XVII. Other Issues

A. Implementation of DA CRS in Coordination with Companion Proceedings

Although this proceeding is to determine the CRS for DA customers, the final implementation of the measures adopted in this order requires coordination with other proceedings before the Commission. Specifically, with respect to DA - CRS to recover costs incurred by DWR, this proceeding must be coordinated with the proceedings in A.00-11-038 et al., in which the 2003 revenue requirement for power charges and bond charges are separately being litigated. PG&E recommends that the actual DA CRS applicable to DWR costs be determined in the DWR Revenue Requirement proceeding in A.00-11-038 et al. in order to ensure that it is based on the adopted DWR revenue requirement and inter-utility cost allocation. PG&E recommends that the Commission direct DWR to perform production simulation runs to calculate DA CRS for the DWR costs as part of the DWR revenue requirement proceeding, reflecting whatever is adopted in this case with respect to methodology and applicability of charges, and consistent with the assumptions adopted concerning forecast costs and inter-utility cost allocation.

We shall direct that the final implementation of CRS for DA customers shall incorporate the actual 2003 revenue requirements for DWR power charges and bond charges as shall be adopted in the companion proceedings in A.00-11-038 et al.

For purposes of calculating the DA share DWR power charge, the historic period September 21, 2001 through Decision 31, 2002,the DWR/Navigant model be re-run utilizing the DA "in/out" cost difference scenarios, consistent with methodological approaches we adopt in this order, as discussed above, and based on the recorded information regarding the historic costs, sales, and resource utilization for this period. The information used for this modeling exercise should be consistent with any true up of this period which is included in DWR's submittal of its 2003 power charge revenue requirement in A.00-11-038 et al.

We also direct DWR to perform an updated DA in/out model run, incorporating input assumptions consistent with those underlying the 2003 revenue requirement that is being implemented in A.00-11-038 et al., and in accordance with the methodologies and policies established in today's order. When the utilities resume purchasing power on behalf of their bundled service customers, customers should still pay the same total cost for net short power at high levels of DA market penetration as they would have paid at July 1, 2001 DA levels. Thus, utility purchases will need to be incorporated in the DWR modeling calculation. The ALJ shall issue a ruling as to a schedule for DWR to file and serve the updated model run on parties to this proceeding, and for implementation workshops, in coordination with A.00-11-038 et al. proceedings, as appropriate.

ORA recommends that employee transition costs be addressed in the Annual Transition Cost Proceeding (ATCP), the proceeding where the reasonableness of these costs is normally reviewed on a retrospective basis, with actual employee transition costs tracked in a true-up mechanism. Those costs found reasonable in the ATCP could be amortized in the subsequent year's ongoing CTC rate. We shall adopt ORA's proposal.

1. Remittance of Funds to DWR

SDG&E proposes direct remittance of revenues generated by the DWR related cost component of the DA CRS to DWR with the IOUs continuing in their role as billing agent for DWR. Remitting all revenue directly to DWR allows for immediate relief to bundled customers since their DWR charges will be based on a revenue requirement reduced by expected DA CRS revenue. SDG&E proposes that the January 2003 DWR charges for each IOU service territory be designed to recover that IOU's allocated DWR revenue requirement after the DA CRS that is expected to be received from migrated DA load is subtracted from the total DWR revenue requirement. We adopt this proposal. This revenue treatment is necessary in order to make the bundled customers of all three IOUs indifferent to the stranded DWR contract costs caused by DA migration.

Consistent with the billing, collection, and remittance processes established in D.02-02-052, the IOU shall serve as the billing and collection agent for DWR revenues applicable to DA customers. The IOU shall remit collections of DWR-related revenues from DA customers to DWR consistent with the procedures in the applicable servicing agreements that are already being applied with respect to remittance of charges for bundled customer's billings.

2. Revenue Allocation and Rate Design of Non-DWR Costs

PG&E, SCE, and ORA recommend the allocation of URG costs across all bundled and incremental DA loads based on each group's share of the highest 100 hours of system loads. This is the methodology adopted in D.00-06-034 for the allocation of ongoing transition costs associated with certain URG resources. D.00-06-034 was the final Phase 2 decision issued in the Post-Transition Electric Ratemaking (PTER) proceeding, and established revenue allocation and rate design guidelines for the same costs that are now to be recovered through DA CRS component for the ongoing CTC non-bypassable charge.

CMTA agrees with the revenue allocation recommendations of PG&E, SCE and ORA. CMTA believes this same approach should be used to allocate uneconomic DWR costs as well.¹⁰⁵ Both ongoing DWR and URG costs are classic "transition costs representing the above-market costs of long-term generation resources that were built or contracted to serve all customers - both bundled and direct access."¹⁰⁶ CMTA maintains that because the costs are so similar in nature, there are compelling reasons to use the same methodology for the allocation of these costs.¹⁰⁷

The 100-hour revenue allocation methodology adopted in the Phase 2 PTER decision assigns costs to each rate class and rate group in proportion to each class' estimated total bundled and DA load during the top 100 hours of a single calendar year. The necessary allocation factors are derived using a weighted average of historic load research data from two consecutive recent calendar years (2000 and 2001), and are then rescaled to adjust for any differences between each class' share of total load during the two-year historic period relative to the test year 2003 sales forecast.

The rate design methodology for post-freeze CTC that the Commission adopted on a prospective basis in D.00-06-034, assigns all costs allocated to each rate class and rate schedule on a simple cents-per-kWh basis. PG&E argues that this approach continues to be reasonable and appropriate for setting the Ongoing CTC to be adopted for DA customers in this proceeding. Consistent with the practice already established for other similar rate components (e.g., nuclear decommissioning and public purpose program rates), PG&E recommends setting just one applicable Ongoing CTC rate for each of its principal rate classes, except that the rate would be differentiated by service voltage for those Large Light and Power customers receiving service under PG&E Schedule E-20.

PG&E proposes that the DA CRS for ongoing CTC and DWR costs paid by DA customers be subtracted from the total of all otherwise applicable generation-related charges determined for DA customers, prior to determining the capped DA credit amounts described in PG&E's proposed Schedule PE. The capping mechanism that PG&E proposed in the DA Credit proceeding is designed to ensure that future DA credits do not produce future undercollections of charges to be assessed to DA customers. By subtracting these revenues prior to determining capped DA amounts, PG&E believes it can ensure that the new charges established in this proceeding are truly non-bypassable.

ORA proposes that any revenues recovered from a non-bypassable charge for recovery of the above market URG costs applied to the DA customers be credited to the URG revenue requirement which is the responsibility of bundled service customers.¹⁰⁸ SCE agrees with this proposal.

Pursuant to the Commission and SCE's Settlement Agreement, as adopted in Resolution E-3765 and D.02-07-032, SCE will subtract the non-bypassable charges associated with recovering SCE's HPC, the DWR Bond Charge, DWR's ongoing costs, and SCE's above-market URG costs from the generation rate of DA customers' Otherwise Applicable Tariff (OAT) before it is credited to them.¹⁰⁹ This procedure will remain in place for the duration of the Rate Repayment period defined by the Settlement Agreement.¹¹⁰ After the Rate Repayment period, SCE expects that the Commission will adopt a "bottoms-up" approach to calculating SCE's rate levels, and the various non-bypassable charges will appear as separate charges applicable to all bundled service and DA customers.

Discussion

The Commission in A.00-11-038 et al. authorized that transition costs to customer classes be allocated using the top-100 hours method adopted in D.00-06-034. Once that allocation is performed, the actual CTC rate for a given class is calculated by dividing that allocation of costs to that class by the kWh sales in that class. As ORA recommends, we will adopt the top 100-hour allocation factors presented in the utilities' testimony, including PG&E's update of its estimates to incorporate line loss factor for calculating the URG component of DA CRS. (Exh. 48.)

We approve PG&E's proposed treatment of DA CRS in determining DA credit amounts. We also approve ORA's proposal to credit DA CRS revenue against bundled customers revenue requirement.

B. Process for Updating the DA CRS/ True ups and Balancing Account Treatment

Parties generally agree that it is appropriate to establish a procedural process to provide for periodic updating of the DA CRS so that cost responsibility is accurately determined and so that the effects of forecasting errors can be rectified. Parties offered different ideas as to how such an updating process should work, and coordinated with other Commission proceedings.

TURN proposes that the Commission set the initial DA CRS for year 2003 based upon a "backcast" rather than a forecast. TURN proposes that recorded data from the historical period beginning with the fourth quarter of 2001 through the third quarter of 2002 be used to determine the applicable DA CRS. Thus, the charge would be assessed on a 15-month lagged historical basis plus an interest allowance, with a balancing account to track actual revenues against the determined CRS revenue requirement. DWR would thereby need to produce revised DA in/out model runs incorporating such recorded data. The DA "in" scenario would still require a simulation providing hypothetical assumptions as to how DWR procurement would have looked if incremental DA load had remained on bundled service. TURN believes that backcasting is likely to be fraught with less complexity and controversy than forecasting entails.

CLECA proposes that a balancing account be established to perform two functions with respect to recovery of DWR forward costs from DA customers.¹¹¹ The first would be to true-up the differences between the realized and forecast levels of such variables as gas prices, spot market prices, and DA participation. The other purpose would be to track the difference in revenues recovered under the CLECA's proposed cap and the revenues that should have been recovered absent any cap.

SCE agrees with this concept, but disagrees with any proposal that an undercollection in this account should be carried forward, presumably by the utility, for the DA customers at the utility's commercial paper rate. SCE argues that by law, the amounts collected through the DWR costs are the property of DWR and not the utilities. Therefore, SCE argues that DWR should be the entity financing these undercollections. Second, at its current credit rating, SCE claims it is not possible for it to finance these balances on behalf of DA customers. Lastly, the cost of financing any balance, regardless of the entity that does it, should be entirely passed on to DA customers in order to keep bundled service customers indifferent.

PG&E characterizes the DWR charge as a simple pass-through rate that does not require the utilities to establish and administer balancing accounts. SDG&E agrees with PG&E, and does not believe that any balancing account is required or appropriate for these types of charges, since it is not SDG&E's revenues, but DWR's, that would be placed in the account. SDG&E believes the only accounting requirement should be tracking the charges and revenues associated with past and future DWR-related CRS, and that this can be accomplished through the normal accounting requirements associated with SDG&E's billing agent agreement with DWR. SDG&E anticipates it will account for the various DWR charges and the associated revenues, separately by type of charge.

PG&E proposes that the Commission simply rely upon the forecasted 2003 DWR revenue requirement, rather than separately litigate forecast assumptions for setting a 2003 DA CRS in this proceeding. PG&E proposes that the Modified TCBA (MTCBA) adopted in the PTER decision be used to track the Ongoing CTC revenues and associated costs.¹¹² The MTCBA will track the cost components for QF, PPA, and employee transition costs in a fashion similar to the Post-2001-Eligible Costs section of the current TCBA. There are specific line items dedicated to each of these components. PG&E argues that nothing more complex is needed.¹¹³

PG&E argues that if a market measure is adopted to identify the portion of QF and other PPA costs that is to be considered ongoing CTC, then the resulting split should not be readjusted after the fact. Forecasts are regularly used by the Commission to allocate costs between classes and categories of customers. The Commission typically trues up cost forecasts for those costs that are largely outside the utility's control. But it rarely if ever trues up allocation forecasts, and should follow that same approach here. PG&E thus believes it would be more consistent with Commission practice to maintain the original cost allocation, and not perform any cost allocation true-up.

ORA also proposes the establishment of a balancing account, similar to the Transition Cost Balancing Account (TCBA), to compare the revenues received from the non-bypassable charge and the actual above market costs. Any over- or under-collection in any given year will be amortized in the rate for the following year.

SCE agrees with ORA's proposal except that no true-up should take place for the realized market price. ORA's proposal to true-up for the market price in addition to the URG costs and sales variations may be a by-product of its proposal to use DWR's forecast of spot market prices as the market benchmark. SCE's proposal to use a forward contract price with a profile similar to that of the URG output makes the market benchmark true-up unnecessary.

Discussion

We agree that an annual process is necessary to update and true-up the forecasted data underlying the DA CRS. Regular periodic true ups and updates of the DA CRS are essential to assure that the charges remain accurately aligned with more contemporary information on costs. This updating process is particularly important to ensure that any benefits derived from renegotiating more favorable terms and conditions on DWR contracts are passed through in CRS. We shall, therefore, require that the process for true-ups and updates of the DA CRS be conducted as a part of the annual DWR revenue requirements update proceeding which is currently docketed in A.00-11-038 et al. To the extent, if any, that DWR comes before the Commission for updates of its power charges more frequently than annually, any such updates shall take into account relevant DA CRS adjustments as well.

In D.02-02-052, the Commission has previously established procedures for DWR to make at least annual submissions to Commission to true up and update the applicable DWR power charges to be collected from customers. Those procedures already call for DWR to include a true up of prior period differences between forecast and actual data. We shall clarify through this order that the data submitted by DWR relating to its true up must also include requisite detail relating to costs and revenues attributable to DA load. In order to perform the true up, a back cast will need to be performed to model the difference in costs between a DA in/out scenario, along the lines of the approach that parties have used in this proceeding.

Parties expressed differing views in this proceeding concerning how a backcast might be constructed, and exactly what variables should be subject to revision in any backcast. A backcast of a DA "in" scenario requires that assumptions be made as to how DWR procurement costs would have been different if incremental DA load after July 1, 2002 had remained as bundled load. We believe that further conceptual development would be in order concerning how the backcast should be performed. We direct the ALJ to develop a further process through workshops or other appropriate forums for parties to develop protocols for a backcast process.

In D.02-02-052, we also directed the utilities each to establish balancing accounts to track revenues remitted to DWR and to segregate associated sales of URG power versus DWR power. As an additional accounting requirement, we require in today's order that each utility further segregate the tracking of revenues remittances to DWR to distinguish between DA and bundled customer collections and remittances. This segregation shall be particular important to ensure that there is no cross subsidization between bundled and DA customers with respect to the true-ups.

We order that the updating and true up of the DA CRS shall occur as a part of the DWR annual revenue requirement update. We also decline to adopt TURN's proposal that a backcast be used to set the DWR component of the DA CRS for 2003. A backcast approach would build in an ongoing disparity between the treatment of bundled versus DA customers with respect to the time frame underlying the DWR power charge. In the interests of bundled ratepayer indifference, both bundled and DA customer charges should be set based on application of a consistent measurement period. Since the forecast of DWR 2003 revenue requirement is being determined in A.00-11-038 et al., we will simply rely upon the forecast assumptions implemented in that proceeding for use in determining DA CRS. Another problem with TURN's backcast approach is that it fails to provide for a full accounting of DA cost responsibility. The backcast approach would establish charges only for previously incurred costs through 2002, but there would be no concurrent charges to compensate for prospective 2003 costs. A full accounting of cost responsibility requires that charges be established both for previously incurred costs through 2002, as well as ongoing charges to recognize prospective costs beginning in 2003. To the extent that any of these charges exceed allowable rate caps, appropriate interest charges must be assessed to account for the time value of money.

C. Billing and Tariff Implementation

Implementation of the DA CRS will require changes to a number of the utilities'tariffs. The specific changes to the tariffs can be determined following completion of the compliance workshops to compute the DA CRS cost elements, as prescribed elsewhere in this order. We direct the utilities to file compliance advice letters with all of the required tariff modifications that are necessary to implement DA CRS following completion of the compliance implementation workshops.

D. TURN's Proposal to Include the Costs of the Interruptible Program in the Distribution Component of Rates

TURN and other parties propose moving the costs of the interruptible program into distribution rates.¹¹⁴ PG&E agrees that distribution rates should be modified to include the cost of the non-firm program, as directed by D.00-06-034 (Ordering Paragraph 14) in the Post-Transition Electric Ratemaking proceeding. Placing these costs in distribution rates ensures they are not avoided when a customer elects direct access. In accordance with that decision, PG&E expected the costs of the non-firm program, rate limiter adjustments, and power factor adjustments to be incorporated in distribution rates at the same time "bottoms-up" billing was implemented. PG&E asks that if the Commission adopts this proposal, it indicate when it would like this change made. We hereby adopt TURN's proposal. The assigned ALJ shall set a schedule to take comments as to the timing and manner of implementation.

E. Negative CTC

SCE argues that transition costs should never be negative and that a customer should not be paid for taking service, nor should the utility be placed at risk for recovery of its authorized revenue requirement, because of some unusual set of circumstances that result in an anomalous rate. (Exh. 22, p. 7.) The other two utilities did not address this issue as directly. PG&E, however, omits from its calculation elements of transition costs (i.e., irrigation district contracts) that could cause the CTC rate to become negative.¹¹⁵ SDG&E's proposed accounting limits the credit to the TCBA from below market resources, meaning that CTC could only become negative if the CTC rate itself the previous year had been based on a forecast of market prices that turned out to be too high. (Exh. 56, pp. 4-6.)

ORA argues, however, that not allowing negative CTC seems to go against the netting principle articulated in Section 367(b). It states that CTC must be based on a calculation mechanism that net the negative value of all above market utility-owned generation-related assets against the positive value of all below market utility-owned generation related assets. ORA views SDG&E's proposed accounting mechanism as a partial, but not complete, implementation of this netting principle. (RT. 8, 1129, Danforth/ORA.) It does allow credits from below market CTC eligible resources to offset the costs of above market CTC eligible resources. But that credit is limited if the credit becomes large enough to create an overcollection in the TCBA, necessitating a negative CTC rate in the following period to amortize.

Though all three utilities appear to have concerns about negative CTC, only SDG&E advanced a tangible accounting mechanism that would deal with this issue. SDG&E's proposal for the netting process was described very briefly in one paragraph of witness Schavrein's testimony, and ORA had difficulty understanding SDG&E's proposal. The implications of the proposal have not been fully explored. Moreover, a further record would need to be developed on how the accounting would be done for PG&E and SCE.¹¹⁶ Since it is probably unlikely that CTC will become negative this coming year, ORA recommends that the Commission take more time to evaluate SDG&E's proposal, and also allow other parties to make their own proposals. We concur with ORA's recommendation. This issue will be taken up in a subsequent phase of this proceeding, or in another proceeding as designated by further ruling.

F. Rescission of the One Cent Surcharge from D.01-01-018 as Applicable to Direct Access Customers

In D.01-01-018, the Commission instituted what was called a temporary surcharge of a cent per kilowatt hour. As the Commission explained, "The increase will be a temporary surcharge to improve the ability of the applicants to cover the costs of procuring future energy in wholesale markets that they cannot produce themselves to serve their loads." (Id., mimeo., As we discussed earlier, issues related to the impact of AB 6X and AB 1X on AB 1890 and Section 367(b) are being considered in A.00-11-038 et al. In other words, the reason for the surcharge was to pay for energy. The Commission applied that surcharge to direct access customers, even though such customers were not receiving generation service from the utilities.

The Commission later instituted an additional three cent per kilowatt hour surcharge, but noting that direct access customers did not receive generation service from the utilities, exempted direct access customers from that surcharge. (D.01-05-064, mimeo, p. 28.)

At this point, the utilities serve bundled customers with their URG, and receive payment through normal rates. Bundled customers also receive power from DWR. Direct access customers are provided generation from neither source, although it seems quite clear that the payment by direct access customers of the one cent surcharge to date has helped defray DWR generation costs. Upon institution of CRS, direct access customers will pay what amounts to a dedicated charge component to pay for their share of DWR's power purchase program.

CIU claims there is no justification to continue the one cent surcharge after CRS commences, since it pays for generation and direct access customers will be fully paying for generation through their own contracts and CRS. CIU also claims that in calculating CRS, the Commission must provide credit to direct access customers in some way for a portion of the one cent surcharge they have been paying since January 2001, arguing that a portion of the one-cent should have gone to pay for DWR power, and not to include such a credit would result in double recovery from direct access customers.

SCE asserts, however, that it has not been assessing DA customers the 1 cent/kWh surcharge since June 3, 2001, making CIU's request to exclude SCE's DA customers from the 1 cent/kWh on a prospective basis moot. The advice letter implementing SCE's tariff changes authorized in D.01-05-064, Advice No. 1545-E, proposed to exclude DA customers from both the 1 cent and 3 cents/kWh surcharge.

SCE argues that CIU's recommendation to credit DA customers for the amount of the 1-cent/kWh surcharge they paid from January 2001 to June 2001 should be rejected. That surcharge was adopted by the Commission in D.01-01-018, and was appropriately assessed to DA customers until the Commission set forth its rationale for exempting DA customers from the 3 cent/kWh surcharge and SCE filed Advice No. 1529-E to modify it calculations of the Power Exchange (PX) credit to DA customers. SCE argues that excluding those customers from the 1-cent/kWh surcharge, as of January 2001, would violate the prohbititon against retroactive ratemaking. SCE relies on Public Utilities Code Section 728 and case law to make the following argument: Public Utilities Code Sectin 728 provides that when the Commission finds, after holding a hearing, that the rates charged or collected by a public utility are "insufficient, unlawful, unjust, unreasonable, discriminatory, or preferential, the commission shall determine and fix, by order, the just, reasonable, or sufficient rates, classifications, rules, practices, or contracts to be thereafter observed and in force." In Pacific Telephone and Telegraph Company v. Public Utilities Commission, the California Supreme Court annulled a Commission decision that ordered Pacific Telephone and Telegraph Company (Pacific) to refund amounts collected pursuant to its tariffs.

The Court noted: "The Legislature has instructed the commission that after a hearing it is to make its order fixing rates to be in force thereafter."¹¹⁷ The Commission does not have the authority to order refunds of amounts collected by a public utility pursuant to approved rates.¹¹⁸ Thus, SCE argues that to retroactively alter rates charged or collected by IOUs is thus prohibited. Accordingly, SCE argues that CIU's proposal to retroactively exclude DA customers from the 1 cent/kWh surcharge should be rejected.

PG&E argues that the CIU proposal is beyond the scope of this proceeding and so should be rejected. The issue is currently before the Commission in another forum. AReM specifically protested this aspect of PG&E Advice Letter 2119-E, which established the average 3-cent-per-kWh generation surcharge in accordance with D.01-05-064 and required direct access customers to pay the 1-cent-per-kWh generation surcharge. The advice letter is still pending.

In fact, in the DA Credit proceeding, PG&E proposed to include the currently-excluded 3-cent-per-kWh surcharge¹¹⁹ in the calculation of DA customers' rates. That proposal was stricken from the proceeding.¹²⁰ CIU's proposal in this proceeding, made with no citation to the record, PG&E argues that it should therefore be disregarded.

Discussion

Since in the case of PG&E, the matter is already before us in a pending advice letter, this proceeding is not the proper place to resolve the issue. Further, we agree that CIU's request for a prospective adjustment is moot, at least with respect to SCE, since the charge has been removed since June 2001. Thus, no further disposition of the matter is warranted at this time.

G. PG&E's WAPA Contract

TURN argues that the costs of the WAPA contract should be included in the CRS. The WAPA contract provided significant benefits to ratepayers 20 or 30 years ago, when WAPA provided cheap power to PG&E. Now the situation has reversed, and PG&E must provide cheap power to WAPA at $22.21/MWh between now and the expiration of the contract in 2004. The contract's net costs were included in rates in 1996 and TURN thus argues that the costs are reasonably part of tail CTC. If the costs are not assigned to direct access customers, TURN argues, it is equivalent to making the unfair assumption that WAPA is supplied entirely with URG while bundled service customers must buy the DWR power.

While the contract constitutes "tail CTC," TURN argues that the appropriate valuation of the obligation is intimately tied to the DWR charges because PG&E is currently buying the power to supply WAPA from DWR as part of the net short. Its costs, therefore, must be calculated here and assigned to all customers.

Unlike the DA CRS, TURN argues that the WAPA contract should be paid for by all direct access customers, including those who were not on the system at any time after January 17, 2001. TURN divides the WAPA charge in to (1) a shortfall fee through September 30, 2001, which is part of the DWR bonds and could therefore be financed, and (2) ongoing obligations through 2004.

The existing calculation method for the rate shortfalls before September, 2001 include a pro rata share of WAPA shortfall costs for customers who moved from bundled service to direct access, but they do not include costs assignable to direct access customers who stayed on the system. The shortfall fee is calculated at $1.26 per MWh of total PG&E direct access load based on actual WAPA sales during the period from January-September, 2001, using DWR's financial assumptions.

PG&E agrees with TURN that DA customers should be responsible for a share of the costs associated with the sale of power to WAPA at very low rates. In addition, TURN appears to agree with PG&E that one would use a portfolio price to determine the amount to include in the ongoing CTC determination for power provided to WAPA.¹²¹ PG&E concurs with TURN's proposal to do a separate, post-indifference calculation adjustment to rates.¹²²

TURN further proposes that WAPA costs be included on a lagged, actual cost basis.¹²³ PG&E disagrees with this proposal. When the Energy Cost Adjustment Clause (ECAC) was in effect, WAPA costs were treated like other costs, with WAPA costs forecast to set ECAC rates, and actual WAPA costs recorded in the balancing account. There is no sound basis for building a lag into recovery of these costs. Actual costs are what will be recovered in any event.

Discussion

We adopt TURN's proposal to include the costs of the WAPA contract in the CRS calculation. As noted by PG&E, one would need to incorporate not only the WAPA revenues into ongoing CTC (as is proposed by PG&E), but also some estimate of the cost of the power being provided to WAPA in order to put TURN's proposal into effect.

Currently, DWR is providing the power to meet the WAPA contract, in the sense that DWR is providing the power to meet PG&E's net open position, and PG&E's obligations under the WAPA contract increase PG&E's net open position. However, in reality a portfolio of power is meeting the needs of PG&E's bundled customers, as well as its WAPA obligations.

Therefore, if TURN's proposal were adopted, PG&E suggests using an average portfolio price to calculate the WAPA component of ongoing CTC. The cost would be recorded as the adopted portfolio price multiplied by actual WAPA volumes, and that same amount would also be recorded as revenue against PG&E's bundled customers' costs of power. We concur with the approach suggested by PG&E. We direct that in the final calculations to compute the appropriate 2003 costs to include in the CRS for PG&E that WAPA costs be included on this basis.

H. Additions to DA List

Strategic Energy asserts that the suspension decision should be "clarified" so that some additional customers can be added to the "October 5" list; and second, Strategic Energy argues that the switching exemption should be "modified" to allow chain retailers to add additional contracts to existing DA contracts. These implementation issues are beyond the scope of this proceeding, and so they should not be addressed here.¹²⁴

Strategic Energy has not provided any record evidence to support its recommendations to expand the scope of allowable migration to DA, and the Commission should not adopt such changes without ample supporting evidence.