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SoCalGas/SDG&E Natural Gas Pipeline Safety Enhancement Plan (A.11-11-002)

SoCalGas/SDG&E Natural Gas Pipeline Safety Enhancement Plan (A.11-11-002). Dave Peck Dao Phan Tom Roberts Kelly Lee Pearlie Sabino ALJ: Long Commissioner: Florio EMC Presentation July 18, 2012. Presentation Outline. Background Cost Recovery Policy

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SoCalGas/SDG&E Natural Gas Pipeline Safety Enhancement Plan (A.11-11-002)

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  1. SoCalGas/SDG&E Natural Gas Pipeline Safety Enhancement Plan(A.11-11-002) Dave Peck Dao Phan Tom Roberts Kelly Lee Pearlie Sabino ALJ: Long Commissioner: Florio EMC Presentation July 18, 2012

  2. Presentation Outline • Background • Cost Recovery Policy • Pipeline Safety Enhancement Plan Recommendations • Hydrostatic Pressure Test Cost Analysis • Valve Enhancement Plan Recommendations • Revenue Requirement Recommendations 2

  3. Procedural Timeline • September 9, 2010 - Pipeline explosion in San Bruno • February 24, 2011- CPUC opens R.11-02-019 rulemaking to set new rules for safe, reliable operation of state’s natural gas pipelines • June 9, 2011 - Decision 11-06-017 Ordering natural gas transmission operators to file plans to test or replace pipelines that have not been pressure tested or lack sufficient records of a test • August 26, 2011 - SoCalGas/SDG&E file Pipeline Safety Enhancement Plan (PSEP) • January 12, 2012 – CPSD issues Technical Report on SoCalGas/SDG&E PSEP • June 19, 2012 - DRA serves Testimony to SoCalGas/SDG&E PSEP

  4. SoCalGas/SDG&E System

  5. Commission Intent • The Commission has stated that the primary efforts of R.11-02-019 have been focused on ensuring that California is properly determining the Maximum Allowable Operating Pressure (MAOP) for each pipeline. • Decision 11-06-017 requires plans to either pressure test or replace all segments of natural gas pipelines that were not pressure tested or lacked sufficient details of any such test. Upon completion, all pipeline segments would be: (1) pressure tested, (2) have traceable, verifiable, and complete records, and (3) where warranted, be capable of accommodating in-line inspection devices. 5

  6. SoCalGas/SDG&E PSEP Lowlights • Phase 1A – 2012-2015; Pressure test about 360 miles of pipelines and replacing 246 miles of pipeline. • Install new technologies – fiber optic and methane detection. • The total cost estimate for Phase 1A and 1B is $2.5 billion over a 10-year period. Costs for Phase 1A alone is $1.7 Billion. 6

  7. DRA Cost Recover Policy Recommendation # 1 SoCalGas/SDG&E Shareholders should cover costs for hydrostatic testing or replacement of pipes installed in 1955 and later if a reliable record of a test can not be found. • ASA (American Standards Association) B31.1.8-1955 requirements (Requires hydrostatic testing of new pipe and recordkeeping associated with the testing for the useful life of the pipe) • This industry standard established requirements for pipe material, welding, and testing • SoCalGas/SDG&E helped develop ASA B31.1.8-1955 and state that they have always met or exceeded industry standards • NOTE: SoCalGas/SDG&E propose to absorb testing and replacement costs for any post-1970 pipes (“grandfathering” provision to establish MAOP based upon 5 years of operational data, 49 CFR §192.619(c)) 7

  8. DRA Cost Recover Policy Recommendation # 2 SoCalGas/SDG&E Shareholders should cover costs for hydrostatic testing of pipes installed between 1935 and 1955 if a reliable record of a test can not be found. • ASA issued the first national code for pressure piping in 1935 (B31). • The code represents the minimum safety requirements • Requires hydrostatic testing of pipes 8

  9. DRA Cost Recover Policy Recommendation # 3 • For any replacements of pipes installed between 1935 and 1955 where a reliable record of a test can not be found, the rate of return on equity (ROE) for those pipes should be adjusted down by 200 basis points. • Strikes an equitable balance between ratepayers and shareholders, • Recognizes that pipelines installed prior to 1955 and after 1935 should have been properly hydrostatically tested and records maintained, • Recognizes that pipelines installed prior to 1955 will be in excess of 60 years old by 2015, • Recognizes that 60 years is close to the average economic life used for depreciation purposes for pipelines, • Recognizes that transmission pipelines that are properly maintained can continue to operate safely well beyond the average economic life used for purposes of depreciation, • Gives consideration to the fact that any pre-1955 transmission pipelines which are replaced, will be replaced with a new transmission pipeline, • Strikes a fair balance given the acceleration of pipeline replacement that may occur pursuant to the Applicants’ Plan relative to the status quo. 9

  10. SoCalGas PSEP (Phase 1A) Base Case and Proposed Case 10

  11. SDG&E PSEP (Phase 1A) Base Case and Proposed Case 11

  12. SoCalGas/SDG&E PSEP Phase 1A Requests Phase 1A (2012-2015) • A total of $1.7 billion in O&M expenses and capital expenditures • The PSEP addresses the following pipelines: Transmission +Distribution+ Pipelines located in Class 3, 4 and 1, 2 HCAs+ Non-HCA pipelines located in rural areas) • The PSEP includes proposals above and beyond the Commission’s directives in D.11-06-017 • Replace 295 miles of SoCalGas and SDG&E pipelines • Pressure test 362 miles of SoCalGas and SDG&E pipelines • Perform in-line inspections and repairs on 721 miles of pipelines prior to conducting pressure tests 12

  13. DRA SoCalGas/SDG&E PSEP Recommendations • Address only Phase 1A (2012-2015) • Reject all items included in the Proposed Case and adopt the Base Case with modifications • Authorize $78.2 million in funding to pressure test 327 miles of transmission pipelines that have not been pressure tested • Reject Sempra’s request to replace pipelines in lieu of testing based on lack of support for criteria used 13

  14. DRA SoCalGas/SDG&E PSEP Recommendations (continued) • Reject SoCalGas/SDGE’ inclusion and acceleration of pipelines located in rural areas (class 1 and 2 non-HCAs) as part of Phase 1A • Reject SoCalGas/SDGE’ inclusion of distribution pipelines in the PSEP • Require SoCalGas/SDGE to consider the assessments of the Transmission Integrity Management Pipeline Program and pipeline locations in ranking pressure tests • Require SoCalGas/SDGE to reduce the PSEP costs for pressure tests used to comply with TIMP requirements. 14

  15. SoCalGas/SDG&E Proposed Hydro Costs $175 million for Phase 1A 15

  16. Variable Costs 90% based on volume of pipe segment and water required 16

  17. Water Supply Cost • SoCalGas/SDG&E assumes $.45 per gallon • DRA survey shows $.01 to $.02 typical • DRA calculations use $.045 per gallon 17

  18. Water Disposal Cost • SoCalGas/SDG&E requests $1.31 per gallon • DRA survey shows $.01 to $1.61 possible • DRA calculations use $.13 per gallon 18

  19. Other Adjustments to Variable Costs • Water storage tanks – SoCalGas/SDG&E estimate is 2-10 times too high • Water Trucks - SoCalGas/SDG&E estimate is nearly 7 times too high • Nitrogen purge – disallow since no justification 19

  20. Contingency Costs • SoCalGas/SDG&E provide no support for their proposed contingency rates • 20% for large projects (> $ 2 million) • 30% for small projects (< $ 2 million) • 21% average for all proposed hydrotest plan • DRA proposed 8% based on adopted AMI costs 20

  21. DRA Adjusted Hydrotest Project Costs • SoCalGas/SDG&E proposed $175 million • Remove low-priority “accelerated miles” – scope reduced by 50% • Use Sempra fixed and indirect costs • Use DRA’s variable costs - ($25 per barrel vs. $94 per barrel) • 8% contingency • DRA adjusted hydro cost - $34.7 million • DRA TOTAL cost - $78.1 million 21

  22. DRA Hydrotest Recommendations • SoCalGas/SDG&E should develop a water management plan to minimize costs • CPUC should work with Water Control Board to set reasonable and consistent disposal costs • Adopt unit cost caps, not aggregate costs • Adopt standards for drawing down contingency funds 22

  23. Valve Enhancement Plan • Technical Issues, Political Decision, Public Perception • SoCalGas/SDG&E’s forecasted expenditure for Phase 1A (2012 to 2015) is $149 million • Proposal is high level, cost estimates are highly uncertain, includes no engineering analysis and no cost/benefit analysis 23

  24. Valve Enhancement Plan (continued) DRA Recommendations: SoCalGas/SDG&E should to proceed with the valve upgrades at a more measured pace (at about 50% of the proposed rate) to gain experience in installation and operation, to assess the operational reliability of ASV/RCV, and to get a better handle on cost estimates. • Ratepayers to fully fund the tasks that will serve to improve and modernize the monitoring capability of the transmission system ($9.5 million in Phase 1A). • SoCalGas/SDG&E seek future ratepayer funding with supporting detailed cost/benefit analysis in GRC filings. • DRA recommends Phase 1A funding of $61 million instead of $149 million proposed by SoCalGas/SDG&E 24

  25. SoCalGas/SDG&E PSEP Direct Costs (Phase 1A) 25

  26. SoCalGas/SDG&E PSEP (Phase 1A) Revenue Requirement 26

  27. Comparison of PG&E and SoCalGas/SDG&E PSEP 27

  28. Next Steps • July 18, 2012 – SoCalGas/SDG&E Rebuttal Testimony • August 20-31, 2012 – Evidentiary Hearings • October 1, 2012 – Opening Briefs • October 19, 2012 – Reply Briefs 28

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