D.97-06-060

Findings of Fact

1. The requirement that allocation of transition costs shall not result in rate increases beyond June 10, 1996 levels requires that the CTC portion of a customer’s bill be computed on a residual basis, i.e., the difference between the total rate and all other charges, including the Power Exchange price.
2. The Joint Recommendation is not a settlement and is accorded appropriate weight.
3. Recovery of generation-related transition costs is not intended to be without risk, but § 330(t) provides the IOUs a reasonable opportunity to fully recover transition costs.
4. Other than employee-related transition costs addressed in § 375, restructuring implementation costs addressed in § 376, and any generation-related transition costs which are displaced because of the collection of funds addressed in § 381(d), current transition costs must be recovered as incurred.
5. Greater revenues are available for total transition cost recovery when assets with a higher rate of return are accelerated prior to assets with a lower rate of return, and in a manner that maximizes the tax benefit of such amortization.
6. It is in the interests of both ratepayers and shareholders to ensure that the greatest amount of revenues is available to collect transition costs, rather than being applied to interest and carrying costs.
7. Ratepayers benefit from maximizing the amount of revenues to apply to transition cost recovery, because if transition costs are collected as expeditiously as possible, the rate freeze may end before December 31, 2001.
8. Shareholders benefit from ensuring that the greatest amount of revenues is available to collect transition costs, because there is a greater likelihood of full recovery of those costs.
9. It would not be equitable to allow the utilities to have the flexibility to accelerate the recovery of assets that do not bear a rate of return and simultaneously allow the utilities to apply a lower interest rate to their CTC revenue accounts.
10. We have not yet adopted a definition of regulatory assets for purposes of transition cost recovery, although regulatory obligations are included in the definition of generation-related assets provided for in AB 1890.
11. Recovery of regulatory assets is probable because there is no reason to assume that frozen rates will not result in sufficient headroom to fully recover transition costs.
12. Regulatory assets that may be subject to write-off due to FASB Statement No. 71 should be amortized ratably over a 48-month period. The specific regulatory assets to which this finding applies will be determined after Phase 2 eligibility is established.
13. To the extent these assets adhere to the requirements of § 367, generation-related regulatory assets remain recoverable through the CTC, even if written-off for financial accounting purposes.
14. The utilities have the opportunity to accrue revenues to offset transition costs prior to the beginning of the transition period because the rate freeze commenced on January 1, 1997, pursuant to D.96-12-077.
15. The proceeds from rate reduction bonds will have a significant impact on transition cost recovery.
16. An annual transition cost proceeding will help to ensure that we can provide for unanticipated problems.
17. We will not know the extent to which transition costs are uneconomic until market valuation is completed and until we determine the amount of fixed costs that are recovered in the Power Exchange market clearing price.
18. We must ensure that we can track recovery of transition costs on a detailed basis, so that we can determine when those transition costs are fully collected, and we must ensure that adequate review is provided for to ensure that only the uneconomic portion of transition costs is recovered.
19. Current ratemaking principles remain essentially intact, including the accounting principle of matching revenues with expenses; therefore, excepting costs whose recovery may be deferred beyond 2001 as discussed herein, current costs should be recovered first.
20. To the extent that revenues did not cover costs in the current period, revenues should be applied first to transition costs incurred during that period and then to scheduled amortization.
21. As assets which are currently included in rate base are amortized, rate base should be reduced correspondingly, including the impact of associated return and income taxes.
22. Generation-related assets should be written down to the estimated market value, but not below, on an asset-by-asset basis.
23. Similar to balancing accounts established today, the utilities should manage the acceleration of assets to achieve a matching of revenues to current costs plus the portion of noncurrent costs that is accelerated in a manner to avoid major under- or over-collections of CTC. To the extent that over- and under-collections occur, interest will accrue at the 90-day commercial paper rate, with the exception of the deferred generation-related transition costs displaced because of funding the programs addressed in § 381(d).
24. To the extent feasible, the transition costs addressed in §§ 375, 376 and 381(d) should be recovered before 2001, similar to current ratemaking practices, but may be deferred to the extent such recovery will put generation-related assets at risk. Section 375 costs may be collected through 2006 and collection of § 376 costs may continue until fully recovered. Any deferrals of these costs may accrue interest at the 90-day commercial paper rate. In addition, to the extent generation-related transition cost recovery is impacted by the collection of renewable program costs under § 381(d) during the rate freeze period, those displaced generation-related transition costs may be collected in the period January 1, 2002—March 31, 2002. Shareholders must bear any associated carrying costs.
25. Establishing memorandum accounts to track transition cost obligations and revenues separately for customers on each side of the fire wall is a useful way to ensure that transition cost obligations are not shifted from one side of the firewall to another.
26. Current application of the EPMC methodology does not allocate costs to the disaggregated level of rate schedule, tariff option, or contract.
27. It is reasonable to require that the utilities track transition cost obligations and payments at the rate group level. Rate groups are the units for which marginal cost revenue responsibility and allocated revenue are determined.
28. The definition of departing load does not apply to Western’s customers who are increasing their allocation of federal preference load and PG&E load in a manner contemplated under the existing Contract 2948-A.
29. To the extent that FERC imposes a CTC on the contracts addressed herein, we will develop a process to adequately account for these funds to offset transition cost recovery and to make any necessary adjustments to the firewall memorandum accounts.
30. It is reasonable to adopt the stipulated market clearing price of 2.4 cents per kilowatt hour for the limited purpose of developing an estimate of the total transition cost level applicable for 1998, which may also be important for developing the rate reduction bond applications. Our approval of this stipulated market price does not establish a precedent for any other purpose.
31. CTC tariffs should be constructed to provide the necessary tariff information for utility service customers, direct access customers, and departing load customers.
32. To the extent possible, the billed CTC should be based on metered consumption.
33. It is appropriate that one option for determining the load of departing customers should include reliance upon third-party metering, if a verification of that meter is provided and provided that each party shall bear its own costs for any verification process.
34. It is inappropriate for a utility to require current metered information to determine departing load; rather the customer should be able to select the billing determinant to be applied in consultation with the utility.
35. Customers should be able to change the rate basis used in their CTC calculation by providing current metered information which demonstrates that if they were still taking full utility service, they would be under a different rate schedule.
36. Any transition cost metering option should be available to full service customers, direct access customers, and departing load customers.
37. Providing CTC tariffs for full service, direct access, and departing load customers in one central area of the tariffs will assist the customer in assessing how its CTC calculation and terms may change under various service alternatives.
38. CTC amounts that would otherwise have been paid by exempt customers must be tracked according to the type of exemption and by large and small customer class, as defined by the fire wall requirements delineated in § 330(v).
39. Each utility should provide special procedures which allow departing load customers to cure failures to provide notice of departure and failure to pay CTC.
40. A two-stage approach to establishing a penalty for failure of departing load customers to pay CTC is reasonable.
41. PG&E’s derivation of the lump-sum payment reflects a scaling formula that helps to account for transition costs already paid by the customer and should be adopted for PG&E, Edison, and SDG&E.
42. The lump-sum amount must be trued-up to reflect adopted transition cost estimates, as determined in Phase 2 of these proceedings.
43. Requiring departing load customers to pay a final lump-sum payment of the transition cost obligation remaining after March 31, 2002 could impose significant hardship on departing load customers.
44. It is appropriate to require PG&E, Edison, and SDG&E to expand the standard advice letter filing service list to include the service list to R.94-04-031/I.94-04-032 and this proceeding.