IV. Other Ratemaking Issues

Devers Palo Verde 2 (DPV2) is a transmission project Edison abandoned before completing construction. The cost of the abandoned project is $6.704 million. Pursuant to D.97-11-073, Edison entered the amount into its ERAM, now TCBA, for recovery in rates. The $6.704 million was subject to refund pending the FERC's review of the costs. FERC subsequently approved $3.352 million of the costs for recovery in transmission rates and found that the remaining costs of the plant should be assumed by Edison's shareholders. By Advice Letter 1301-E, Edison asked the Commission to include the $3.352 million in transmission rates that FERC approved for the project. Resolution E-3547 approved the amount in the transmission portion of Edison's rates, consistent with D.97-11-073 and the FERC decision.

In this proceeding, Edison seeks recovery of $3.352 million in costs associated with DPV2, which have been disallowed by the FERC. TURN opposes Edison's request here for recovery of the amounts the FERC disallowed and allocated to shareholders. The Commission, TURN argues, should not include in rates costs which a federal agency has disallowed. DGS makes similar comments in its reply brief.7

Edison's request to recover funds disallowed by the FERC is effectively a request that we vacate the order of a federal agency. We could only approve Edison 's proposal here by ignoring the FERC's explicit requirement that shareholders assume liability for half of DPV2-related costs. While the Commission did state in D.97-11-073 that "If the FERC does not permit them to be included in transmission rates, we will permit their recovery in Commission jurisdictional rates..." (mimeo, p. 11), in our view, FERC did permit recovery of these costs based on precedent of only allowing 50% recovery for canceled plant costs. We decline to take action in defiance of a federal order for costs that are subject to FERC's exclusive jurisdiction. Moreover, we never intended that Edison would recover transmission costs in distribution rates or other CPUC-jurisdictional rates. Edison does not demonstrate or even argue that the subject costs are anything but transmission costs. D.97-08-056 stated our uncontested view that "FERC will have sole responsibility to set transmission revenue requirements" and deference to the provisions of § 368(b) requiring "the identification and separation of individual rate components such as charges for energy, transmission, distribution, public benefit programs, and recovery of uneconomic costs." By including transmission costs in any other rate, Edison would ignore this requirement of AB 1890 and our decision. Edison shall reduce its TCBA $6.704 million and may continue to recover the $3.352 million approved by the FERC and included in its transmission rates.

All three applicant utilities include in their CTCs those costs relating to "reliability must run" contracts. RMR generation costs arise from contracts entered into by the ISO with all types of generation providers for the purpose of ensuring the reliability of the transmission system.

Enron argues that including RMR costs in the CTC gives customers the false impression that the costs will be eliminated at the end of the transition period, although they are ongoing. Enron proposes that the Commission require the utilities to unbundle these costs and include them on customer bills as a separate rate component.

Edison opposes Enron's recommendation, arguing that the Commission has already resolved the issue in D.97-12-109. Edison believes it cannot readily implement an alternative to the existing convention prior to the end of the transition period. It comments that these costs will be included in transmission rates at a later date. PG&E makes similar comments.

We will not require the development of a separate rate element at this time, as Enron proposes, because it may cause additional customer confusion without creating offsetting benefits. As we stated in D.97-12-109, RMR costs are those associated with either transmission or generation. They are currently recovered through a separate accounting in the TRA. After the transition period ends, however, we will have no jurisdiction to set transmission rates. The utilities will need to take steps to recover the amounts by way of transmission rates. Alternatively, we will consider including the costs in generation rates, depending on whether and how we set those rates, if the utilities are able to demonstrate that the costs are related to generation.

SDG&E proposes to eliminate certain residential and small customer rate options, effective at the end of the rate freeze period. Enron supports SDG&E's proposal on the basis that the utilities should not provide optional rates schedules.

ORA objects to SDG&E's proposal, arguing that the Commission has not yet determined the extent to which a utility should be required to offer various rate options to small customers. ORA would defer the matter to SDG&E's post-transition period ratemaking application.

The utilities have filed post-transition period ratemaking applications in which we will consider limited rate design following the transition period. SDG&E has proposed a comprehensive rate design proceeding at a later date. We decline to consider the matter piecemeal here and accordingly deny SDG&E's request to eliminate rate options for small customers effective at the end of the transition period.

SDG&E has collected about $8 million more than its costs in various balancing and memorandum accounts and proposes to credit the TRA accordingly. The accounts in question track Demand Side Management (DSM), Research, Development and Demonstration (RD&D) and CARE costs and revenues prior to January 1, 1998. Specifically, SDG&E would offset a $28 million shortfall in the industry restructuring memorandum accounts, the DSM pilot bidding program and a handful of smaller accounts with a $35 million over collection in DSM, CARE, and RD&D accounts. Alternatively, SDG&E proposes to transfer the overcollections to the TCBA to reduce transition costs.

ORA opposes SDG&E's proposal to aggregate balances because doing so would allow SDG&E to recover certain costs for which it has not received approval. ORA prefers that the Commission defer the disposition of overcollections to the Energy Division's pending review of existing account balances.

We agree with ORA that this proceeding is not the appropriate forum to consider the reasonableness of the costs in these accounts. We are also concerned that SDG&E's proposal as it is presented may overlook the requirements of Section 367 which, as we have found previously in this decision, limits the Commission's discretion with regard to changes in cost allocation between customer groups. Specifically, SDG&E recovered the CARE, DSM and RD&D costs on an equal cents per kilowatt hour basis, consistent with the cost allocation method in effect on June 10, l996. To refund the amounts according to the cost allocation method used for the TCBA would constitute a change in cost allocation method. The cost allocation method applied to the TCBA is EPMC. In our discussion regarding restructuring implementation costs, we found that Section 367 does not permit a change in cost allocation from past practice even for those costs which are not specifically identified as transition costs. This interpretation is consistent with SDG&E's view on the matter. SDG&E's proposal as presented may also violate Section 381, which requires that public purpose funds are not "commingled with other revenues."

In order to comply with the Section 367 and Section 381, we will permit SDG&E to transfer the balances to the TCBA but require SDG&E to refund the amounts in proportion to how they were collected from each customer group. Therefore, SDG&E would credit its RGTCOMA subaccounts using the equal cents per kilowatt hour method of cost allocation.

In addition, the reasonableness of the costs remain subject to review, audit, and potential disallowance even though we authorize this transfer. We are comfortable with this approach because, if disallowances were identified, such disallowances would only serve to increase the amount of overcollection, thus increasing the amount transferred to the TCBA. With these conditions, we see little risk to ratepayers of authorizing transfer of existing overcollections at this time.

PG&E proposes the creation of a new memorandum account for tax liabilities. TURN opposes it on the basis that it is "a remnant of the era of balancing account ratemaking" and therefore contrary to the Commission's current ratemaking policy.

As TURN observes, PG&E may gain or lose in any given category of costs. We decline to create new balancing accounts to shield the utilities from the risks that all businesses must assume, such as those relating to changes in tax law. We reject PG&E's proposal to create an Incremental Tax Memorandum Account.

Enron recommends that Edison be required to remove from the TRA costs associated with inter-utility contracts and resale city wholesale contracts. Edison agrees that it inappropriately included those costs in the TRA and will adjust the TRA accounts accordingly.

Enron recommends that each utility use the same methodology for calculating residual revenues transferred to the TCBA. Edison and PG&E reply that each utility is performing the calculation in compliance with Commission-approved tariffs. We agree that the Commission may have adopted slightly different methods for calculating the TCBA revenues. We find no compelling reason to change them here in order to make them consistent across the utilities.

7 TURN argues that the TCBA should be adjusted by $6.704 million to avoid double recovery of the amounts associated with the project. Edison would reduce the TCBA $3.352 million so as to allow it to recover the amounts disallowed by FERC.

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