5. Comments on Proposed Decision

The proposed decision of the ALJ in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on May 31, 2011, and reply comments were filed
on June 6, 2011.

In its comments, PG&E supported the proposed decision but requested that the Commission allow the use of alternative inspection technologies to verify pipeline integrity where pressure testing would cause an interruption in service to customers. PG&E proposed that the decision be modified to all an operator to provide CPSD 30 days notice of its intention to use alternative inspection technologies and, if no objection raised, to proceed with the alternative.

SoCalGas and SDG&E recommended that the Commission consider all issues in this proceeding pursuant to a three track schedule.25 These operators also sought clarification on whether the scope of the decision was limited to natural gas transmission pipeline located in the high consequence areas identified by the NTSC or included all pipeline regardless of location. These utilities also requested that the proposed decision be clarified to allow operators to use in-line inspection tools and inspection technologies to validate the pressure-carrying ability of pipeline segments.

The Division of Ratepayer Advocates opposed the proposed decision's requirement for ratemaking proposals as being premature and recommended that PG&E pay all costs associated with the implementation plan.

TURN supported the proposed decision and asked for three modifications: (1) provide more guidance on pipeline retrofits and valve replacement components, (2) expand the time for workshops, and (3) leave open the question of ratemaking for SoCalGas and SDG&E.

The City of San Bruno recommended that the proposed decision require the implementation plans to have urgent and timely deadlines.

The City and County of San Francisco supported the proposed decision in many respects but argued that additional detail should be provided on how the plans will be put into effect and that all pressure testing should be performed by a third party.

The Utility Workers Union of America supported the proposed decision but questioned whether additional pipeline should be included and recommended that costs of implementing the plan should be incorporated into SoCalGas's current general rate case.

The Coalition of California Utility Employees generally supported the pipeline testing requirement of the proposed decision but opposed having PG&E's shareholders pay a portion of the costs.

The Greenlining Institute questioned whether the costs to be incurred by the MAOP validation efforts continued to be justified in light of the proposed decision's requirement for pressure testing or replacement.

The Black Economic Council, the Latino Business Chamber of Greater Los Angeles, and the National Asian-American Coalition filed joint comments supporting cost sharing. The comments also included a survey on the proposed cost sharing mechanism.

Californians for Renewable Energy opposed the proposed decision because it did not include sufficient process validation and product performance qualification.

In reply comments, the Plumbers, Pipe Fitters, and Steamfitters Local Unions Nos. 246 and 342, and their individual members recommend that the implementation plans ensure that that workers, testers, and inspectors are qualified, and that all materials and testing, repair, and replacement methods meet state-of-the-art strength and safety standards.

Reply comments were also filed by SDG&E, SoCalGas, TURN, City of San Bruno, City and County of San Francisco, the Greenlining Institute, Utility Workers Unions of America, and CAlifornians for Renewable Energy.

All comments and reply comments have been reviewed and, where warranted, revisions to the proposed decision have been made.

1. In Resolution L-410 and R.11-02-019, the Commission ordered PG&E, SoCalGas, SDG&E, and Southwest Gas Corporation to:

a. Aggressively and diligently search for all as-built drawings, alignment sheets, and specifications, and all design, construction, inspection, testing, maintenance, and other related records, including those records in locations controlled by personnel or firms other than PG&E, relating to pipeline system components, such as pipe segments, valves, fittings, and weld seams for PG&E natural gas transmission lines in Class 3 and Class 4 locations and Class 1 and Class 2 high consequence areas that have not had MAOP established through prior hydrostatic testing. These records should be traceable, verifiable, and complete. (P-10-2) (Urgent)

b. Use the traceable, verifiable, and complete records located by implementation of Safety Recommendation P-10-2 (Urgent) to determine the valid MAOP, based on the weakest section of the pipeline or component to ensure safe operation, of PG&E natural gas transmission lines in Class 3 and Class 4 locations and Class 1 and Class 2 HCAs that have not had MAOP established through prior hydrostatic testing. (P-10-3) (Urgent)

2. PG&E has stated that it is not able to provide specific records of every component in its natural gas transmission pipelines.

3. SoCalGas and SDG&E have stated that it is very difficult, if not infeasible, to locate records for all pipeline materials in the specified areas.

4. MAOP determined by component calculation is useful for prioritizing segments for interim pressure reductions and replacement or pressure testing, but MAOP determined in this manner is not reliable enough for permanent pipeline operations.

5. Natural gas transmission pipelines (operating at a pressure producing a hoop stress of 20% or more of SMYS) placed in service in California after July 1, 1961 were required to be pressure tested per General Order 112; however, pipelines installed before this date were exempted from pressure test requirements.

6. Natural gas transmission pipelines placed in service prior to 1970 were note required to be pressure tested, and were exempted from then-new federal regulations requiring such tests. These regulations allowed operators to operate a segment at the highest actual operating pressure of the segment during the five-year period between July 1, 1965 and June 30, 1970.

7. Natural gas transmission pipeline operators should be required to replace or pressure test all transmission pipeline that has not been so tested.

8. Technical workshops are needed to establish standards for determining whether pipeline segments should be replaced or tested, and the priority to be assigned to pipeline segments with different characteristics.

9. The unique circumstances of PG&E's pipeline records, the costs of replacing the San Bruno line, and the public interest require that PG&E's rate Implementation Plan include a cost sharing proposal.

1. PG&E should be required to complete its MAOP determination based on pipeline features and should be allowed to use engineering-based assumptions for pipeline components where complete records are not available. Such assumptions must be clearly identified, based on sound engineering principles, and, where ambiguities arise, the assumption allowing the greatest safety margin must be adopted. The calculated values should be used to prioritize segments for interim pressure reductions and subsequent pressure testing.

2. SoCalGas and SDG&E should complete their work in response to the NTSB's recommendations and the Commission's order.

3. A pressure test record must include all elements required by the regulations in effect when the test was conducted. For pressure tests conducted prior to the effective date of General Order 112, one hour is the minimum acceptable duration for a pressure test.

4. No later than August 26, 2011, all California natural gas transmission pipeline operators must file and serve a proposed Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plan.

5. The Implementation Plan should reflect a timeline for completion that is as soon as practicable and provide for 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 MAOP values which result in hoop stress levels at or above 30% of SMYS, and other such measures that will enhance public safety during the implementation period.

6. The Implementation Plan should set forth criteria on which pipeline segments were identified for replacement instead of pressure testing.

7. The Implementation Plan should include a rate proposal with the following:

a. For PG&E only, proposed cost allocation between shareholders and ratepayers;

b. Specific rate base and expense amounts for each year proposed to be included in regulated revenue requirement;

c. Proposed rate impacts for each year and each customer class; and,

d. Other such facts and demonstrations necessary to understand the comprehensive rate impact of the Implementation Plan.

8. The Implementation Plan should priority rank and schedule for pressure testing pipeline not previously so tested, and may provide for MAOP reductions to the lowest of the following: (1) a level no greater than 80% of the reliably recorded MOP from January 1, 2006 to January 1, 2011, (2) the lowest MOP of any HCA segment (defined per 49 CFR, Part 192) on a pipeline for the five-year period preceding the date of the identification of the HCA segment or the level to which the segment was lowered after September 9, 2010.

9. The Implementation Plan should also address retrofitting pipeline to allow for in-line inspection tools and, where appropriate, automated or remote controlled shut off valves.

10. Technical workshops should be convened prior to the natural gas transmission operators filing their Implementation Plans as set forth in the Ordering Paragraphs.

11. This order should be effective immediately so that the natural gas transmission system operators can expeditiously develop their Implementation Plans.

ORDER

Therefore, IT IS ORDERED that:

1. Pacific Gas and Electric Company must complete its Maximum Allowable Operating Pressure determination based on pipeline features and may use engineering-based assumptions for pipeline components where complete records are not available. Such assumptions must be clearly identified, based on sound engineering principles, and, where ambiguities arise, the assumption allowing the greatest safety margin must be adopted. The calculated values must be used for interim pressure reductions and to prioritize segments for subsequent pressure testing.

2. Southern California Gas Company and San Diego Gas & Electric Company must complete their work in response to the National Transportation Safety Board's recommendations and the Commission's Resolution L-410.

3. A pressure test record must include all elements required by the regulations in effect when the test was conducted. For pressure tests conducted prior to the effective date of General Order 112, one hour is the minimum acceptable duration for a pressure test.

4. No later than August 26, 2011, San Diego Gas & Electric Company, Southern California Gas Company, Southwest Gas Corporation and Pacific Gas and Electric Company must file and serve a proposed Natural Gas Transmission Pipeline Comprehensive Pressure Testing Implementation Plan (Implementation Plan) to comply with the requirement that all in-service natural gas transmission pipeline in California has been pressure tested in accord with 49 CFR 192.619, excluding subsection 49 CFR 192.619 (c). The Implementation Plan should start with pipeline segments located in Class 3 and Class 4 locations and Class 1 and Class 2 high consequence areas, with pipeline segments in other locations given lower priority for pressure testing. The schedule and cost detail for lower priority pipeline segments may be limited.

5. The Implementation Plan must reflect a timeline for completion that is as soon as practicable, and 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 values which result in hoop stress levels at or above 30% of Specified Minimum Yield Stress, and other such measures that will enhance public safety during the implementation period.

6. The Implementation Plan must set forth criteria on which pipeline segments were identified for replacement instead of pressure testing.

7. The Implementation Plan must contain a priority-ranked schedule for pressure testing pipeline not previously so tested, and may provide for Maximum Allowable Operating Pressure reductions to the lowest of the following: (1) a level no greater than 80% of the reliably recorded maximum operating pressure from January 1, 2006 to January 1, 2011, (2) the lowest Maximum Operating Pressure of any High Consequence Area segment (defined per 49 CFR, Part 192) on a pipeline for the five-year period preceding the date of the identification of the High Consequence Area segment or the level to which the segment was lowered after September 9, 2010.

8. The Implementation Plan must consider retrofitting pipeline to allow for in-line inspection tools and, where appropriate, improved shut off valves.

9. The Implementation Plan must include best available expense and capital cost projections for each Plan component and each year of the implementation period. Although not the determinative factor, improved safety effects for amount expended must be considered in prioritizing projects. Segments with the highest risk, however, must be tested or replaced first.

10. The Implementation Plan must also include a rate proposal with the following:

a. For Pacific Gas and Electric Company only, proposed cost allocation between shareholders and ratepayers;

b. Specific rate base and expense amounts for each year proposed to be included in regulated revenue requirement;

c. Proposed rate impacts for each year and each customer class; and

d. Other such facts and demonstrations necessary to understand the comprehensive rate impact of the Implementation Plan.

11. As soon as practicable after the effective date of this order, the Commission's Chief Administrative Law Judge shall designate a facilitator for technical workshops for California natural gas transmission pipeline operators and pipeline safety experts. The purpose of the workshops shall be to discuss and provide recommendations for California's natural gas transmission system operators on their Implementation Plans, including assisting in prioritizing segments for replacement or pressure testing. The workshops may survey best practices in other states for addressing natural gas pipeline that has not been pressure-tested, seek advice from industry experts or federal authorities, and take such actions as are necessary to inform itself as to the optimum means of addressing the technical issues in this proceeding. The workshops will consider this information in developing the best practices for use in California. Written reports may be prepared and circulated.

12. The Commission's Consumer Protection and Safety Division shall participate in the technical workshop and may submit periodic reports to Commission or otherwise bring forward any urgent issues.

13. Rulemaking 11-02-019 remains open.

This order is effective today.

Dated June 9, 2011, at San Francisco, California.

25 The first track of the proposal formed the basis for the procedural schedule adopted at the prehearing conference on June 2, 2011.

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