16. Assignment of Proceeding

Michel Peter Florio is the assigned Commissioner and David M. Gamson is the assigned ALJ in this proceeding.

1. On April 1, 2009, the CAISO began implementation of the Market Redesign and Technology Upgrade, which substantially changed the least-cost dispatch processes of SCE and other utilities.

2. DRA does not take issue with SCE's least-cost dispatch record in this proceeding.

3. SCE's methodology for forecasting its ERRA revenue requirement has been reviewed and approved by the Commission on an annual basis in SCE's ERRA Forecast proceedings.

4. To the extent that there are large variations in SCE's forecast of its ERRA revenue requirement, these are usually driven by factors beyond SCE's control, such as unexpected swings in the price of natural gas.

5. In its testimony, DRA found that three nuclear forced outages were unreasonable. However, in its opening brief, DRA only recommended disallowances associated with a SONGS Unit 2 outage.

6. RCEs are based on hindsight, using information and results available at the time the report was written - not just information that was available at the time of the incident.

7. For the December 28, 2008 SONGS Unit 2 outage which lasted approximately 18 days more than anticipated, DRA provides an evaluation of the RCE in light of the reasonable manager standard.

8. There is evidence that a reasonable manager should have been aware that the steel ball in the vent valve had been left on top of the valve stem for foreign material exclusion purposes, instead of in its final configuration position under the valve stem, or should have been aware of the potential effect of the problem, prior to the final approximately 48 hour extension of the December 28, 2008 SONGS Unit 2 outage.

9. With respect to SCE's operation and maintenance of its hydro facilities, in its testimony DRA recommends disallowances for forced outages at Big Creek 3 Unit 1 on December 14, 2008 and Mammoth Pool Unit 2 on June 11, 2008.

10. Evidence shows that it most likely was a failed switch which caused the December 14, 2008 fire and outage in Big Creek 3 Unit 1, given that considerable damage was found around the switch concurrent with the damage to the generator.

11. There is not sufficient evidence that SCE had information before the Big Creek 3 Unit 1 outage upon which a reasonable manager should have acted to prevent the outage, either with regard to corrosion in the insulation or to standing water in the cabinet at the time of the incident.

12. Two reports prepared by or for SCE show that the Mammoth Pool Unit 2 generator was run at temperatures significantly exceeding the recommended maximum for extended periods of time.

13. By running the Mammoth Pool Unit 2 generator at temperatures significantly exceeding the recommended maximum for extended periods of time, SCE reduced the expected life of the plant.

14. With respect to SCE's coal generation resources, in its testimony DRA found that three outages at Four Corners Units 4 and 5 were unreasonable. However, DRA withdrew its recommendations for disallowances except for a forced outage at Four Corners Unit 4 on January 17, 2009.

15. There is no evidence that a reasonable manager should have taken any specific steps that would have prevented the forced outage at Four Corners Unit 4 on January 17, 2009.

16. DRA indicates that SCE reasonably operated all of its other fuel and generation activities.

17. DRA proposed a replacement power cost methodology and calculated the replacement power costs for its proposed outage disallowances.

18. SCE has shown that DRA's proposed replacement power cost methodology for the SONGS Unit 2 outage and the Mammoth Pool Unit 2 outage was incorrect.

19. SCE's proposed disallowance level for the SONGS Unit 2 outage of December 28, 2008 is reasonable.

20. DRA's modified proposal for a disallowance for the Mammoth Pool outage is reasonable.

21. DRA has no objection to SCE's Non-QF contract administration activities, including those related to RPS contracts.

22. DRA has no objection to SCE's management and administration of its PURPA contracts.

23. DRA has no objection to SCE's administration of contracts during the Record Period.

24. DRA has not challenged SCE's request that the Commission find all CAISO-related costs incurred during the Record Period to be reasonable.

25. DRA has not challenged SCE's administration of its Self Generation Deferral Rate Agreements with ExxonMobil and Tosco during the Record Period.

26. D.10-07-049 did not adopt DRA's recommendation that SCE, PG&E, and SDG&E should not submit non-ERRA balancing and memorandum accounts in any ERRA proceeding, but that instead, these non-ERRA accounts should be combined together and submitted in a separate reasonableness review proceeding.

27. With respect to the operation of ratemaking accounts, DRA reviewed all of the accounts and, in testimony, noted exceptions only for the DOELMA and MRTUMA.

28. With respect to SCE's MRTUMA request, there is sufficient record evidence for the Commission to provisionally determine whether or not the requested costs were incremental and reasonably incurred. However, there is a need for a Commission audit to verify SCE's request.

29. With respect to the DOELMA, SCE withdrew its request.

30. As capital projects are completed, the capital related revenue requirements associated with those projects will be booked into the MRTUMA.

31. MRTU is the result of numerous CAISO stakeholder processes and FERC orders. A Ruling on June 23, 2011 determined that for the 2009 Record Period there is no need for a single comprehensive proceeding to assess the reasonableness of MRTU or the associated requirements imposed on the IOUs.

32. SCE's PDDMA request of $3,907,000 excluding interest, is less than the maximum of $4,950,000 indicated in D.06-05-016.

33. DRA and SCE agreed to defer reasonableness review of SCE's Mohave Balancing Account to SCE's 2010 ERRA Compliance and Reasonableness Review proceeding.

1. All dispatch-related activities SCE performed during the Record Period complied with Commission orders and SCE's procurement plan.

2. RCEs must be evaluated in conjunction with the "reasonable manager" standard in determining whether a nuclear outage is reasonable or unreasonable for the purposes of this proceeding.

3. The evidence supports DRA's position that SCE's actions, with respect to the 18 day extension of the December 28, 2008 SONGS Unit 2 planned outage, were not reasonable.

4. With the exception of the December 28, 2008 SONGS Unit 2 outage, the generation, nuclear fuel expenses, and fuel material and services that SCE purchased for both SONGS and Palo Verde during the Record Period were reasonable.

5. The evidence supports SCE's position that its actions, with respect to the December 14, 2008 Big Creek 2 forced outage, were reasonable.

6. The evidence supports DRA's position that SCE's actions, with respect to the June 11, 2008 Mammoth Pool Unit 2 forced outage, were not reasonable.

7. Aside from the June 11, 2008 Mammoth Pool Unit 2 forced outage, SCE's hydro facilities were operated reasonably during the Record Period.

8. Four Corners Units 4 and 5 were operated reasonably during the Record Period.

9. All other of SCE's fuel and generation operations were operated reasonably during the Record Period.

10. It is reasonable to use SCE's calculated amount of $1,442,200 for the SONGS Unit 2 outage replacement power cost.

11. It is reasonable to use DRA's modified calculated amount of $979,350 for the Mammoth Unit 2 outage replacement power cost.

12. All aspects of SCE's contract administration during the Record Period were reasonable.

13. SCE's administration of its SGDR agreements during the Record Period was reasonable.

14. RPS costs incurred during the Record Period are recoverable.

15. SCE's CAISO-related costs incurred during the Record Period were reasonably incurred.

16. SCE's administration of its two remaining Self Generation Deferral Rate agreements during the Record Period was reasonable.

17. The operation of and entries in the ERRA, BRRBA, NDAM, PPPAM, NSGBA and CBA as presented by SCE in Exhibit SCE-2 are appropriate, correctly stated, and in compliance with Commission decisions.

18. The amounts recorded in the ESMA and the LCTA are appropriate, correctly stated, consistent with Commission orders, and reasonably incurred.

19. The entries recorded in the RSMA are appropriate, correctly stated, and in compliance with prior Commission decisions.

20. The Phase III costs recorded in the SmartConnect Balancing Account were properly recorded, consistent with the categories adopted in D.08-09-039, and recoverable.

21. SCE's MRTU expenses and associated revenue requirement for 2007 through 2009 are incremental to its general rate case expenses.

22. It is necessary for there to be an audit to ensure that SCE's MRTU expenses and associated revenue requirement for 2007 through 2009 are appropriate, correctly stated, consistent with Commission orders, and reasonably incurred.

23. With respect to the PDDMA, SCE's showing is sufficient and meets its burden of proof obligations.

24. SCE should be allowed recovery of $3,912,000 including interest, in PDD costs for 2009.

25. SCE should request disposition of the DOELMA after all costs and proceeds are known.

26. Reasonableness review of SCE's Mohave Balancing Account should be deferred to SCE's 2010 ERRA Compliance and Reasonableness Review proceeding.

ORDER

IT IS ORDERED that:

1. Southern California Edison Company shall appropriately reflect a $1,442,200 disallowance associated with the December 28, 2008 San Onofre Nuclear Generating Station Unit 2 outage, in its Energy Resource Recovery Account.

2. Southern California Edison Company shall appropriately reflect a $979,350 disallowance, associated with the June 11, 2008 Mammoth Pool Unit 2 forced outage, in its Energy Resource Recovery Account.

3. Southern California Edison Company is authorized rate recovery of $19.409 million for the Energy Settlement Memorandum Account and Litigation Costs Tracking Account, $3.912 million for the Project Development Division Memorandum Account, and $343,000 in franchise fees and uncollectibles.

4. Southern California Edison Company shall transfer the $2,865,000 balance of the Solar Photovoltaic Program Memorandum Account to its Solar Photovoltaic Program Balancing Account, and shall eliminate the Solar Photovoltaic Program Memorandum Account.

5. Southern California Edison Company (SCE) is authorized to recover the expenses and capital costs recorded in its Market Redesign and Technology Upgrade Memorandum Account (MRTUMA) for 2007 through 2009, subject to refund based upon a Commission audit, to be completed within 12 months of the effective date of this decision. The audit must include, but not be limited to, the following items:

1. Compliance with requirements of the Resolution in which the MRTUMA was authorized (Resolution E-4087);

2. Verification that amounts recorded in the MRTUMA since inception have been spent on the incremental costs of the MRTU program;

3. Verification that amounts recorded in the MRTUMA since inception are incremental to the amounts otherwise authorized by this Commission for SCE's Information Technology program;

4. Verification that amounts recorded in the MRTUMA since inception have not been spent on non-MRTU Information Technology programs; and

5. Verification that amounts recorded in the MRTUMA are separately identified in SCE's accounting system.

6. The audit referenced in Ordering Paragraph 5 of this decision shall be filed and served in the then-current proceeding considering Southern California Edison Company's Market Redesign Technology Upgrade expenses and capital costs.

7. Application 10-04-002 is closed.

This order is effective today.

Dated October 6, 2011, at Los Angeles, California.

APPENDIX

The Commission Process for Review and Approval of the Forecast ERRA Revenue Requirement and the Recorded Procurement Costs

The Commission has established the following processes for review and approval of a utility's forecasted fuel and purchased power expenses for the purpose of setting rates:

· ERRA Forecast Proceeding: The utility submits a forecast of its procurement expenses for the following year to the Commission for review and approval. The utility's forecast is based on its best estimate of such factors as its projected sales and load, natural gas and power prices, etc., during the forecast year. The adopted forecast value is used to establish procurement related rates, but it does not determine which procurement-related costs are eligible for cost recovery. Actual fuel and purchased power costs must be reviewed by the Commission and found eligible for cost recovery.

· ERRA Trigger Mechanism: ERRA Trigger applications are a Commission-mandated vehicle to ensure that utility ERRA balancing account balances (i.e., the differences between revenues and actual costs incurred - or over- and under-collections) do not reach excessive levels. In a trigger application, the utility requests Commission approval either to increase or decrease rates in order to reduce a large difference in the balancing account between revenues and recorded costs. This "trigger" application is to include a projected account balance 60 days or more from the date of filing, depending upon when the balance will reach the Commission established five percent threshold. The trigger application is to propose an amortization period of not less than 90 days to ensure timely recovery (or refund) of the projected ERRA balance.

The Commission does not review or approve the utilities' actual recorded procurement costs as part of the ERRA Forecast or ERRA Trigger proceedings, because in these proceedings costs are forecasted and, as such, have yet to be incurred by the utilities.

The Commission has established the following processes for the review and approval of recorded utility procurement costs:

· Long-Term Procurement Plan Proceeding: Approximately every two years (subject to change by Commission order), the utility submits a procurement plan to the Commission for its review and approval. The Commission-approved procurement plan establishes the "upfront" standards and criteria that will guide the utility's procurement activities. The utility must execute its transactions in compliance with these approved procurement plan standards and criteria to gain a finding that its procurement-related expenses are eligible for cost recovery, or subject the transactions to traditional after-the-fact reasonableness review. If any transaction does not fit within the Commission-approved procurement authority and the procurement plan standards, the utility must seek the Commission's pre-approval via a separate application.

· Quarterly Compliance Report (QCR) Advice Letter Filings: For each quarter of the year, the utility submits a QCR advice letter detailing all transactions that it executed during the quarter. The Commission's audit team reviews these transactions to determine if they were in compliance with the utility's procurement plan, and forwards its recommendations to the Energy Division for approval. If the Energy Division approves the QCR, the utility's transactions are deemed to be in compliance with the utility's Commission-approved procurement plan and the related procurement costs are deemed recoverable through the ERRA balancing account. On the other hand, if the audit team finds any transaction to be non-compliant with the utility's procurement plan, the utility would need to justify that transaction's reasonableness via a separate application.

· ERRA Review Proceeding: In the ERRA Review proceeding, the Commission conducts the following reviews: (1) a compliance review to determine if the utility's daily energy dispatch decisions and related short-term procurement activities (i.e., daily and hourly spot market transactions) were consistent with the least cost dispatch principles set forth in Standard of Conduct No. 4; (2) an accounting review to determine if the utility accurately recorded the procurement expenses that are eligible to be recovered through the ERRA balancing account; and (3) a reasonableness review to determine if the utility reasonably administered its QF and non-QF contracts, and if the operation of its utility-retained generation units, including maintenance outages, was reasonable.

In the ERRA Review proceeding, the Commission also reviews entries recorded in the ERRA balancing account to ensure that such entries are accurate and consistent with Commission decisions. The recorded year-end ERRA balancing account over- or under-collection (i.e. "true-up") is included in the following forecast year's rate change.

(END OF APPENDIX)

Previous PageTop Of PageGo To First Page