V. Elements of the Procurement Plans

A general issue raised in testimony supporting the procurement plans, is that today's energy markets may not be sufficiently liquid, i.e., a robust transparent competitive market, to provide the data necessary to support the showing for negotiated bilaterals that we adopted in Section VI.E. at page 34 of D.02-10-062. While the utilities asserted this, none provided an adequate measurement tool that could be used as an alternative. The Commission recognizes the market may not be robust but we do expect the up-front standard to be met by a strong showing. This could be, for example, by comparison to Request for Offers (RFOs) completed within one month of the transaction. We note that the issuance of an RFO does not mean that a bid must be selected but it would provide an evaluation of the market. The other option for the utilities is to update their plans.

We clarify that interutility exchanges do not need to meet the transparent competitive market standard, but rather have a separate cost effective standard under Section VI.D of D.02-10-062. We encourage the utilities to pursue the option of interutility exchanges. If they find our adopted standard has problems in today's market environment, they should confer with their PRG and propose an alternative.

A. Effective Duration of the Short-Term Plans

D.02-10-062 required the utilities to submit modified short-term procurement plan addressing procurement activities in 2003 and authorized contract terms for up to five years for transactions entered into under the plan. D.02-10-062 also placed in motion a schedule for the development, review, and approval of long-term procurement plans covering anticipated procurement needs between 2004 and 2023.

PG&E's plan indicates that its plan is designed to cover procurement activities for a 12-month delivery horizon starting January 1, 2003. Edison's modified short-term plan presents residual net short (RNS) forecast data for calendar years 2003 through 2007 and acknowledges that its plan covers procurement activities executed in 2003. SDG&E's plan also notes that it is intended to address 2003 needs. In comments filed on the short-term plans, TURN expresses concern with PG&E's stated reference to limiting its procurement activities to only 2003. TURN states:

While we would certainly consider it prudent for the utilities to limit any procurement that would extend beyond the end of 2003 until the long-term plan is approved, that does not mean that no power at all should be bought for January 2004 . . . until such approval is obtained. At least some degree of forward hedging for the early months of 2004 should logically occur in the later months of 2003, consistent with the other parameters set forth in the company's current plan. (Comments of TURN on PG&E Generation Procurement Plan, Unredacted, p. 4.)

We agree. 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. We therefore authorize the utilities to hedge 2004 first quarter residual net short positions with transactions entered into in 2003. Each utility should consult with its respective Procurement Review Group in the development of a hedging strategy for 2004 first quarter needs.

B. Forecasts of Loads and Resources

In D.02-10-062, we directed the utilities to include in their modified short-term procurement plans the allocated quantities of power provided from DWR's long-term contracts pursuant to D.02-09-053, as well as transitional procurement contract amounts as authorized in D.02-08-071. The updated procurement plans filed by PG&E, Edison and SDG&E contain the necessary forecasts of energy and capacity that will be available from the allocated DWR contracts.

With respect to transitional procurement, we note that PG&E's Advice Letter 2293-E filed on October 23, 2002, requesting approval of certain contracts, was approved by the Commission in Resolution E-3796 on November 21, 2002. PG&E has two additional transitional procurement resolutions awaiting Commission approval prior to the end of 2002: AL 2303-E for renewable resource contracts and AL 2302-E for QF SO1 contracts. On December 5, 2002, the Commission approved Resolution E-3803, approving certain renewable resource contracts filed by SDG&E in Advice Letter 1445-E. SDG&E does not have any other transitional procurement advice letters pending Commission approval at this time. Both the PG&E and SDG&E procurement plans include estimates of power to be provided under the terms of the approved and pending transition contract advice letters.

Edison's plan update, while it does reflect DWR contract allocation amounts, does not include transition contract quantities in the derivation of its forecast RNS position. On November 21, 2002, the Commission adopted Resolution E-3802 approving certain transitional procurement contracts requested by Edison in Advice Letter 1660-E filed on November 5, 2002. Edison has yet to file a renewables advice letter in accordance with the requirements of D.02-08-071, as we discuss further below, but does have AL 1664-E for QF SO1 contracts on file awaiting Commission approval before the end of the year. Edison's short-term plan states that it will count any transitional contract quantities approved by the Commission against the forward energy and capacity procurement limits ultimately adopted in its short-term plan update.

In order that the short-term plans accurately reflect the final disposition of transitional contracts approved by the Commission under the procurement authority granted in D.02-08-071, we direct PG&E and Edison to update their plans within 18 calendar days of the effective date of this decision. We do not require an update from SDG&E because its plan already reflects the contracts approved in Resolution E-3803.

With the exception of TURN, parties did not challenge the utilities' loads and resources assumptions underlying the forecast RNS in the short-term plans. Although Edison developed three different load forecasts and four direct access penetration scenarios for a total of 12 forecasts of UDC load, TURN recommends that an additional direct access load scenario should be developed. TURN argues that Edison's existing set of direct access load forecasts do not sufficiently account for the combined effects of: (1) new municipalization; (2) new community aggregation under AB 117; and (3) future direct access loads surpassing existing direct access levels. As a result of not adequately addressing these three factors in its procurement plan, TURN expresses concern that Edison might end up over-procuring power on behalf of bundled service customers.

Edison resists TURN's recommendation for development of an additional direct access scenario noting that the Commission suspended the right of customers to acquire direct access after September 20, 2001, and that the Commission is not required to establish community aggregation procedures until July 15, 2003.⁷ With respect to municipalization, Edison characterizes this trend as "expensive, highly uncertain, and very time consuming." (Edison Reply Comments, p. 10.) Edison notes that should bundled service load decrease as a result of any of these changes, its plan provides for the filing of a revised procurement plan with the Commission.

The Commission has not announced any imminent intention of lifting the current suspension of direct access. In the event the Commission does elect to lift the suspension, such action will occur within the purview of a Commission proceeding and involve public notice in accordance with our Rules of Practice and Procedure. Edison is incorrect in arguing that the Commission has until July 2003 to establish policies and procedures for implementing community aggregation. We note that that the statutory deadline cited by Edison applies to the energy efficiency-related provisions of the bill and not to community aggregation. Local governments may initiate public processes at any time in 2003 to determine whether communities shall participate in community aggregation programs. We also note that prospective aggregators must register with the Commission prior to implementing aggregation.

It is premature at this time to direct the utilities to speculate as to the effects of these possible events in their load forecasts. 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. We note that the utilities will be required to file plan updates when certain triggering events occur rendering a current procurement plan inaccurate due to changing conditions underlying RNS forecasts (see discussion of plan updates in confidential Appendices A-C).

C. Volume Limits on Procurement

1. Edison

Both ORA and TURN propose downward adjustments to Edison's position limits. ORA states that given the great degree of uncertainty regarding both the size of the 2003 RNS and the distribution of probable future electric market costs, and because customer risk aversion has not yet been measured, the Commission should be conservative and not authorize the utilities to sign excessive amounts of contracts for 2003. It also states that the Commission should keep in mind that, unlike during the energy crisis of 2000-2001, market prices only apply to about 5 to 10 percent of the market, not 100 percent. ORA recommends that the maximum RNS purchase limit be set to a specified percentage of the average hourly RNS for the reference or expected case. For Edison, ORA proposes a modified annual limit for capacity contracts, a modified monthly forward energy contract limit, as well as separate volume limits for gas contracts.

TURN states it is concerned that Edison's plan appears completely focused on ensuring that Edison is not caught short in a period of price volatility while failing to contemplate the possibility of over-procurement and its adverse financial consequences for bundled ratepayers. TURN states that based on its review of the forecasts provided by Edison, the risks associated with potential high market prices (or total dysfunction) appear to be manageable even without locking in any major additional capacity commitments.

As an additional measure to protect ratepayers, TURN proposes that Edison be authorized to procure only 50% of its proposed energy and capacity limits through transactions that do not require pre-approval by the Commission. To the extent that Edison believes that forward purchases of the remaining 50% will benefit ratepayers, it should be required to make a showing as part of a pre-approval process that does not presume reasonableness of the quantities or prices.

We share the concerns of ORA and TURN regarding the prospect that Edison could over-procure energy and capacity. While recognizing that Edison proposes maximum limits that it may not in fact utilize, it is not prudent at this time to pre-approve these ceilings based on a worst-case RNS scenario. We are particularly concerned that Edison could over-hedge its position for a five-year term. This would effectively preclude the Commission's ability to consider renewable procurement under the Renewable Portfolio Standard (RPS), and additional energy efficiency and demand reduction programs for the 2004-2007 period in the long-term planning process. It would also preclude the Commission's ability to ensure that Edison responds in an economically efficient manner to possible reductions in its 2004-2007 RNS from community aggregation and other factors.

Therefore, we adopt ORA's 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. We also adopt a modification of TURN's 50% recommendation to address five-year contract limits. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit gas volumes.

2. PG&E

Based on our review and parties' comments, we find PG&E's volumetric guidelines presented in Appendices B and C of its short-term plan are reasonable. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit forward purchases at this time.

3. SDG&E

Based on our review and parties' comments, we find SD&GE's volumetric limits to be reasonable. We do not find sufficient justification to adopt ORA's recommendations to further limit forward purchases at this time. We note that SDG&E's reply comments make the erroneous assumption that ORA's recommendation to limit spot market transactions to a specified percentage of the average hourly RNS is not 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 retail needs.

D. Risk Management

1. Consumer Risk Tolerance Level

In D.02-10-062, we required the utilities to provide a level of consumer risk tolerance, along with a justification for the level they propose, in their November plan updates. We stated we would accept or modify their proposed consumer risk level for the short-term procurement plans and would retain a consultant to gather additional information regarding appropriate consumer risk tolerance levels for use in our review process for 2004.

While PG&E and SDG&E complied with our directive, Edison did not. The proposals by PG&E and SDG&E are well developed but we have concerns, particularly with PG&E's, that the limit it sets is too conservative. By setting too conservative a limit, customers will be paying a higher price premium to hedge against risk.

Both ORA and TURN filed proposals for modifying the utilities' risk management methodologies. TURN's proposal would set a specific consumer risk tolerance level consistently for all utilities. ORA's proposal would take a more conservative approach than that proposed by PG&E for when the utilities would need to meet and confer with PRG to develop a revised hedging strategy and file a revised procurement plan in instances when the price risk exposure of the open position exceeds the consumer risk tolerance level by a specified percentage. We find ORA's proposed trigger mechanism, when used in conjunction with TURN's proposal, to be reasonable and will adopt these two mechanisms for each utility for the short-term procurement plans. Adopting a higher customer risk tolerance also alleviates the concerns expressed by PG&E in Chapter 1, page 1-5 of its short-term plan.

We also 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. In addition, we agree with TURN's comments concerning the procurement selection process as reflected on page C-3 of PG&E's plan. Based on these comments, we direct PG&E to confer with its PRG to elaborate on how it will select among different procurement products to hedge in 2003. PG&E shall file an addendum by Advice Letter to its plan by advice letter providing clarification of this issue at the same time it submits updated tables reflecting executed transitional contracts.

2. Using Value at Risk (VaR), Cash-Flow-at-Risk (CFAR) Models and Other Tools to Measure Portfolio Risk

Each utility proposes its own tools to measure portfolio risk, as discussed in the confidential portion of their procurement plans. ORA recommends that the utilities should move in the direction of analyzing portfolio risk based on a probability distribution of risk drivers in lieu of the utilities' methodologies and specifically recommends the use of VaR and CFAR models.

We agree with ORA that the utilities should move in the direction of analyzing portfolio risk based on a probability distribution of risk drivers but do not want to be prescriptive at this time in requiring use of the VaR and CFAR models. We direct Energy Division to schedule a workshop in early 2003 that will assist us in gathering additional information on this subject and to discuss a broader range of measures of portfolio risk exposure.

We approve PG&E's use of pre-defined scenarios to measure the customers' exposure to specific price and volumetric risks but question the design of its portfolio scenarios, based on ORA's comments. Therefore, we direct it make specific scenario changes, as detailed in confidential Appendix A.

We modify Edison's risk management criteria described in Chapter IV, Section C.1 to include two revisions; similar to the adjustments that were adopted by the Commission recently in Resolution E-3802.

SDG&E's risk assessment methodology is approved without modification; however, we direct SDG&E to meet with its PRG and ORA to discuss further what magnitude is appropriate for a benefit/cost ratio for transaction screening and how it should be calculated.

3. Use of the Black Model and Other Standardized Models

ORA recommends that each utility use the Black Model and a specific benefit/cost ratio for screening transactions. The utilities object to this recommendation and cite to a number of limitations with the Black Model and concerns with the benefit/cost ratio as proposed by ORA.

We do not mandate the use of the Black Model as a determinant for contract evaluation at this time, but do want to have the data collected so that we can better evaluate the model's merits at a later date. Therefore, we direct the utilities to present Black Model results, for informational purposes, as part of their quarterly advice letter filings as well as for contracts submitted for pre-approval.

With respect to prescribing a specific benefit/coat ratio, PG&E and SDG&E shall confer with their respective PRGs to further assess the appropriate magnitude of the benefit-cost ratio and the calculation of such a ratio.

4. Trigger for Plan Updates

TURN proposes that if the monthly RNS deviates from a utility's underlying assumptions by a certain percentage, it should trigger an update of the plan. In each confidential appendix, we set a higher threshold for the trigger and direct that at this level, each utility should confer with its PRG to discuss the need to file a plan update.

E. Renewable Procurement Issues

1. General Comments

In D.02-10-062, we directed the utilities to file, with their November 12^th short-term procurement plans, "a report on the status of their procurement under the renewable generation mandate of our previous order (D.02-08-071, directing a 1% incremental renewable procurement." With varying degrees of specificity the utilities have complied, and have subsequently filed - with the exception of Edison - Advice Letters for expedited approval of these new renewable contracts. An evaluation of these short-term plan and Advice Letter filings follows.

Before turning to these filings, however, we wish to address a few outstanding issues raised in the utility filings and in party comments on them. Edison has repeated arguments addressed in D.02-10-062 concerning the relationship between § 701.3, the basis for our 1% incremental procurement order, and the directives of the recently enacted SB 1078. Edison contends in its short-term plan that SB 1078 establishes "additional and qualifying conditions" on this Commission's authority to order renewable set-asides.⁸ We disposed of Edison's arguments in D.02-10-062,⁹ which cannot be avoided by delay.

Second, parties remain concerned about the exact quantities the utilities are tasked with procuring, and the relationship of past sales levels to the 1% procurement order. The determination of renewable generation "baselines" is a task that will be addressed in party briefs in January, but for now we direct the utilities to submit, as a compliance filing by January 2nd, their 2001 sales figures including DWR power. It is 1% of this figure that utilities are directed to procure in the form of new renewable generation.

Parties express additional concern over the possibility that a utility's baseline renewable generation might shrink, even as the 1 percent procurement is executed. To this point we provide the following direction: the 1 percent procurement, as has been repeatedly expressed, is to 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. If the utility allows its present renewable generation to shrink by 1 percent, even as it procures 1 percent from another renewable source, it will not be meeting our directive - it will, at best, be holding steady.

To be considered incremental renewable generation, the interim procurement must result in a net increase of at least 1% of total 2001 retail sales in the utility's renewable portfolio above its 2002 level. If the 2002 renewable generation baseline amount will shrink in 2003, the utility must 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.

This is the imperative, and the measure against which we will be assessing the results of this procurement early next year - when the collaborative CPUC-CEC RPS implementation effort produces, with the assistance of other parties, monitoring and compliance mechanisms that can be deployed. Since the utilities are in the best position to assess the condition of their renewable baseline at present, and have at their disposal a list of potentially cost-effective renewable contracts that can be executed in the coming weeks to insure these conditions are met, we direct the utilities to reaffirm these incremental results immediately. Utilities may find cost-effective procurement options more limited if they wait until next year's verification process to be completed before procuring sufficient renewable power to preserve their baseline. Further contracts filed by Advice Letter for this purpose will be given expedited treatment.

Third, we recognize the outstanding uncertainties regarding the distinctions between existing levels of renewable generation from a given facility, incremental additions to the generation from a given facility, and output from a facility that is completely new. As clarified in D.02-10-062, incremental production from existing facilities is eligible to meet the 1% interim procurement target. We must be able to ascertain, however, that this generation is in fact incremental, and for this purpose - and for the purposes of RPS implementation beginning next year - we will rely on the analysis of the CEC. While we have made a preliminary assessment as to whether the approved renewable generation amounts to incremental production, this assessment will not be final until the CEC performs its analysis. As with several other aspects of this renewable procurement effort, we must be flexible as we design the program's parameters, and ask that parties maintain a similar degree of flexibility. Again, the utilities are presently in the best position to answer these questions, and we direct them to avail themselves of all cost-effective options that will achieve the necessary result.

2. Short-Term Plans and Advice Letter Filings

In evaluating the short-term plan filings of each utility in regard to renewable energy procurement, we also discuss the contents of each utility's Advice Letter filing for renewable procurement approval, and the extent to which these two filings together satisfy the requirements of D.02-10-062. As we continue to prepare for implementation of the RPS, we also discuss the effectiveness of the plans in addressing projected needs for future renewable procurement.

As a preliminary matter, we must emphasize that, given the remaining uncertainties regarding baselines, targets and RPS implementation rules, none of the utility plans are sufficiently robust to meet the standard of procurement pre-approval under AB 57. There are simply too many unanswered questions regarding future renewable procurement to allow for further, pre-approved renewable procurement in 2003. However, the RPS implementation process that will unfold next year will develop the standard definitions and contract terms necessary if procurement pre-approval is to be authorized. Moreover, we do not foreclose the option of further renewable procurement by the utilities in 2003, subject to the defined contract filing and approval process. In this aspect of the utility short-term plans we agree with ORA in characterizing these plans as "working documents,"¹⁰ describing the interim RFO process and some preliminary lessons learned, with implications for full RPS implementation to be developed next year.

a) SDG&E

In SDG&E's two-page assessment of its short-term renewable procurement plan, the utility describes what appears to be a commendable RFO process resulting in procurement of substantially more renewable generation than required by our order. SDG&E Advice Letter 1445-E describes more fully the nature of this procurement, estimating that it will result in an incremental 4% of renewable generation in 2003, and approximately 7% in 2004. Commission Resolution E-3803 approved these procurement contracts, and noted the apparently effective participation of the Procurement Review Group in evaluating the solicitation.

CBEA raises several questions regarding SDG&E's solicitation,¹¹ to which the utility responds in its December 6^th Reply Comments. The first concerns the treatment of expiring renewable contracts that SDG&E extended as a result of the interim solicitation, characterized by the utility as "purchases...for incremental megawatts above those that SDG&E would have otherwise made.... Therefore, all of the megawatts associated with the RFO-related renewable contracts are for incremental megawatts and count towards meeting the 1% annual requirement."¹²

This description by SDG&E is overbroad. The procurement requirement in D.02-08-071 is for "at least an additional 1 percent of their annual electricity sold" (p. 32, emphasis added). Thus, extending existing contracts serves, all else equal, only to maintain the utility's renewable generation baseline. The 1 percent additional procurement must be met either from projects not currently selling to the utility, or from incremental production from existing facilities. The process for determining incremental output from existing facilities is one that we will turn to early in our RPS implementation process, and cannot be addressed at this time.

As a result 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. Nonetheless, 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 RPS. If the utility is shown to not have met its 1 percent incremental procurement target, either by under-procurement via the RFO or by allowing its 2001 renewables baseline to shrink, further procurement may be ordered under the authority of § 701.3.

Second, CBEA questions the extent to which SDG&E includes DWR renewable power in the calculation of its baseline and 1 percent targets. SDG&E responds that it did not include such power, given that the contracts allocated to the utility from DWR did not include the so-called "renewable attributes" associated with such power. These renewable contracts, it appears, were therefore excluded from both the baseline and the 1 percent target calculation. While we do not address the issue of renewable attributes here, we intend to investigate these DWR contracts further.¹³ In any event, we reiterate our instructions that all power sold in 2001 be represented in the calculation of the 1 percent procurement target, including DWR power, and regardless of the technology used to generate it. This DWR power must appear, in effect, in the denominator of the calculation, and we will ensure that it does in the development of our renewable baselines and annual procurement targets. Again, given that SDG&E has apparently procured four times the renewable power required of the utility in 2003, we will make a determination on this point when all certification mechanisms are in place.

b) PG&E

PG&E submits a brief discussion of its interim renewable RFO process in its short-term plan, and describes the process and results in its Advice Letter 2303-E. Pending Commission approval of Resolution E-3805, it appears that PG&E has met its 1 percent interim renewable procurement mandate, pending final certification by the CEC of incremental output from existing resources per SB 1078.

A few points require clarification, however, in response to comments from CBEA, TURN and based on our own analysis of the record. First, it appears from tables in Appendix A to PG&E's short-term plan that PG&E calculates its 1 percent target based on anticipated 2003 sales figures, not those from 2001, as directed. As ordered above, we direct the utilities to submit 2001 sales data as a compliance filing by January 2^nd, in order that procurement targets can be developed from a common understanding. Again, if this process results in the recalculation of procurement targets for the utility in this interim process, we direct the utility to undertake further renewable procurement as needed. Commission review of these potential new contracts will receive expedited review.

CBEA contends, as it does in SDG&E's case, that PG&E does an inadequate job of ensuring that the utility's renewable generation baseline is calculated correctly and will not shrink in 2003. While we agree with PG&E that it is impossible to predict with certainty the output of many renewable facilities, the requirement is that the utility contract for a level of renewable generation that would result in an additional 1 percent of generation in 2003. The ultimate output of each facility is a separate matter, and the penalties for deviation from contracted-for levels are determined in each contract. Thus, it is imperative that the interim procurement process results in a net increase of at least 1 percent. If the renewables baseline shrinks, new contracts must be signed that will replace the lost power and increase output by at least 1 percent. Since PG&E's proposed renewable procurement level is much lower than that for SDG&E, we cannot assume that, at the margin, our requirement has been satisfied. We will provisionally hold that PG&E has met its interim procurement goal, pending the filing of 2001 sales figures and certification of facility output by the CEC. If the utility is shown to not have met its 1 percent incremental procurement target, either by under-procurement via the RFO or by allowing its 2001 renewables baseline to shrink, further procurement may be ordered under the authority of § 701.3.

TURN raises a number of valid concerns in its confidential comments on PG&E's Advice Letter 2303-E, concerns that merit our attention in analyzing the utility's short-term plan. While we agree with TURN that the concerns raised do not warrant the invalidation of PG&E's interim procurement contracts, we also agree that the issues TURN raises must be addressed fully if the RPS implementation process is to be successful. Rules governing issues such as the eligibility of resources, facility expansion and repowering, and the flexibility of RFO and contract terms will be defined in our implementation process, not by the unilateral declaration of any individual party. We look forward to an effective and mutually beneficial collaboration across all parties as the process develops next year.

c) Edison

Edison provides in its November 12^th filing a moderate amount of information regarding targets and assumptions for its 1 percent incremental renewable procurement. One of these assumptions - that the passage of SB 1078 limits the authority of § 701.3 - has been addressed above. Details regarding procurement targets and the RFO process are contained in confidential Volume II of the short-term plan, and what is disclosed looks, on balance, reasonable.

No Advice Letter filing has been forthcoming, however, despite the utility's pledge to file early this month. This delay unfortunately lends credence to the concerns expressed by TURN and CalWEA that Edison is deliberately stalling the interim procurement process, either to test the Commission's § 701.3 authority or to pre-judge the implementation efforts for the RPS program. Examples such as creation of undue barriers to participation by particular technologies, and of price benchmarks different from the Commission's 5.37¢/kWh target, are cited in support of these assertions. Both of these practices, if verified, would constitute violation of Commission orders and would be subject to sanction. The Commission is actively exploring its options in this regard.

Subject to further sanction would be the utility's continued failure to simply file an Advice Letter containing renewable contracts of any sort, be they for more or less than the 1 percent target. Waiting to file will not have the effect of avoiding the requirements of D.02-08-071; in fact it will make those requirements more challenging, as the utility will need to procure the same GWh amount over fewer days in the calendar year.

We find that the utility is in noncompliance with D.02-08-071, and will address this noncompliance in a subsequent Commission order. In the event that this Advice Letter is forthcoming, we reiterate our direction provided to the other utilities regarding calculation of the 1 percent target and the preservation of Edison's baseline level of renewable generation.

d) CBEA

As noted above, CBEA has raised a number of concerns to do with the utilities' interim procurement process, and has described the inability of four biomass plants with expiring DWR contracts to secure contracts under the 1 percent order. CBEA raises three general objections to the utility plans: 1) the plans do not ensure that renewable procurement will increase by 1 percent on net; 2) the plans do not include DWR renewable power in the calculation of the baseline; and 3) utilities may be improperly accounting for existing generation. We have addressed each of these general points above, and have established a verification process for each issue that will result in the quickest possible resolution. CBEA's comments have aided us in assessing the points of contention in the interim procurement process and in the RPS implementation to come.

CBEA's specific complaint, however, is that these four biomass plants were not offered contracts by the utilities and may be forced to close without Commission action. The Commission has approved by Resolution the Advice Letter filings of SDG&E and PG&E, finding that the renewable solicitation process for each utility was sufficiently competitive and has provisionally resulted in sufficient procurement to meet the 1 percent order. To disallow a utility's renewable procurement on the grounds that specific facilities were not acquired, or to force utilities otherwise in compliance with our order to extend contracts to these facilities - particularly given the appearance that these biomass bids were relatively uncompetitive - would be to unduly favor a specific economic interest in this process. At this time we will not force any utility to accept this power. CBEA's remaining avenues for relief, as before, are sales into the open market, a potential short-term contract extension through DWR, or possible registration as a QF under PURPA, for sale directly to the utilities at avoided-cost prices.

3. CPUC-CEC Collaborative Workplan

Pursuant to SB 1078, the CPUC and CEC will collaborate on a number of key RPS implementation points, many of which were identified for party briefs in D.02-10-062. Over the past two months, CPUC and CEC staff have met regularly to scope the RPS implementation issues and develop a plan and schedule for next year's effort. This plan will be informed by party comment on the 6^th and 13^th of January, and will be served on parties as a Workplan on February 3^rd for party comment on February 10^th. A portion of the prehearing conference scheduled for February 17^th will be set aside for discussion of the plan.

We take this opportunity to clarify our inter-agency approach with the CEC regarding implementation of the RPS. The CEC will designate specific staff members to be RPS Implementation Collaborative Staff, who along with CPUC 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 service of February 3^rd. The CEC has agreed that a similar, reciprocal arrangement will be established for CPUC staff in the CEC's rulemaking addressing renewable generation issues.

F. Qualifying Facilities Contracts

CAC states that the utilities' plans are so general in the public version that the Commission should reject the filings as deficient. In addition, CAC states that these plans provide for the procurement of resources for up to a five-year period and during that time several QF contracts will expire. CAC requests that the Commission require the utilities to provide for the renewal of a federally compliant procurement agreement with existing QFs and the maintenance of their output throughout the term of the plan.

In its response, PG&E states the plan is for 2003, not five years, and that the utilities obligations to QFs for 2003 was determined in D.02-08-071. PG&E also points out that the type of material that is designated as protected is covered under the Protective Order in place here.

D.02-10-062 does authorize the utilities to enter five year contracts, but it is only for the purpose of meeting 2003 needs. PG&E is correct that D.02-08-071 addresses QF contracts in 2003. CAC will have the opportunity to address future years in the long-term planning phase.

Turning to CAC's assertion that the plans "lack any meaningful detail," we agree with PG&E that § 454.5(g) requires both the utilities and the Commission to keep market sensitive information confidential. Section  454.5(g) provides in pertinent part that:

"(g) The commission shall adopt appropriate procedures to ensure the confidentiality of any market sensitive information submitted in an electrical corporation's proposed procurement plan or resulting from or related to its approved procurement plan, . . . provided that the Office of Ratepayer Advocates and other consumer groups that are nonmarket participants shall be provided access to this information under confidentiality procedures authorized by the commission."

Through a combination of nondisclosure agreements, confidential appendices, and acceptance of filings under seals, we have complied with our statutory obligations. We decline at this time to order the utilities to make public more detail regarding their procurement plans. See, on a related note, our disposition of IEP's Motion in Section IV of this decision.

G. Demand Response Programs

ORA raises several important issues in relationship to the integration of utility demand response programs into the short-term procurement plans. Specifically, while ORA finds that the utilities "properly included demand response resources in their short-term procurement plans," ORA requests that the utilities specify which demand response initiatives are treated as resources and which are integrated into the load forecast. ORA also recommends that the utility short-term plans include contracts of one year or less that could be superceded by future demand response efforts.

In addition, ORA present its views on the definition and distinction between: a) tariffs and b) demand response programs. In general, ORA views tariffs as having uncertain impacts in the short-run, but "in the long run as forecast accuracy improves the demand reductions expected in response to the tariff's price signal can be built into the load forecast." On the other hand, ORA views programmatic demand response efforts that are paid for as they are procured as having the potential to be a reliable resource that can be counted on (as supply) to reduce demand when called into play.

The Commission takes note of these comments as well as ORA's recognition that many of the issues addressed in their comments are being considered in our Demand Response Rulemaking (R.02-06-001). Specifically, we note that 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 that Rulemaking. Given that this is pending issue in that Rulemaking, the Commission finds it inappropriate at this time to integrate ORA's comments into this current decision.

Without an adequate definition of this issue, 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 plans. Rather, we will be addressing at this issue comprehensively and in a coordinated fashion. We therefore respectfully deny ORA's request on this matter.

H. Reserve Levels

Based on our review and the comments filed, we find the 7% operating reserves level proposed by the utilities in their short-term plans to be adequate for 2003. We have concerns regarding other reserve levels of Edison, and modify its authorized limits in confidential Appendix B.

For the long-term planning phase, ORA requests that each utility 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. This is a reasonable request and, therefore, we adopt it. We note that ORA's request, while requiring specific data be furnished, allows each utility latitude to propose and support a planning reserve level it considers appropriate to its service territory. This should be done in conjunction with the provisional 15% reserve level and guidance we adopted in D.02-10-062.

I. Cost Recovery and Related Issues

The cost recovery issues were decided by the Commission in D.02-10-062, as discussed in Section XII of that order, and the utilities were directed to implement the necessary accounting mechanisms. In its November 12, filing, PG&E proposes accounting mechanisms not in conformance with D.02-10-062 and raises new arguments regarding the proper implementation of AB 57. We discuss and resolve those issues here.

PG&E included in its plan the cost recovery proposal (Chapter 5) it believes is in compliance with D.02-10-062 and § 454.5(d)(3). On November 13, 2002, PG&E filed Advice Letter 2299-E to implement the procurement ratemaking adopted in D.02-10-062. PG&E's implementation filing, however, includes elements of its cost recovery proposal. The Energy Division rejected the advice letter on November 15, 2002. On November 20, 2002, PG&E met with the Commission General Counsel and representatives from the Energy Division to discuss the rejection of the advice letter and other procurement issues. On November 22, 2002, PG&E filed revised Chapter 5 to clarify ambiguities and modify certain aspects of its cost recovery proposal. The revisions include proposed tariff changes to Transition Revenue Account (TRA) and Emergency Procurement Balancing Account (EPBA) and a pro-forma Preliminary Statement for the Energy Resource Recovery Account (ERRA). PG&E states that the revised Chapter 5 and the attachments supersede the original filing in its entirety. PG&E requests that these tariffs be approved effective January 1, 2003.

1. The Trigger Mechanism and the ERRA Balancing Account

D.02-10-062¹⁴ directs the utilities to file "trigger" applications when undercollections in the ERRA reach 4% "of the electrical corporation's actual recorded generation revenues for the prior calendar year excluding revenues collected for the Department of Water Resources."¹⁵ D.02-10-062 further provides that the a trigger application should call for Commission approval within 60 days of filing. PG&E's cost recovery proposal focuses on language from AB 57/SB 1976 stating "...that any overcollection or undercollection in the power procurement balancing account does not exceed 5 percent of the electrical corporation's of actual recorded generation revenues for the prior calendar year excluding revenues collected for the Department of Water Resources," and so goes beyond the requirements of D.02-10-062 to address contingencies that might occur during the 60-day period when the Commission is reviewing an expedited trigger application filed pursuant to PG&E proposes to include the following items in its trigger application.

1. A projected account ERRA balance in 60 days from the date of the filing and a forecast when the account balance will exceed the 5 percent threshold.

2. Since the ERRA balance cannot exceed 5 percent without triggering rate increases, PG&E proposes to reduce the ERRA balance automatically to the 4 percent threshold by transferring an amount equivalent to the amount that would reduce the balance to this level from the TRA overcollection, if available, in the month the undercollection occurs in the ERRA. Alternatively, PG&E will increase rates as follows: (1) if the ERRA balance exceeds 5 percent threshold prior to the end of 60-day period, request an interim emergency rate adjustment; (2) Increase rates on the 61^st day of the filing if the Commission does not act on its expedited application and the ERRA balance exceeds 5 percent threshold. This is an automatic rate increase subject to refund and adjustment; and (3) In any month the undercollection in the ERRA exceeds TRA overcollection; PG&E requests a rate increase.

3. In the event of unusual market conditions, PG&E would include in the expedited trigger application updated procurement costs and adjusted revenue requirements to update the stale procurement forecasts. The new forecast would reset the revenue requirement for the rest of the year.

The cost recovery and the ERRA trigger mechanism are intertwined. PG&E, therefore, contends that its cost recovery proposal and the trigger mechanisms it proposed are in compliance with D.02-10-062 and § 454.4(d)(3).

TURN is concerned about PG&E's derivation of the $150 million generation revenue requirement that PG&E suggests is the 5 percent trigger amount in its example of how the transfer from the TRA will be accomplished. TURN alleges that the $150 million is "significantly lower than the comparable number proposed by Edison" and therefore questions whether PG&E included all its 2002-generation revenues, including surcharges in developing the amount.

PG&E responds to TURN's concern that its calculation of the $150 million excludes revenues collected for DWR and claims that it derived its number based on the information contained in Appendix D to D.02-10-062. PG&E states that it calculated its $150 million based on updated revenue requirement filing¹⁶ pursuant to D.02-04-016.

TURN contends that PG&E's tariff language to transfer the monthly ERRA revenue requirement from the TRA to ERRA and also to transfer the overcollection amount from the TRA to reduce the undercollection in the ERRA to the 4 percent threshold "is simply not what the statute contemplates." Neither TURN nor ORA addresses the issue of automatic rate increases if the Commission fails to act within the 60-day period.

TURN alleges that PG&E's proposed ERRA balancing account preliminary tariff language does not comply with AB 57. TURN adds that the tariff would require substantial revision that should be addressed in an emergency workshop setting conducted by Commission's Energy Division. Specifically, TURN maintains that the statute requires that the balancing account track the difference between actual costs incurred and actual recorded revenues collected to cover those costs. This is in contrast to PG&E's proposed ERRA tariff language, which would track the difference between actual costs incurred and ERRA revenue requirement authorized by the Commission in D.02-04-016, the Utility Retained Generation (URG) decision. In other words, TURN maintains that the ERRA balancing account tariff language should compare actual ERRA costs with the actual generation revenues collected based on the residual generation rate component of the tariff schedules and emergency surcharges which cover not only ERRA costs but allocated DWR costs and non-fuel URG costs.

PG&E argues that TURN's recommendations on the ERRA tariff should be rejected because D.02-10-062 requires that actual recorded procurement costs be tracked against the "recently approved fuel and purchase power revenue requirements" as specified by Appendix D of the decision. PG&E states that the inclusion of generation revenues and surcharge revenues in the ERRA as suggested by TURN would be in violation of D.02-10-062 and AB 57, creating a huge overcollection that could trigger a refund to ratepayers. PG&E further states that costs included in ERRA do not include DWR costs and therefore, revenues recorded in the ERRA should not include DWR revenues which the law specifically excluded from generation revenues. PG&E rejects TURN's suggestion for expedited workshops on the ERRA tariff language and cites ORA's support of its balancing account and trigger mechanism proposal as being reasonable.

2. Starting Point for ERRA Costs and Revenues

PG&E proposes a "starting point" revenue requirement that will be transferred from the TRA to the ERRA to offset ERRA costs. PG&E states that the 2002 URG procurement revenue requirement includes its URG fuel and purchase power costs and not the additional costs to be incurred for the RNS. It proposes to include these additional costs and revenues in the fuel and purchase power revenue requirement adopted in the 2002 URG decision. These costs include open market position, reserves and collateral costs as well as DWR surplus sales revenues allocated to PG&E. PG&E's forecast for these costs and revenues in 2003 produces a negative amount of $3 million. When this amount is added to the fuel and purchase power revenue requirement of $2.038 billion, the proposed starting point revenue requirement is $2.035 billion. PG&E asserts that it made this calculation to avoid a mismatch between revenues and costs, to prevent a triggering event occurring sooner, and for the trigger mechanism to function properly.

PG&E proposes to transfer monthly revenues from the TRA equal to the monthly costs underlying the annual 2003 ERRA starting point revenue requirement or one twelfth of $2.035 billion as ERRA procurement revenue requirement to match against actual costs incurred. TURN opposes this concept as previously discussed.

3. Issues With Proposed Tariff Language

PG&E's Plan's Chapter 5 includes Appendix A, which contains a pro-forma ERRA Preliminary Statement, as well as revised TRA and EPSBA tariffs. PG&E requests approval of the tariffs effective January 1, 2003.

TURN opposes the revised tariff language in the TRA indicating that the tariff "will be in effect until the end of rate freeze." TURN asserts that the language in D.02-11-026¹⁷ shows that the freeze ended no later than March 31, 2002 and therefore, the TRA tariff has expired and should be removed from PG&E's tariffs. PG&E disagrees with TURN. PG&E asserts that "it is premature to supercede its previously Advice Letter¹⁸ filing of post rate freeze accounting mechanisms before a more definitive indication that the Commission is ready to address the effective date of the post rate freeze tariffs."

TURN also alleges that PG&E's revisions to EPSBA tariff do not comply with D.02-11-026 because PG&E failed to show that it would apply ongoing power costs first to AB 1890 frozen rates and only secondarily to surcharge revenues to the extent needed. In response PG&E states that the same decision requires all utilities to continue to track surcharge revenues in the authorized balancing accounts since they remain subject to later adjustment and possible refund. PG&E states that it revised EPSBA tariff to exclude costs that would be recorded in the ERRA and to keep non-fuel retained generation and DWR costs in the EPSBA.

4. Cost Recovery of Certain Costs

a) Electric Energy Transaction Administration (EETA) Costs

PG&E states that a conflict exists with two Commission decisions as to where EETA costs should be recorded. Appendix D to D.02-10-062 indicates that these costs should be recorded in the ERRA while D.02-09-053 ordered PG&E to address the recovery of EETA costs pertaining to the administration of the DWR contracts allocated to it in the general rate case (GRC). PG&E recommends that these costs be reviewed and set on a forecast basis in the GRC and not recorded in the ERRA. TURN and ORA support PG&E's recommendation.

Edison and SDG&E differ from PG&E's position regarding where and when EETA costs should be recorded and recovered. SDG&E wants to record its EETA costs in the ERRA until base rates are established in its future cost of service application according to its ERRA tariff.¹⁹ Edison agrees with ORA's recommendation to recover ERRA costs through base rate but wants to initially record EETA costs in the ERRA until the effective date of its 2003 Test Year GRC decision. Edison claims that because it does not presently have any RNS costs in Commission authorized rate levels, starting January 1, 2003; it must record its EETA costs and non-EETA costs in the ERRA account.

b) Above-Market Costs Related to Qualifying Facilities (QFs) and Purchase Power Agreements (PPAs)

PG&E asserts that there is some ambiguity regarding where to recover ongoing transition cost component associated with QF and PPA contracts since D.02-11-022 established a market benchmark for determining the above market costs. PG&E recommends that the above-market costs should be recovered in the Modified Transition Cost Balancing Account (MTCBA).

TURN and PG&E differ on how the above market costs or competition transition costs (CTC) should be calculated. PG&E and TURN disagree as to whether the calculation of CTC should be the difference between the average costs of the URG resources or limited to only the QF and PPA costs and the market benchmark.

ORA, Edison and SDG&E agree that all QF and PPA costs should be recorded in the ERRA. Edison further indicates that the CTC portion can be tracked separately in the ERRA.

5. Discussion

a) The Trigger Mechanism and the ERRA Balancing Account

Pub. Util. Code § 454.5(d)(3) provides, in pertinent part, that:

"The commission shall review the power procurement balancing accounts, not less than semiannually, and shall adjust rates or order refunds, as necessary, to promptly amortize a balancing account, according to a schedule determined by the commission. Until January 1, 2006, the commission shall ensure that any overcollection or undercollection in the power procurement balancing account does not exceed 5 percent of the electrical corporation's actual recorded generation revenues for the prior calendar year excluding revenues collected for the Department of Water Resources. The commission shall determine the schedule for amortizing the overcollection or undercollection in the balancing account to ensure that the 5 percent threshold is not exceeded.

As an initial matter, we must determine how to calculate "5% of the electrical corporation's actual recorded generation revenues . . ." (the "5% threshold"). We share TURN's concern regarding PG&E's derivation of $150 million as the 5% threshold. PG&E's figure is significantly low when compared with Edison's calculation²⁰ of its (Edison's) 5% threshold. The reason for the discrepancy between Edison and PG&E lies in each utilities' treatment of emergency surcharge revenues. PG&E excludes revenues associated with the emergency surcharges from its "recorded generation revenues" figure, while Edison includes emergency surcharges. Presently, the emergency surcharges of 4.5 cents are part of generation revenues and they should be included in PG&E's calculation. PG&E must compare actual recorded generation revenue, including the surcharge revenue, in order to calculate whether the threshold has been triggered. Therefore, PG&E is directed to use the same method used by Edison. We expect PG&E's recalculated 5% threshold number to be about $300 million.

We must turn next to the question of how to calculate the level of ERRA over and undercollections. PG&E proposes to track ERRA costs against authorized revenue requirements to determine when to file the expedited 4 percent trigger application. TURN points to language in § 454.5 requiring that actual incurred costs be compared with actual recorded revenues for the determination of over and under collections in the ERRA balancing account. PG&E is correct, however, that D.02-10-062 adopts 2002 URG fuel and purchase power revenue requirements to be tracked against ERRA costs. D.02-10-062 adopts the interim revenue requirements for the majority of costs that will be recorded in the ERRA since the Commission has yet to establish generation rates to recover those costs. We agree with PG&E that the residual generation rate recovers more than fuel and purchase power costs. 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 is denied.

Finally, we turn to the question of what to do when the crossing of the 5% threshold looms. As described above, D.02-10-062 already provides for an expedited trigger application process when undercollections reach the 4 percent level. PG&E, alone among the utilities, is dissatisfied with this approach to undercollections, and as already described proposes several additional ways to avoid crossing the 5% threshold. PG&E seeks authority to automatically transfer overcollection amounts from the TRA to bring the undercollection in the ERRA to the 4 percent level. PG&E has also proposed implementing automatic rate changes requests when the Commission does not act in a timely manner upon an expedited trigger application.

We agree with TURN that the interaction between the TRA and ERRA needs further understanding by the Commission and parties. Also, there are several PG&E's advice letters²¹ that are related to TRA mechanism still pending before the Commission.

Nothing in AB 57/SB 1976 requires this Commission to cede its ratemaking authority to PG&E by allowing for automatically effective rate increases (whether subject to refund or not), and we decline PG&E's invitation to do so today. We retain the authority that § 454.5 grants us in determining how to amortize undercollections. That said, we undertake today, in recognition of the somewhat unique posture of PG&E as a bankrupt utility, certain actions to address PG&E's concerns about undercollections exceeding the 5% threshold.

First, we authorize PG&E to file and expedited trigger application at any time that its forecasts indicate it will face an undercollection in excess of the 5% threshold. That is, we no longer require PG&E's ERRA undercollections to reach 4 percent before we will entertain a trigger application.

Second, pending completion of further review of PG&E's ERRA account (about which more below), the Commission commits to act as rapidly as necessary on rate changes requests, consonant with § 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 determine by the Commission."

Third, we accelerate our review of PG&E's ERRA account, advancing the review by four months to commence in February rather than in June.²² We agree with PG&E that it is reasonable to explore the concept of transferring overcollection in a balancing account to offset undercollection in another balancing account. It may not make sense to increase rates because there is undercollection in one account while there is a significant overcollection in another account benefiting the same customers. In order to address PG&E's proposal regarding offsetting ERRA undercollections and to quickly address its concerns, we direct PG&E to file both its forecast application and the balancing account review application on February 1 and August 1, 2003, respectively. SDG&E will file similar applications on June 1 and December 1, 2003. PG&E should include its proposal for applying the overcollection of TRA to the ERRA account in the February filing. We intend to look closely at this approach and also whether refunds to ratepayers should be implemented in the same way.

We take this opportunity to clarify our previous order for SDG&E and Edison. SDG&E should use its generation rate revenues for this purpose instead of the authorized revenue requirements as provided for in its ERRA tariff.²³

Edison's Advice Letter²⁴ to implement the ERRA mechanism reflects the 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). This means that Edison does not plan to file an expedited application when the undercollection in the ERRA tracking sub-account reaches an amount equal to 4 percent of prior year recorded generation revenues excluding revenues collected for DWR because it is recovering its full ERRA costs through the SRBA. We authorize this approach.

Finally, in one further effort to respond to PG&E's concern on timely cost recovery to avoid violating the law, we direct PG&E, SDG&E, and Edison to file with the Commission's Energy Division each month a report showing the activity in the ERRA balancing account with copies of original source document supporting each entry over $100.00 recorded in the account. This report shall be filed not later than the 20^th following the end of the month. This should give the Commission the opportunity to anticipate when an expedited trigger application might be filed by any utility. It would also reduce the review time for such application. The report itself, but not the underlying documents, shall be served on interested parties to this proceeding.

In summary, we are making numerous changes to D.02-10-062 to address PG&E's concerns. We deny PG&E's rate adjustment requests and TRA overcollection transfer to the ERRA at this time without prejudice.

b) Starting Point for ERRA Costs and Revenues

PG&E proposes a $2.035 billion starting point annual revenue requirement for transferring the monthly revenue requirement from the TRA to the ERRA to match against ERRA costs. We 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 1 filing. We 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. Therefore, PG&E should revise its ERRA and TRA tariffs accordingly.

c) Issues With Proposed Tariff Language

PG&E should 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 rate freeze should have ended." TURN's request is denied.

TURN also questions the revisions to EPSBA tariff. We have reviewed the page cited by TURN in its comments along with D.02-11-026, which is replete with the phrase that the funds from the surcharges should be used "to pay for future power purchases or securing reasonable financial health." We agree with TURN that because of the modification to D.01-03-082, PG&E does not need to track ongoing power costs first with 1-cent surcharge revenues in the EPSBA. Such revenues should be included in the TRA. We note that PG&E currently records the 3 cents surcharge revenues in the TRA as part of the billed revenues because Advice Letter (AL) 2096-E is still pending before the Commission for approval. 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. 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 (OP 9), "to segregate DWR related billed revenues from URG related billed revenues." 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. In view of the changes to D.01-03-082 by D.02-11-026, the tariff changes proposed in the AL 2096-E are moot and the AL should be withdrawn. Other ALs related to AL 2096-E should be amended accordingly five days after the approval of this decision.

d) Cost Recovery of Certain Costs

TURN and PG&E agree that EETA costs should be included in the GRC. SDG&E and Edison want to include the costs in the EERA until such time when base rates are established to recover them. Consistent with D.02-09-053, EETA should be recovered through base rates in the GRC. D.02-10-062 is modified to exclude EETA costs. SDG&E and Edison should modify their ERRA tariffs to exclude costs associated with EETA. Since SDG&E's cost of service application is in the future, SDG&E should track this costs in a memorandum account for later recovery.

PG&E and TURN agree that ongoing transition costs associated with QF and PPA contracts should be recorded in a Modified Transition Cost Balancing Account (MTCBA) for later recovery from all customers. SDG&E and ORA want to record these costs in the ERRA, which tracks costs incurred by bundled customers. We agree with TURN and PG&E that these costs should not be recorded in the ERRA balancing account. TURN differs with PG&E on how to calculate ongoing CTC associated with QF and PPA contracts in view of the market benchmark established by D.02-11-022.²⁵ We agree with PG&E's method of CTC calculation, but we also note that those issues will also be more fully addressed in A.00-11-038 et al. (D.02-11-026).