18. Assignment of Proceeding
Timothy Alan Simon is the assigned Commissioner and David Fukutome is the assigned ALJ in this proceeding.
1. DRA does not take issue with SCE's least-cost dispatch record in this proceeding.
2. 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.
3. 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.
4. DRA did not respond directly to SCE's criticisms of its monthly average price comparisons.
5. DRA and SCE can informally explore the development and use of supplemental information or techniques that may be valuable in evaluating future SCE ERRA Review filings.
6. In its testimony, DRA found that three nuclear forced outages were unreasonable. However, in its opening brief, DRA only recommended disallowances associated with the SONGS Unit 2 and Palo Verde Unit 3 outages.
7. 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.
8. For the June 5, 2008 SONGS Unit 2 forced outage, DRA does not provide an evaluation of the RCE in light of the "reasonable manager" standard. SCE does provide such evaluation.
9. There is no good evidence or reasoning as to why a reasonable manager should not have been aware of the potential for resin leak problem or the potential effect of the problem, prior to the September 27, 2008 Palo Verde Unit 3 forced outage.
10. While there is no way to know for sure whether or not prompt inspections would have prevented the Palo Verde Unit 3 outage, SCE's statement that it was "probably foreseeable and preventable" indicates that there is a good chance that would have been the case.
11. With respect to SCE's operation and maintenance of its hydro facilities, in its testimony, DRA found that two hydro forced outages were unreasonable. However, in its opening brief, DRA did not recommend disallowances associated with either outage.
12. With respect to SCE's coal generation resources, in its testimony DRA found that a Four Corners Unit 5 forced outage was unreasonable. However, in its opening brief, DRA did not recommend a disallowance associated with this outage.
13. DRA indicates that SCE reasonably operated its peakers.
14. DRA indicates that SCE reasonably operated its Catalina diesel operations.
15. DRA proposed a replacement power cost methodology and calculated the replacement power costs for its proposed outage disallowances.
16. SCE criticized DRA's proposed replacement power cost methodology, but did not provide any alternative data or calculations on which the Commission can rely in making replacement power cost adjustments.
17. DRA did not directly respond to SCE's criticisms of its replacement power cost methodology.
18. DRA recommends that the Commission grant SCE's request that its Non-QF contract administration activities, including that related to RPS contracts, be found reasonable.
19. DRA recommends that the Commission find SCE's management and administration of its PURPA contracts reasonable.
20. DRA found SCE's administration Non-QF contracts, including RPS contracts, during the Record Period to be reasonable.
21. DRA found SCE's administration QF contracts during the Record Period to be reasonable.
22. DRA has not challenged SCE's request that the Commission find all CAISO-related costs incurred during the Record Period to be reasonable.
23. DRA reviewed the Self Generation Deferral Rate Agreements with ExxonMobil and Tosco and does not take issue with either agreement.
24. With respect to the operation of ratemaking accounts, DRA reviewed all of the accounts and, in testimony, noted no exceptions, except for the DOELMA, NSGMA, MRTUMA, and PDDMA. In its opening brief, DRA indicates that, based on additional workpapers that SCE provided in rebuttal testimony, it now recommends that SCE be allowed to recover the full NSGMA amount.
25. There is logic to DRA's recommendation that capital project costs and associated expenses be reviewed together.
26. With respect to SCE's MRTUMA request, there is insufficient record evidence for the Commission to determine whether or not the requested costs were reasonably incurred.
27. As capital projects are completed, the capital related revenue requirements associated with those projects will be booked into the MRTUMA.
28. MRTU is the result of numerous CAISO stakeholder processes and FERC orders. There is no need for a single comprehensive proceeding to assess the reasonableness of MRTU or the associated requirements imposed on the IOUs.
29. While the IOUs' MRTU efforts are driven by common directives, tariff structures, and technical requirements, SCE's assertion that the manner in which each IOU approaches the requirements can be wholly different is not disputed by DRA.
30. SCE's PDDMA request of $3,834,930, excluding interest, is less than the maximum of $4,950,000 indicated in D.06-05-016.
31. Workpapers for SCE's testimony include a description of the various PDD costs for 2008. The descriptions generally are for identifying locations for new generation and evaluating generation technologies and appear consistent with the allowable functions identified in D.06-05-016.
32. The purpose of the PDDMA is to allow SCE cost recovery of appropriate supportive costs that are not associated with a specific project.
33. The Commission's intent in D.06-05-016 was that, regardless of whether or not SCE proposed or built a project, SCE should be given the opportunity to recover those supportive PDD costs that meet the requirements identified in the decision. Use of the PDDMA for all appropriate supportive PDD costs meets that intent.
34. SCE proposed, and the Commission determined, that disposition of the net amount in the DOELMA would be through an application, indicating one application and one review, and not a number of applications and reviews that are necessitated by SCE's current request that reflects only a portion of the costs and no proceeds.
35. Disposition of the net amount cannot occur until after the litigation has been completed and all costs and proceeds are known.
36. Whether or not DOELMA proceeds will be far exceed incremental costs cannot be determined until after the litigation has been completed and all costs and proceeds are known.
37. DRA's proposal for a consolidated proceeding for non-ERRA accounts is vague, and there is insufficient reason to disregard the current cost recovery mechanisms for each of the three IOUs and impose such consolidation and review.
1. All dispatch-related activities SCE performed during the Record Period complied with Commission orders and SCE's procurement plan.
2. SCE acted prudently in first filing trigger application, A.08-09-011, as required and then in withdrawing the trigger application when more recent information indicated that the threshold would not be exceeded.
3. If DRA continues to make use of monthly average purchase and sales price comparisons in future ERRA Review proceedings, it should explain why such comparisons are meaningful or relevant, in light of the criticisms made by SCE in this proceeding.
4. A rulemaking to address a preferred methodology for evaluating least-cost dispatch is unnecessary.
5. 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.
6. The evidence supports SCE's position that its actions, with respect to the June 5, 2008 SONGS Unit 2 forced outage, were reasonable.
7. Due to the potential repercussions of resin leaks, a reasonable course of action, even in the absence of the RCE for the Palo Verde Unit 3 outage, would have been for APS to inspect all similar valves as well as the resin traps for all three units as soon as possible after the incidents occurred.
8. The September 27, 2008 Palo Verde Unit 3 forced outage was not reasonable and ratepayers should not pay for the associated replacement power cost.
9. With the exception of the September 27, 2008 Palo Verde Unit 3 forced 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.
10. SCE's hydro facilities were operated reasonably during the Record Period.
11. Four Corners Units 4 and 5 were operated reasonably during the Record Period.
12. SCE's peakers were operated reasonably during the Record Period.
13. SCE's Catalina diesel operations were operated reasonably during the Record Period.
14. It is reasonable to use DRA's calculated amount of $615,000 for the Palo Verde Unit 1 outage replacement power cost, because there is no better quantification of the disallowance on the record.
15. All aspects of SCE's contract administration during the Record Period were reasonable.
16. RPS costs incurred during the Record Period are recoverable.
17. SCE's CAISO-related costs incurred during the Record Period were reasonably incurred.
18. SCE's administration of its two remaining Self Generation Deferral Rate agreements during the Record Period was reasonable.
19. The operation of and entries in the ERRA, BRRBA, NDAM, PPPAM, and CBA as presented by SCE in Exhibit 2 are appropriate, correctly stated, and in compliance with Commission decisions.
20. The amounts recorded in the ESMA and the LCTA are appropriate, correctly stated, consistent with Commission orders, and reasonably incurred.
21. The entries recorded in the RSMA are appropriate, correctly stated, and in compliance with prior Commission decisions.
22. The amounts recorded in the NSGMA totaling $26,051,000 are reasonable, correctly stated, in compliance with Commission decisions, and recoverable.
23. The recorded demand response program costs for the 2006 - 2008 program cycle, as shown in Exhibit 2, Table XII-34, are consistent with prior Commission decisions and reasonable.
24. The Phase II and Phase III costs recorded in the AMIBA and SmartConnect Balancing Account were properly recorded, consistent with the categories adopted in D.07-07-042 and D.08-09-039, and recoverable.
25. SCE should be granted authority to eliminate the AMIBA ratemaking mechanism from its tariffs.
26. It is reasonable to defer addressing the reasonableness of the $5.1 million in MRTU expenses requested by SCE and allow SCE to include that request and make an appropriate showing in its already filed ERRA Review application for the 2009 Record Period.
27. MRTU expenses should be recorded in FERC accounts.
28. With respect to DRA's recommendation that all expenditures associated with MRTU be submitted as required by the Commission in D.09-03-025, there is no need to make any changes to what SCE is currently doing and plans to do.
29. Based on the record evidence, DRA's request that there be a consolidated proceeding for MRTU costs should be denied. This does not preclude a different outcome with respect to consolidation, if requested in subsequent ERRA Review filings.
30. With respect to the PDDMA, SCE's showing is sufficient and meets its burden of proof obligations.
31. SCE should be allowed recovery of $3,910,000, including interest, in PDD costs for 2008.
32. SCE should request disposition of the DOELMA after all costs and proceeds are known.
33. DRA's request that there be a consolidated proceeding for review of non-ERRA accounts should be denied.
34. DRA recommendation that SCE's Audit Service Department +audit the ERRA balancing account at least once every three years is reasonable.
IT IS ORDERED that:
1. Southern California Edison Company shall appropriately reflect a $615,000 disallowance, associated with the September 17, 2008 Palo Verde Nuclear Generating Station Unit 3 forced outage, in its Energy Resource Recovery Account.
2. Southern California Edison Company is authorized rate recovery of $26,051,000 contained in the New System Generation Memorandum Account, $3,910,000 contained in the Project Development Division Memorandum Account, and $347,000 in associated franchise fees and uncollectibles.
3. Southern California Edison Company is granted authority to eliminate the Automated Meter Infrastructure Balancing Account ratemaking mechanism from its tariffs.
4. Southern California Edison Company may seek cost recovery of the $5,160,000 contained in the Market Redesign and Technology Upgrade Memorandum Account in its Energy Resource Recovery Account Review Application for the 2009 Record Period.
5. The Division of Ratepayer Advocates' request that there be a consolidated proceeding for Market Redesign and Technology Upgrade costs is denied.
6. Southern California Edison Company shall seek appropriate disposition of the Department of Energy Litigation Memorandum Account once all costs and proceeds are known. Such request can be made either through a future Energy Resource Recovery Account Review proceeding or separate application.
7. The Division of Ratepayer Advocates' request that there be a consolidated proceeding for review of non-Energy Resource Recovery Accounts is denied.
8. Southern California Edison Company's Audit Service Department shall audit the Energy Resource Recovery Account balancing account at least once every three years.
9. Application 09-04-002 is closed.
This order is effective today.
Dated July 29, 2010, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
TIMOTHY ALAN SIMON
NANCY E. RYAN
Commissioners
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 procurement17 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)
