All California operators of intrastate natural gas transmission pipelines must prepare implementation plans to pressure test or replace all pipeline segments that have not been tested or lack sufficient records verifying such tests, according to a proposed decision released last Tuesday by Administrative Law Judge (ALJ) Maribeth Bushey.

Plans would be required to be submitted 60 days after the order is approved. The five-member California Public Utilities Commission (CPUC) cannot take up the matter until its June 9 meeting, allowing 30 days for public comment.

Also last week, Pacific Gas and Electric Co. (PG&E) filed a status report with the CPUC noting it had confirmed pressure test records on another 134 miles of transmission pipelines since data became available in mid-March.

PG&E said it is continuing its records collection and other related work, even as the CPUC’s Consumer Protection and Safety Division (CPSD) continues to disagree with PG&E’s proposed approach for validating maximum allowable operating pressures (MAOP) on pipelines running through highly populated areas, such as the San Bruno, CA neighborhood in which PG&E’s Line 132 ruptured last year.

Separately, Sempra Energy’s senior officials predicted last Monday that the holding company’s two major California utilities will satisfy the ongoing state probe on pressure testing natural gas transmission pipelines without any adverse impact on earnings.

In response to a CPUC investigation following the San Bruno rupture, Sempra’s utilities have been “actively participating” in an ongoing review process to make sure pressure tests support the operating pressures being used on the various pipelines, particularly segments in heavily populated areas, according to Sempra CEO Don Felsinger.

Bushey’s proposed decision would allow PG&E, Southwest Gas Corp., and the two Sempra utilities — Southern California Gas Co. (SoCalGas) and San Diego Gas and Electric Co. (SDG&E) — to file rate proposals for recovering the estimated costs of the programs and to outline timelines for completing the work, which could take years.

A PG&E utility spokesperson called the proposed decision “a positive step in raising the public safety bar,” noting that the utility’s greatest priority remains the safe and reliable operation of its gas pipeline system. The Sempra utilities said they were “encouraged” by the proposed decision and the inclusion of technical workshops to develop the utility implementation plans. In the meantime, more documentation for hydrostatically tested pipe has been uncovered by the Sempra utilities, they reported in a letter sent to the CPUC May 9.

Unusual emphasis is being placed on this proceeding as part of the CPUC’s and federal government’s response to the rupture and explosion of a PG&E gas transmission pipeline. In particular, PG&E has been scrambling to address federal, state and local community concerns, and the effort eroded its first quarter earnings results (see NGI, May 9). It is still facing possible fines from the CPUC.

In an April 26 letter from the CPSD, Director Richard Clark pushed back against PG&E’s plans (see NGI, May 2) by insisting that the San Francisco-based utility hydrostatically test up to 705 miles of pipeline in high-consequence areas (HCA).

“We will be working with the commission to better understand the impacts this may have on PG&E’s operations, as well as to the natural gas transmission industry as a whole,” a PG&E spokesperson told NGI in late April. “Meanwhile, we have already taken many steps to further enhance the safety of our system, including an aggressive plan to hydrostatically test or replace 152 miles of gas pipeline in 2011, etc.”

Sempra CEO Don Felsinger said the CPUC-mandated review of operating pressures and records by SoCalGas and SDG&E has “renewed our confidence that the maximum pressures on our system have been appropriately set and that we are operating our system safely.” Felsinger’s remarks ran counter to recent communications between the CPUC safety staff and Sempra’s utilities which indicated there may be sections of the pipeline system that still need hydrostatic testing.

Noting that SoCalGas and SDG&E collectively operate about 4,000 miles of intrastate gas transmission pipelines, Felsinger said the utilities’ records review has covered about 1,600 miles of pipelines in high consequence areas. About 500 miles of those pipelines were installed after 1970, and thus require pressure testing.

“Our records give us a very high degree of confidence that all of the pipeline has been pressure tested and is operating safely, ” Felsinger said. Of the remaining 1,100 miles of pipe installed prior to 1970, Sempra has uncovered records that indicate that more than 700 miles of pipe was pressure tested, he said. The other 400 miles had operating pressures determined by using “alternate procedures” allowed under state and federal regulations.

Bushey’s proposed order recognizes that the CPUC will be asking the major gas utilities to undertake a task that will take years and require an unprecedented amount of pipeline inspections and manipulations, including the use of pressure reductions in some segments. Ultimately, each of the operators’ pipelines at the end of the implementation program must have all pipeline segments covered in the CPUC order pressure tested with “traceable, verifiable and complete records” readily available, and where warranted, be capable of accommodating inline inspection devices inside the pipe segments.

The proposed decision said the utility plans “must include interim safety enhancement measures, including increased patrols and leak surveys, pressure reductions, prioritization of pressure testing for critical pipelines that must run at or near maximum allowable operating pressure [MAOP] values which result in hoop stress levels at or above 30% ‘specified minimum yield stress [SMYS],’ and other such measures that will enhance public safety.”

The implementation plans are to assure that all in-service gas transmission pipelines operating in the state have been pressure tested to meet state standards. “[These] implementation plans shall be completed as soon as practicable, due to significant public safety concerns and must include interim safety enhancement measures as described,” the proposed decision said.

Bushey noted in the proposed decision that PG&E must complete its current work on the determination of MAOP through a pipeline features analysis and apply that analysis to imposing additional pressure reductions on parts of its system as needed, pending the eventual replacement or testing work. The utility is currently squabbling with CPUC safety staff over the adequacy of its approach to making these determinations.

Given the highly technical nature of this proposed order, the ALJ has provided for a series of CPUC-sponsored workshops to be held prior to the utility implementation plans being unleashed “to assist the operators in prioritizing segments in their implementation plans.”

PG&E said it has located complete pressure test records for five miles that no longer need to be hydro tested. The utility also said it has located an added 41 miles of pressure test records where the pressure test documentation is verified, but “strength test pressure report” footage does not equal the pipeline HCA footage.

Nevertheless, PG&E offered the prospect for reducing the number of miles that ultimately will have to undergo costly and time-consuming hydrostatic testing through its ongoing work, including the expansion of the so-called Pipeline Features List (PFL). “As of April 30, the PFLs are under development for all 152 miles of priority 1 segments.

PG&E hopes to be able to provide final results for all priority 1 segments by the end of June.

“The cost we have incurred so far is less than $2 million and we don’t expect our utility earnings to be impacted by these efforts,” according to Felsinger, who said it is unclear what new pipeline requirements the CPUC will establish, but he expects the utilities to be able to recover in rates whatever added costs would be created.

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