III. Evidentiary Hearing

ERRA issues litigated between SCE and the Office of Ratepayer Advocates (ORA) during the September 3, 2003 evidentiary hearing were Nuclear Unit Incentive Procedure (NUIP) rewards, the interest rate applicable to over- and under-collected balances,² and the semiannual schedule. Not at issue were SCE's revenue requirement forecast and trigger mechanism setting its trigger and threshold amounts for 2003.

A. NUIP Reward

SCE seeks to recover $19.2 million of NUIP rewards in this forecast proceeding. This request is opposed by ORA on the basis that the rewards are not based on a forecast, the intended purpose of this proceeding. The rewards are based on recorded performance.

1. Appropriate Issue?

ORA recommends that this issue be deferred to SCE's October ERRA application which will involve a reasonableness review of energy recorded costs.³ ORA concludes that this deferral would provide it and other interested parties notice and an opportunity to review the reasonableness of NUIP awards.⁴ However, if the NUIP rewards is addressed in this proceeding, ORA recommends that SCE be authorized only $14.1 million of its requested $19.2 million amount.

As detailed in the application, SCE served a copy of this application on the entire service list in the Commission's Generation Procurement Rulemaking (R.) 01-10-024 proceeding and in its Post-PROACT ratemaking Application (A.) 03-01-019. Further, no party objected to addressing this issue at either the May 21, 2003 or July 18, 2003 PHC. ORA even went so far as to recommend an alternative NUIP rewards amount in the evidentiary hearing.

Further, SCE's authorized tariff provides for the debiting of NUIP rewards to its ERRA upon Commission approval.⁵ Although the tariff does not identify the specific proceeding that SCE should seek such approval, it does provide for NUIP rewards to be included in SCE's ERRA upon Commission approval.

The above discussion demonstrates that all parties were notified that the NUIP rewards issue would be litigated in this proceeding, did not object at the PHC to include NUIP rewards as an issue, an alternative rewards amount was proposed by ORA, and SCE's tariff provides for the inclusion of rewards in its ERRA. The issue of NUIP rewards is properly before us.

2. Reasonableness

By way of background, SCE's Palo Verde units performing above an 80% capacity factor for a fuel cycle are eligible for NUIP rewards.⁶ The rewards, based on the difference between the additional cost per kilowatt-hour (KWh) of nuclear fuel and the replacement power cost of the output above an 80% capacity factor, are shared equally between SCE's customers and shareholders.

During the period that the Power Exchange (PX) was operational (through January 2001), SCE used the average monthly price it paid the PX for energy SCE purchased for bundled service customers as its replacement power cost. Beginning in February 2001 and throughout 2002, SCE used the California Department of Water Resources (DWR) rate adopted in D.02-03-052 for recovery of DWR procurement costs that it purchased for SCE's retail customers as the replacement power cost.

In D.02-02-052, the Commission-adopted a 9.706¢ per KWh rate that SCE's customers were obligated to pay DWR for energy DWR supplied SCE during 2001 and 2002. Since the replacement power cost for all NUIP fuel cycles was greater than the five-cents-per-KWh cap set in D.01-09-041, SCE limited its replacement power cost to that amount.

ORA used California Independent System Operator's (CAISO) market clearing prices as a reasonable proxy of DWR's then-actual prevailing market prices for incremental cost of energy. Hence, the $5.1 million difference in NUIP rewards between SCE and ORA resulted from the use of different replacement power cost.

All power not supplied by SCE during this time period would have been supplied by DWR with an energy portfolio based on long and short-term purchased energy, only a portion of which was purchased through the CAISO. Of the two calculations, SCE's five-cent-per-KWh cap cost more accurately reflects the cost SCE's customers actually paid. Because the cost of energy from DWR during the NUIP rewards period may change after a true up is completed in A.00-11-038, et al. SCE should be authorized to debit its ERRA with $19.2 million of NUIP rewards subject to the results of a DWR 2001-2002 energy cost true up pending in A.00-11-038, et al.

B. Interest Rate

SCE seeks to change the short-term interest rate applicable to its undercollected and overcollected balances in the ERRA. The current interest rate for balancing account over- and under-collections is the three-month commercial paper rate as reported in the Federal Reserve Statistical Release H-15 (index).

SCE seeks a deviation in the index because its actual short-term financing cost is substantially higher than the index. Since May 2002 its actual short-term financing cost has exceeded the index by more than 300 basis points. SCE estimates that its weighted average short-term financing cost in 2003 will be 4.48%,⁷ more than 300 basis points⁸ greater than the average index rate of 1.39%.⁹

1. Appropriate Issue?

ORA opposes any deviation from the index on the basis that it would constitute a major policy change affecting ratepayers of all regulated utilities. It also opposes the deviation because SCE did not identify any procedure for verifying that SCE will minimize its financing costs and maximize benefits. ORA recommends that this issue be deferred to either a separate SCE application or to a Commission instituted rulemaking proceeding.

This issue was identified in SCE's proposed testimony attached to its application and discussed at the July 18, 2003 PHC. At that PHC, which ORA participated in, SCE agreed to limit its interest rate proposal to its ERRA balancing account.¹⁰ All parties were aware of this issue. For these reasons, the interest rate proposal is properly before us.

2. Interest Rate

SCE has been precluded from issuing commercial paper since December 2000 because of its low credit rating. Its current BB credit rating precludes it from issuing commercial paper now or in the foreseeable future. SCE does not expect to be able to borrow at the commercial paper rate until its credit rating improves to a BBB+.¹¹ Absent its ability to issue commercial paper, SCE uses a $700 million term loan and $300 million revolving line of credit for its short-term borrowings. The term loan carries an interest rate of the London Interbank Offered Rate (LIBOR) plus 300 basis points. The revolving line of credit carries a commitment fee of 50 basis points on the unused portion of the loan and an interest rate of LIBOR plus 250 basis points on the amount actually drawn at any time.

SCE will not have an opportunity to recover its actual cost of financing undercollections if it is required to use the index while its short-term financing cost continues to exceed that index. Hence, an adjustment to the index may be warranted.

This issue of using actual financing cost is not new. It was previously addressed in a generic Commission investigation (Order Instituting Investigation (OII) No. 56 on August 14, 1979). At that time SCE's actual short-term financing cost approximated the index while SDG&E's actual short-term financing cost was higher than the index.

In D.91269 we concluded that the index was appropriate for over- and under-collected balances.¹² Except for SDG&E, that decision authorized the major utilities to use the index for over- and under-collected balances. In recognition of its higher short-term financing cost, SDG&E was authorized a 50 basis point premium above that index.¹³ Hence, any deviation from the index to recognize SCE's higher long-term debt cost in this proceeding would not constitute a major policy change as asserted by ORA.

The index and premium to that index was authorized in lieu of the utilities' actual short-term financing cost to provide the utilities an incentive to minimize undercollections and interest expense. Use of the index also deters a utility from investing in undercollections to the extent that it can recover more than its authorized rate of return. At the same time, it does not remove the utility's opportunity or risk associated with actual interest rates being lower or higher than authorized.

This interest rate issue can best be resolved by reducing undercollections. That can be accomplished through the mitigating factors incorporated into the ERRA process. Those mitigating factors include more accurate forecasts, ability to change rates as part of the semiannual ERRA applications, and utilization of the trigger mechanism for more frequent rate changes. Irrespective, over- and under-collections will occur.

SCE should have an opportunity to recover its short-term cost in financing undercollections. At the same time, SCE ratepayers should have an opportunity to benefit from SCE's short-term investment of overcollections. Consistency and fairness requires use of the same process (an index or actual cost) for both over- and under-collections.

Given that utility funds are commingled for a multitude of purposes, any consideration of using SCE's actual short-term financing cost would at the very minimum require SCE to demonstrate that it actually did not have access to or use lower cost funds for other utility purposes and that it actually accessed its short-term borrowings to finance undercollections. For overcollections, SCE would at the very minimum need to demonstrate where it actually invested overcollections, whether in three-month commercial paper, rate base or other uses and at what interest rate. For both over- and under-collections, SCE would also need to demonstrate that it prudently utilized the mitigating factors discussed above. This verification of cost and investments would be time consuming for both SCE and ORA and unnecessarily detract from our intended simplified ERRA process. It could also be construed precedent setting for all utilities and all balancing accounts. Any consideration of using actual short-term financing of undercollections and actual investment of overcollections should more appropriately be addressed in a generic proceeding. For these reasons we reject SCE's proposal to replace the index with its actual short-term financing cost for ERRA undercollections and actual investments for overcollections. We opt for the index or a variation of the index as adopted in D.91269.

A comparison of the index to SCE's short-term financing LIBOR base cost shows that the spread in rates is not materially different. For example, the September 2003 index is approximately 1.1% and the LIBOR rate for that same period is approximately 1.2%, of which official notice is taken. Hence, SCE's short-term financing rate is higher than the index due to the basis points premium it pays for using its term loan or revolving line of credit.

Consistent with the index variance approach previously adopted for SDG&E in D.91269, a variance to the index should be adopted for SCE. This is true even though SCE's credit rating was upgraded by Moody's and Standard & Poor's subsequent to the filing of reply briefs in this proceeding, because SCE has not yet been able to issue any commercial paper. Since the index and LIBOR rates are comparable in 2003, that variance should be based on the premium SCE pays for using its short-term financing. It should be set at a level that fairly compensates SCE for its higher short-term cost while at the same time provides SCE with sufficient incentives to minimize undercollections, deters it from investing in undercollections, and utilizes the mitigation factors discussed above.

Based on informed judgment, that index variance should be set at three-fourths the spread between the index and SCE's actual cost of short-term financing. This variance should continue for undercollections until the spread is reduced to 50 basis points or less or until SCE can again issue commercial paper. At that time the interest rate should revert to the index. The interest rate for overcollections should continue to be set at the index rate.

C. Semiannual Schedule

SCE proposes that its semiannual ERRA applications be filed on April 1^st and October 1^st, consistent with the dates set forth in D.02-10-062. It wants a forecast phase in its April application so that it can update its ERRA revenue requirement for that calendar year with the goal of a June decision so that new rates may become effective July 1^st.

SCE wants its October 1^st filing bifurcated. The first phase would address its next calendar year's revenue requirement forecast with the goal of a December decision so that new rates may become effective January 1^st of the following year. The second phase would be a reasonableness review of the preceding twelve months (July through June) recorded ERRA operations, Utility Retained Generation (URG) expenses, contract administration, and least-cost dispatch operations. Its goal is to have a decision in this second phase issued in May of the following year.

SCE further proposes that the second phase of its October application be designated the proceeding to facilitate the consolidation of all SCE regulatory mechanisms and a reasonableness review of those mechanisms and true up of associated rate levels.

1. Forecasts

SCE's proposal for two forecasts each year was opposed by ORA on the basis that D.02-10-062 provides for only one forecast a year.

a. Transition Year Forecasts

Irrespective of different positions on the number of forecasts for each year, ORA concurred with SCE that two forecasts should be allowed in the 2003 ERRA transition year, a 2003 forecast in this proceeding and a 2004 forecast in the October application.

With the year 2003 almost completed, we concur with SCE and ORA. Two forecasts should be approved for SCE's initial ERRA year, one forecast for 2003 as requested in the current application and one for 2004 as requested by SCE in its October ERRA application.

b. Number of Future Forecasts

SCE and ORA's forecast recommendations were based on their individual interpretation of D.02-10-062. SCE relied on a table in that decision addressing "A comparison of the ECAC and the recommended (emphasis added) ERRA..."¹⁴ for providing two forecasts each year. ORA relied on a table in the decision that describes"... the semiannual update process that we establish (emphasis added) for fuel and purchased power forecasts and the ERRA mechanism" ¹⁵ for limiting the number of forecasts to one each year. That process included a requirement that SCE file an April application proposing to establish an annual (emphasis added) forecast.

ORA also relied on Finding of Fact No. 25 of that same decision. That finding states that an annual update process should be adopted for forecasts and another proceeding to review balancing accounts, URG expenses, contract administration and least-cost dispatch. ORA also opposed semiannual forecasts on the basis that two forecasts each year would create unnecessary duplicative procedures and place additional work on ORA.

The ERRA process established in D.02-10-062 (and relied on by ORA) takes precedence over any process being recommended (and relied on by SCE) in that same decision. Hence, the ERRA schedule should provide for an annual forecast as set forth in the table ORA relied on and Finding of Fact No. 25. SCE's ERRA applications should provide for only one forecast and one reasonableness review each year.

c. Appropriate Semiannual Application

Which semiannual application should be used for addressing future forecasts? SCE's witness testified that SCE forecasts its energy cost often, sometimes on a daily basis.¹⁶ This process demonstrates a high degree of difficulty in accurately forecasting future costs. However, that witness also testified that the annual estimate SCE uses for its official budget is "locked in stone."¹⁷

Given that SCE does not change its official budget, it is not appropriate to adopt a subsequent year's forecast in SCE's first semiannual ERRA application. That is because the first semiannual application is scheduled for filing in April, eight months prior to the subsequent year and well before SCE's adoption of an annual budget for the subsequent year. To enable us to adopt a more accurate and realistic forecast, SCE should use its October ERRA application for seeking approval of subsequent forecasts. Dependent on the outcome of November 8, 2003 proposed decisions in the Commission's Generation Procurement OIR, R.01-10-024, that October filing date may be changed to August 1^st.

2. Reasonableness Review

We next address SCE's proposal to bifurcate its October application. ERRA was adopted with the intent of providing the utilities more frequent opportunities to adjust energy rates than they had under the ECAC process. The intent, in part, was to adopt a process that balanced the need to adjust rates more frequently with utility and staff time. The result of that balance was an ERRA process providing for semiannual applications with semiannual decisions. A trigger mechanism was also authorized so that more frequent rate changes could be made upon an established need.

Although SCE proposes to use its October ERRA application for a reasonableness review and approval of its subsequent year's forecast, it proposes no action on the reasonableness review after its forecast has been approved. This bifurcated approach effectively changes the semiannual application process to a triennial process requiring three separate decisions. It also extends the lag in truing up its forecast and actual energy costs. For example, SCE has requested a reasonableness review of its September 1, 2001 through June 30, 2003 costs in its October 2003 ERRA application with a decision not expected on the reasonableness review until May 2004. This equates to a ten-month lag in truing up energy costs, from the June 30, 2003 actual energy cost under review to a May 2004 scheduled decision.

Consistent with the intent in D.02-03-052 for an annual update process for forecasts and another proceeding for a reasonableness review, we reject SCE's proposal to bifurcate its October ERRA applications. Having already concluded that energy forecasts should be addressed in the October ERRA application, its reasonableness review should be addressed in its April ERRA application.

Given that SCE has already filed its October application, the Administrative Law Judge (ALJ) assigned to that proceeding should have latitude in deciding whether that proceeding should be bifurcated to address reasonableness of SCE's energy costs through June 30, 2003. SCE should seek a reasonableness review of its actual energy costs from July 1, 2003 through December 31, 2003 in its April 2004 ERRA application.¹⁸ The reasonableness review for subsequent April ERRA applications should be from January 1^st of the prior year through December 31^st of the prior year. April ERRA applications should also be used to consolidate all SCE revenue requirements and unbundled rate levels to recover those revenue requirements.

D. Revenue Requirement Forecast

SCE's revenue requirement forecast is based on fuel costs related to its generation stations, purchased power costs related to cogeneration and renewable contracts, existing inter-utility and bilateral contracts entered into prior to January 17, 2001, and new procurement-related costs that SCE began incurring on January 1, 2003. Purchased power costs associated with the DWR power contracts are excluded. Also excluded are EETA costs pursuant to D.02-12-074.

SCE's calculation of its revenue requirement forecast also takes into account the above-market portion of qualified facilities (QF) and purchased power agreement (PPA) expenses, which are eligible for ongoing Competitive Transition Charge (CTC) treatment as provided in D.02-11-022. SCE proposes to track the above-market portion of these costs in the Direct Access (DA) Cost Responsibility Surcharge (CRS) tracking account to ensure that DA customers ultimately pay for them. Once the DA CRS is sufficient to begin covering the above-market portion of these amounts, SCE will credit its ERRA with applicable DA CRS revenues to reduce the Bundled Service customer's on-going ERRA revenue requirement. There is no opposition to this proposal.

Details of SCE's 2003 revenue requirement forecast is set forth in Exhibit 1 and sealed Exhibit A. Although individual components of the 2003 fuel and purchased power revenue requirement forecast of $2.505 billion are under seal, details of those components were made available to interested parties under a protective agreement.¹⁹ All information placed under seal should remain sealed for a period of two years from the date of a final order in this proceeding, and during that period shall not be made accessible or disclosed to anyone other than Commission staff except on the execution of a mutually acceptable protective agreement.

We adopt SCE's 2003 fuel and purchased power revenue requirement forecast of $2.505 billion and tariff modifications incorporating this forecast. We also adopt SCE's proposed ratemaking treatment for above-market costs related to QF and PPA expenses as set forth in its application.

E. Trigger Mechanism

In D.02-10-062, the Commission required SCE to establish a trigger mechanism whereby over- and under-collections would not surpass 5% of the prior year's generation revenue. To implement timely rate adjustments when this difference exists, SCE is required to file an expedited application for approval 60 days from the filing date when its ERRA balance reaches 4% of the prior year's recorded generation revenues, excluding revenues collected for the DWR. SCE's trigger amount for 2003 is $228.593 million, based on its 2002 recorded generation revenues of $5.715 billion.

Expedited applications are required to include a projected account balance for a period of 60 days or more from the date of filing depending on when the balance will reach the 5% threshold. SCE's threshold amount for 2003 is $285.741 million, based on its 2002 recorded generation revenues of $5.715 billion.

SCE intends to update its trigger and threshold amounts in late January of each year through the Advice Letter process once the amount of the previous year's recorded generation revenue is known.

There is no dispute on the 2003 trigger and threshold amounts calculated by SCE. SCE's 2003 trigger amount shall be set at $228.593 million and threshold amount at $285.741 million. The ERRA tariff modification proposal by SCE that incorporates its 2003 trigger and threshold amounts is adopted as well as the yearly Advice Letter filing proposed by SCE to update its trigger and threshold amounts. However, that yearly Advice Letter shall be filed on February 1^st. If the first of February falls on a Saturday, Sunday, or holiday when the Commission offices are closed, the filing date is extended to include the first day thereafter.²⁰