IX. Assignment of Proceeding
Loretta M. Lynch is the Assigned Commissioner and Christine M. Walwyn is the assigned Administrative Law Judge in this proceeding.
1. Both the Commission and the legislature have clearly expressed their intent to return the respondent utilities to full procurement on January 1, 2003, consistent with the utilities' statutory obligation to serve their customers and the provisions of Assembly Bill ABX1 X.
2. Our approval of the updated procurement plans, as modified by each utility's adopted confidential appendix, puts in place the upfront standards and practices under which each utility shall conduct its procurement. Any adjustments or revisions that are requested by the utilities or other parties will be considered only on a prospective basis.
3. We have identified and addressed conflicts between the DWR/utility servicing agreements and operating agreements in the confidential appendices.
4. The confidential appendices list the specific modifications this decision adopts to the November procurement plans filed by the utilities.
5. The Commission realizes that the transparent competitive market may not be robust but we do expect the up-front standard for bilateral contracts to be met by a strong showing. This could be met, for example, by comparison to Requests for Proposals completed within one month of the transaction.
6. We encourage the utilities to pursue the option of inter-utility exchanges. If the utilities find our adopted cost effectiveness standard has problems in today's market environment, they should confer with their procurement review group and propose an alternative.
7. Utility procurement of early 2004 needs should not await a final Commission decision on long-term procurement plans, although we recognize that a final decision on such plans is scheduled for November 2003.
8. PG&E's, Edison's, and SDG&E's forecast of their loads and resources assumptions underlying the forecast residual net short in their procurement plans are reasonable.
9. The utilities should pursue development of new direct access scenarios once it is known with more certainty how community aggregation will be implemented as well as possible impacts from municipalization and incremental direct access loads.
10. While recognizing that Edison proposes maximum volume limits on transactions that it may not in fact utilize, it is not prudent at this time to pre-approve these ceilings. We are particularly concerned that Edison could over-hedge its position for a five-year period.
11. It is reasonable to adopt the recommendation that Edison establish its monthly forward energy limit based on its reference case RNS-Reference Dispatch Scenario, with certain modifications that are specified in confidential Appendix B.
12. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit Edison's gas volumes, forward energy and forward capacity amounts at this time.
13. We find PG&E's volumetric guidelines presented in Appendices B and C of its short-term plan are reasonable.
14. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit forward purchases for PG&E at this time.
15. We find SDG&E's volumetric limits to be reasonable.
16. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit forward purchases for SDG&E at this time.
17. We note that SDG&E's reply comments make the erroneous assumption that ORA's recommendation to limit spot market transactions to 4% of the hourly average RNS is comparable to the calculation underlying the Commission's guideline in D.02-10-062 that utilities should plan to minimize their spot market exposure to 5% of monthly needs.
18. Edison did not comply with the Commission's directive in D.02-10-062 to present a consumer risk tolerance level.
19. In setting a consumer risk tolerance level, we find ORA's proposed trigger mechanism, when used in conjunction with TURN's proposal to be reasonable and, therefore, should adopt these two mechanisms for each utility for their short-term procurement plans.
20. The utilities should move in the direction of analyzing portfolio risk based on a probability distribution of risk drivers.
21. PG&E should make specific portfolio risk scenario changes as detailed in confidential Appendix A.
22. We cannot state with certainty the exact amount of new renewable procurement SDG&E has executed, only that we will make this determination next year, once the CEC has developed its certification process in accordance with SB 1078.
23. Pursuant to SB 1078, the Commission and CEC will collaborate on a number of key Renewable Portfolio Standard implementation points, many of which were identified for party briefs in D.02-10-062. The specific parameters of this arrangement will be provided for party comment in a workplan filed on February 3, 2003 for comment by February 10, 2003. A portion of the prehearing conference scheduled for February 17, 2003 in D.02-10-062 will be set aside for discussion of the workplan.
24. Under our inter-agency approach with the CEC regarding implementation of the Renewable Portfolio Standard, the CEC will designate specific staff members to be RPS Implementation Collaborative Staff, who along with Commission staff will facilitate the further scoping of RPS issues, management of workshops and hearings, and the production of staff working papers and workshop/hearing reports. CEC RPS Implementation Collaborative Staff will assist decision makers in both agencies. We will designate a legal framework to allow other members of CEC staff to continue to participate as parties in the Procurement rulemaking on non-RPS issues. The specific parameters of this arrangement will be provided for party comment in the workplan.
25. The CEC has agreed that a similar, reciprocal arrangement will be established for Commission staff in the CEC's rulemaking addressing renewable generation issues.
26. Issues related to the definition of demand response as either supply, or demand response tariffs as less reliable (currently) than supply but valuable as additions to utility load forecasts, are currently under consideration in Rulemaking R.02-06-001 and, therefore, it is inappropriate at this time to integrate ORA's comments on demand response into this decision.
27. Without an adequate definition of demand response initiatives, and pending a clarification of this issue in R.02-06-001, we find that we cannot at this time require the utilities to make the requested distinction in their short-term procurement plans.
28. The 7% operating reserves proposed by the utilities in their plans are adequate for 2003. We have concerns regarding other reserve levels of Edison, and should modify its authorized limits in confidential Appendix B.
29. ORA's request that each utility in the long-term planning phase provide data sufficient to determine what level of planning reserves would lead to a loss of load probability of one day in ten years, as well as supporting testimony recommending a level of planning reserves, is reasonable.
30. The Commission should develop a further understanding of the interaction between PG&E's Transition Revenue Account (TRA) and Energy Resource Recovery Account (ERRA) accounts.
31. There are several PG&E advice letters that are related to the TRA mechanism still pending before the Commission.
32. In recognition of the somewhat unique posture of PG&E as a bankrupt utility, it is reasonable for the Commission to undertake certain actions to address its concerns about undercollections exceeding the 5% threshold.
33. It is reasonable to explore PG&E's concept of transferring overcollection in a balancing account to offset undercollection in another balancing account.
34. The Commission intends to look closely at PG&E's accounting approach and also whether refunds to ratepayers should be implemented in the same way.
35. Because of our modification to D.01-03-082, PG&E does not need to track ongoing power costs first with the 1-cent surcharge revenues in the Emergency Procurement Balancing Account (EPBA). Such revenues should be included in the TRA.
36. PG&E currently records the 3 cents surcharge revenues in the TRA as part of the billed revenues because Advice Letter 2096-E is still pending before the Commission for approval.
37. PG&E should treat the 1-cent surcharge revenues in the same manner as the 3 cents surcharge revenues, they both should be included in the billed revenues in the TRA.
38. PG&E should reduce the total billed revenues including surcharge revenues by revenues collected for DWR to arrive at the residual electric retail revenue available for all authorized costs as required by D.02-02-052 (Ordering Paragraph 9), "to segregate DWR related billed revenues from Utility Retained Generation (URG) related billed revenues."
39. PG&E's Emergency Procurement Surcharge Balancing Account (EPSBA) should be changed to a memorandum account to track both the 1-cent and 3 cents surcharge revenues included in the TRA billed revenues in a separate sub-account since these are subject to refunds.
40. Ongoing transition costs associated with Qualifying Facilities (QF) and Purchased Power Agreements (PPA) contracts should be recorded in a Modified Transition Cost Balancing Account (MTCBA) for later recovery from all customers, not in the ERRA balancing account.
41. We agree with PG&E's method of calculating ongoing Competitive Transition Costs (CTC) associated with QF and PPA contracts, but we also note that these issues will be more fully addressed in A.0-11-038 et. al. (D.02-11-026).
42. After the transitional procurement period, when the Commission rejects a proposed contract as part of the procurement pre-approval process, it will designate an alternative transaction.
43. Edison's proposal to file monthly reports on its hedging position is reasonable.
44. To provide certainty to the utilities and the investment community, it is reasonable to adopt a maximum amount of potential disallowance to the utility for violation of standard of behavior #4 in D.02-10-062 based on their annual administrative expenditures associated with all procurement activities.
1. Vulcan Power's October 15, 2002 motion to intervene is granted.
2. IEP's November 26, 2002 motion is denied.
3. CAC's December 13, 2002 motion to receive comments and PG&E's December 13, 2002 motion for late-filed reply comments are granted.
4. With the incorporation of the additions, deletions, and modifications set forth in each confidential appendix into the November 2002 filed procurement plans, we adopt a revised updated procurement plan for each utility that meets the statutory requirements of Senate Bill 1976 and all other provisions of the California Public Utilities Code.
5. The legal interpretation of AB 57/SB 1976 is found in the Commission's decisions and the procurement plans must be in compliance with that interpretation.
6. Nothing in the approved procurement plans should be contrary to the procedures adopted in the DWR/utility servicing agreements and operating agreements and the underlying decisions adopting those agreements. To the extent any material in the procurement plans filed by the respondent utilities is contrary to the referenced agreements and decisions, those sections are not approved here.
7. Prospective community aggregation program aggregators must register with the Commission prior to implementing aggregation.
8. We should adopt a modification of TURN's 50% recommendation for Edison to address five-year contract limits.
9. We should adopt PG&E's proposal to revise its language regarding the reasonableness of ISO and bilateral transactions executed while a revised plan is pending approval.
10. We should adopt TURN's comments concerning the procurement selection process as reflected on page C-3 of PG&E's plan. We should direct PG&E to confer with its procurement review group to elaborate on how it will select among different procurement products to hedge in 2003.
11. Our directive in D.02-10-062 that utilities procure 1% of their 2001 sales figures including DWR power in the form of new renewable generation should be incremental above the existing stock of renewable generation in a utility's portfolio - i.e. above the level of renewable generation the utility sells in 2002.
12. We should make a preliminary finding here that PG&E and SDG&E have met the transitional procurement requirement of D.02-08-053 for renewable resources but rely on the California Energy Commission analysis of whether production from an existing renewable facility qualifies as an incremental addition for a final determination.
13. None of the utilities' plans are sufficiently robust to meet the standard of procurement pre-approval under SB 1976/AB 57. However, we should not foreclose the option of further renewable procurement by the utilities in 2003, subject to the defined contract filing and approval process.
14. We provisionally certify that SDG&E has met its procurement requirement under D.02-08-071, and hold that additional renewable procurement above the 1 percent incremental requirement will be eligible for satisfaction of procurement requirements under the Renewable Portfolio Standard.
15. If SDG&E or PG&E is shown to not have met its 1 percent incremental procurement target, further procurement may be ordered under the authority of Public Utilities Code Section 701.3.
16. We provisionally certify that PG&E has met its 1 percent interim renewable procurement mandate, pending its filing of 2001 sales figures and final certification by the CEC of incremental output from existing resources per SB 1078.
17. Edison is in noncompliance with D.02-08-071's directive on renewable resource procurement and the Commission should address this noncompliance in a subsequent order.
18. We should not grant CBEA's request to grant contracts to the four biomass plants not offered contracts by the utilities.
19. We should decline at this time to order the utilities to make public more detail regarding their procurement plans.
20. We should deny TURN's request that PG&E be required to use actual incurred costs rather than a revenue requirement to track ERRA under and over collections.
21. Nothing in AB57/SB1976 requires this Commission to cede its ratemaking authority to PG&E by allowing for automatically effective rate increases (whether subject to refund or not).
22. The Commission retains the authority that Pub. Util. Code § 454.5 grants us in determining how to amortize undercollections.
23. We should authorize PG&E to file an expedited trigger application at any time that its forecasts indicate it will face an undercollection in excess of the 5% threshold.
24. Pending completion of further review of PG&E's ERRA account, the Commission should commit to act as rapidly as necessary on rate change requests, consonant with Pub. Util. Code § 454.5's requirement that "(t)he Commission shall...adjust rates or order refunds as necessary, to promptly amortize a balancing account, according to a schedule determined by the Commission."
25. We should accelerate our review of PG&E's ERRA account, advancing the review by four months to commence in February rather than in June.
26. We clarify our previous order on ERRA accounting for SDG&E and Edison. SDG&E should use its generation rate revenues for ERRA instead of the authorized revenue requirements as provided for in its ERRA tariff. We should authorize Edison to implement the ERRA mechanism by tracking of actual incurred ERRA costs against fuel and purchase power revenue requirements without a true-up since it will transfer actual costs recorded in the ERRA to the Settlement Rates Balancing Account (SRBA) in order to determine the amount of Surplus to apply to the Procurement-Related Obligation Account (PROACT).
27. We should tentatively adopt PG&E's calculation of the $2.035 billion as the ERRA revenue requirement for 2003 to be recorded in the account against recorded ERRA costs until parties have the opportunity to review the derivation of the negative $3 million in detail in PG&E's February 1st filing.
28. We should deny PG&E's request to transfer one twelfth of this amount from the TRA to the ERRA. Instead, PG&E should debit the equivalent amount credited monthly to the ERRA to the TRA in order to align authorized revenues with actual revenues collected from customers in the TRA.
29. In view of the changes to D.01-03-082 by D.02-11-026, the tariff changes proposed by PG&E in Advice Letter 2096-E are moot and the advice letter should be withdrawn.
30. Consistent with D.02-09-053, Electric Energy Transaction Administration (EETA) costs should be recovered through base rates in the general rate case proceedings. SDG&E and Edison should modify their ERRA tariffs to exclude costs associated with ETTA. Since SDG&E's cost of service application is in the future, SDG&E should track these costs in a memorandum account for later recovery.
31. We should set a maximum risk of potential disallowance for each utility at twice their annual expenditures on all procurement activities, as established in their general rate cases.
32. We should not approve the portions of the utilities' procurement plans that change standard of behavior #4's requirement, as adopted in D.02-10-062, either through changing our existing standards or by shifting the burden of proof.
33. Pursuant to Rule 77.7(f)(9), we find that public necessity requires the waiver of the 30-day period for public review and comment on this draft decision because failure of the Commission to act by December 19, 2002 could endanger the public's health and welfare, and this clearly outweighs the public interest in allowing a comment-and-review period.
34. Pursuant to Rule 81(f) and (g), we determine that an unforeseen emergency situation requires waiver of the 30-day period for public review and comment on alternate pages.
IT IS ORDERED that:
1. PG&E's updated procurement plan is modified to reflect the changes contained in confidential Appendix A. Edison's updated procurement plan is modified to reflect the changes contained in confidential Appendix B. SDG&E's updated procurement plan is modified to reflect the changes contained in confidential Appendix C.
2. The confidential appendices are filed under seal and are subject to the May 1, 2002 protective order governing access to and the use of all protected materials in this proceeding. The utilities are not authorized access to each others' appendices. Each respondent utility should obtain a copy of its individual appendix from Interim Chief Administrative Law Judge Carol Brown, or her designee, and is responsible for providing copies to all individuals authorized to receive this material within 5 days. The attorneys for ORA and TURN may obtain copies of all appendices directly from ALJ Brown or her designee.
3. PG&E, Edison, and SDG&E are directed to begin transacting immediately, in accordance with the modified procurement plans adopted herein, for procurement needs in January 2003.
4. To address the new proposals and material that is not in compliance with D.02-10-024, we adopt a confidential appendix for each utility that sets forth the manner in which its November updated procurement plan is modified.
5. Each respondent utility is authorized to hedge 2004 first quarter residual net short/long positions with transactions entered into in 2003. Each utility shall consult with its respective Procurement Review Group in the development of a hedging strategy for 2004 first quarter needs.
6. In order that the short-term procurement plans accurately reflect the final disposition of transitional contracts approved by the Commission under the procurement authority granted in D.02-08-071, PG&E and Edison shall update their plans within 18 calendar days of the effective date of this decision.
7. PG&E shall file by advice letter an addendum to its plan providing clarification on how it will select among different procurement products to hedge in 2003 at the same time it submits updated tables reflecting executed transitional contracts.
8. Energy Division shall schedule a workshop in February 2003 that will assist the Commission in gathering information on Value at Risk and Cash-Flow at Risk models and to discuss a broader range of measures of portfolio risk exposure.
9. SDG&E shall meet with its PRG and ORA to discuss further what magnitude is appropriate for a benefit/cost ratio and how it should be calculated.
10. The utilities shall present Black Model results, for informational purposes, as part of their quarterly advice letter filings as well as for contracts submitted for pre-approval.
11. At the trigger threshold level set in the confidential appendices, each utility shall confer with its procurement review group to discuss the need to file a plan update.
12. Each utility shall submit by January 2, 2003 by compliance filing its 2001 sales figures including Department of Water Resources power.
13. If the 2002 renewable generation baseline amount shrinks in 2003 for a respondent utility, it shall procure sufficient renewable power over and above this 1% of total 2001 retail sales amount, to result in a total 2003 renewable generation portfolio at least equal to the following: 2002 renewable procurement plus 1% of 2001 retail sales. We direct the utilities to reaffirm their incremental results immediately.
14. For the long-term planning phase, each utility shall provide ORA data sufficient to determine what level of planning reserves would lead to a loss of load probability of one day in ten years.
15. PG&E shall use the same method as used by Edison in calculating when the threshold has been triggered for the ERRA Balancing Account.
16. PG&E shall file both its forecast application and the ERRA balancing account review application on February 1 and August 1, 2003, respectively.
17. SDG&E shall file similar applications on June 1 and December 1, 2003.
18. PG&E shall include its proposal for applying the overcollection of TRA to the ERRA account in the February filing.
19. PG&E, SDG&E, and Edison shall file with the Energy Division each month a report showing the activity in the ERRA balancing account with copies of original source documents supporting each entry over $100.00 recorded in the account. This report shall be filed not later than the 20th day following the end of the month. The report itself, but not the underlying documents, shall be served on all interested parties in this proceeding.
20. We deny PG&E's rate adjustment requests and TRA overcollection transfer to the ERRA at this time without prejudice.
21. PG&E shall revise its ERRA and TRA to conform to this order.
22. PG&E shall revise the language in its TRA tariff when it files its compliance ERRA tariff to implement changes being made to the ERRA mechanism five days after the effective date of this decision to read that: "The TRA will be in effect until the Commission determines the date when the rate freeze should have ended."
23. PG&E shall amend other advice letters related to AL 2096-E within five days after the approval of this decision.
24. PG&E's November 20, 2002 Petition to Modify Decision (D.) 02-10-062 is granted in part to provide:
a. Electrical Energy Transaction Administration (EETA) cost shall be established and approved in PG&E's general rate case; and
b. The standards of behavior 2, 4, and 6 in Section XI are clarified and modified as follows:
"2. Each utility must adopt, actively monitor, and enforce compliance with a comprehensive code of conduct for all employees engaged in the procurement process that: 1) identifies trade secrets and other confidential information; 2) specifies procedures for ensuring that such information retains its trade secret and/or confidential status [e.g., limiting access to such information to individuals with a need to know, limiting locations at which such information may be accessed, etc.]; 3) discusses employee actions that may inadvertently waive or jeopardize trade secret and other privileges; 4) discusses employee or former employee activities that may involve misappropriation of trade secrets or other confidential information, unlawful solicitation of former clients or customers of the utility, or otherwise constitute unlawful conduct; 5) requires or encourages negotiation of covenants not to compete to the extent such covenants are lawful under the circumstances [e.g., where a business acquires business interests of individuals who subsequently work for the acquiring business, the individuals disposing of their business interests may enter covenants not to compete with their new employer.] All employees with knowledge of its procurement strategies should be required to sign and abide by an agreement to comply with the comprehensive code of conduct and to refrain from disclosing, misappropriating, or utilizing the utility's trade secrets and other confidential information during or subsequent to their employment by the utility."
For standard #4, to provide specific guidance in the procurement plans, we add the following language:
"Prudent contract administration includes administration of all contracts within the terms and conditions of those contracts, to include dispatching dispatchable contracts when it is most economical to do so. In administering contracts, the utilities have the responsibility to dispose of economic long power and to purchase economic short power in a manner that minimizes ratepayer costs. Least-cost dispatch refers to a situation in which the most cost-effective mix of total resources is used, thereby minimizing the cost of delivering electric services. PG&E's description of least-cost economic dispatch methodology described in its 1992 "Resource: An encyclopedia of energy utility terms," 2d edition, at pages 152-3 is appropriate with the recognition that a pure economic dispatch of resources may need to be constrained to satisfy operational, physical, legal, regulatory, environmental, and safety considerations. The utility bears the burden of proving compliance with the standard set forth in its plan."
For standard #6, as an interim measure for the 2003 short-term procurement plans only, we lift the standard for transactions of less than one year and for those 12 months to 60 months, we substitute the following standard #6:
"For all contracts with terms between 12 and 60 months, all contracts must contain the following revision: "In the event of statutory or federal regulatory changes, this contract shall be subject to such changes or modifications as the CPUC may direct."
25. We set an annual maximum potential disallowance for violation of standard #4 at twice each utility's annual expenditures on all procurement activities. Setting this maximum amount supercedes, to the extent that it is not consistent with, any decision on DWR and utility operating agreements or orders issued in this docket.
26. In all other matters, PG&E's Petition to Modify D.02-10-062 is denied.
This order is effective today.
Dated December 19, 2002, at San Francisco, California.
LORETTA M. LYNCH
President
HENRY M. DUQUE
CARL W. WOOD
GEOFFREY F. BROWN
MICHAEL R. PEEVEY
Commissioners
