction. Portland Pipe Line Corp. has considered making that change so tar sands product can be brought south on its existing 236-mile pipeline, which originates in Montreal and travels through some northeastern states, including Vermont. It has no current plans to reverse the flow, however.
That said, David Mears, commissioner of the Vermont Department of Environmental Conservation, told the House Energy and Commerce Committee in late October that his state is concerned about the bill’s easing of requirements for environmental studies for boundary crossing pipelines.