Background

Until this Commission began to implement electric restructuring in the mid-1990s, there was no need to allocate Edison's total revenue requirement among generation, transmission, distribution and other functions. Instead, the Commission's practice in GRCs was to adopt an overall revenue requirement for the utility for a particular "test year," and then in a later phase of the GRC, to allocate this revenue requirement among customer classes and design rates to recover these allocations.

It was this traditional approach that was followed in Edison's 1995 GRC, which the Commission predicted would be the last such proceeding before the implementation of electric restructuring. In D.96-01-011, the so-called "Phase I" decision in Edison's 1995 GRC, the Commission - after rejecting a stipulation offered by Edison and other parties, and after making an independent assessment of the hearing record - adopted an overall revenue requirement, or Authorized Level of Base Rate Revenue (ALBRR), of $4.017 billion for Edison. (See 64 CPUC2d at 397.)

The need to allocate the ALBBR among the utility's various functions - as electric restructuring required - was first dealt with in D.96-09-092 (68 CPUC2d 275). In that decision, the Commission adopted a performance-based ratemaking (PBR) mechanism for the non-generation revenue requirement derived from Edison's 1995 GRC (i.e., transmission and distribution), as well as a distribution-only PBR mechanism that would go into effect once FERC and this Commission had adopted a separation between transmission and distribution of Edison's rate base and its base rate revenue requirement. After making various adjustments to Edison's proposal for separating the ALBRR between generation and nongeneration, we directed Edison to file a compliance advice letter incorporating these adjustments. (68 CPUC2d at 291-292.) Pursuant to that advice letter (1191-E-A), Edison's nongeneration revenue requirement for 1997 was set at $1.902 billion. For purposes of the "unbundling" proceeding described below, Edison developed a 1996 nongeneration PBR starting point of $2.028 billion.

The implementation of electric restructuring required that there be a further allocation of the nongeneration revenue requirement among transmission, distribution, and other functions. The Commission tackled this task in D.97-08-056, the unbundling decision. In that case, Edison proposed that from its 1996 nongeneration revenue requirement $211 million be allocated to transmission, $1.816 billion to distribution, and $282 million to nuclear decommissioning and public purpose programs. In its application, Edison made the following suggestion for determining the distribution revenue requirement:

"Edison recommends that the Commission derive its distribution rates by subtracting FERC-adopted transmission rates from the amount identified in its PBR as nongeneration rates. Edison refers to this residual approach as a `rate credit' method. Edison supports this approach by observing that the Commission has already approved Edison's nongeneration revenue requirement and that FERC is expected to rule soon on the utilities' transmission revenue requirement proposals." (74 CPUC2d at 17.)

Although D.97-08-056 adopted Edison's proposal to allocate $211 million of the nongeneration revenue requirement to transmission, it specifically rejected Edison's proposal that the revenue requirement and rates for distribution be set using the "residual" approach. The Commission gave two related reasons for this rejection. First, to do so would be to "abandon our own authority or responsibility to FERC by allowing it to determine the revenue requirement for distribution, a determination over which we have sole responsibility and authority." (Id. at 18.) Second, adopting the residual approach

". . . could put us in the position of second-guessing FERC decisions. To the extent that FERC reduces the utilities' proposed revenue requirements, it finds that for whatever reason the costs of utility transmission are not reasonable. The utilities propose that we effectively overlook the FERC's findings and . . . determine that those same costs are reasonable by including them in distribution rates. We would only grant such a request with a showing that the specific costs are both reasonable and associated with distribution activities. None of the utilities have made such a showing here[,] if for no other reason than they have no FERC decision upon which to form their proposals." (Id. at 19.)

Resolution E-3544 and the Creation of TRRRMA

Consistent with its position in the unbundling case, Edison in late 1997 submitted a Transmission Owner (TO) rate proposal to FERC based on the $211 million revenue requirement adopted in D.97-08-056. FERC accepted the TO tariff for filing on December 17, 1997. FERC's order accepting the filing provided that the rates would become effective, subject to refund, on the date the California ISO began operation, which turned out to be April 1, 1998.⁴

Apparently anticipating that FERC might not find all of the $211 million revenue requirement to be reasonably related to transmission, Edison also filed an advice letter (No. 1298-E) with this Commission on March 28, 1998. The advice letter asked that the TRRRMA be established "to track the revenue requirements associated with those costs requested by Edison for recovery in transmission rates in Docket No. ER97-2355-000 which the FERC may, at a later date, not allow to be included in the transmission rates." In its advice letter, Edison argued that establishing a TRRRMA was consistent with D.97-08-056, and that the amounts tracked in the account would be considered in a future Commission proceeding to determine the appropriateness of including them in distribution rates. San Diego Gas and Electric Company (SDG&E) filed a similar advice letter (No. 1088-E).

On July 23, 1998, in Resolution E-3544, the Commission granted Edison and SDG&E permission to establish the TRRRMA. However, the resolution was careful to note that by allowing this new memorandum account, the Commission

was not authorizing the automatic recovery in distribution rates of amounts that FERC might not include in transmission rates on the ground they were not transmission-related:

"As both Edison and SDG&E have correctly noted in their responses to ORA's protests, the mere establishment of these accounts do[es] not guarantee recovery of the costs. A TRRRMA would only set up a mechanism for the utilities to track certain costs that are disallowed by FERC. Amounts booked into these accounts will be considered in future proceedings, where the Commission will have an opportunity to review their appropriateness for recovery, as well as address relevant ratemaking issues. Therefore, the sole purpose of the TRRRMA would be to track certain costs that are disallowed by FERC without any determination of their recovery. This approach is consistent with D.97-08-056.[⁵] We agree with Edison that because utilities are currently incurring these costs, denying the establishment of a TRRRMA would put them at risk for recovery of these costs and could deny them the opportunity to recover, in future proceedings, costs that are distribution-related and reasonable." (Resolution E-3544, pp. 3-4.)

In addition to noting that the recovery of TRRRMA costs would be contingent upon appropriate showings in future proceedings, Resolution E-3544 also stated that (1) only costs eligible for recovery in Edison's PBR could be tracked in TRRRMA, and (2) Edison would be required to treat as a reduction to the TRRRMA balance, any costs that Edison had characterized as distribution-related but that FERC subsequently determined were transmission costs includable in transmission rates.

Edison's Transmission Rate Proceeding at FERC

The disallowance of some costs that Edison had characterized as transmission-related did indeed occur in the FERC proceedings. In his Initial Decision in Docket Nos. ER97-2355-000, et al., issued on March 31, 1999, the FERC ALJ ruled that Edison had not demonstrated that its multi-factor methodology for allocating A&G and G&I costs was superior to FERC's traditional labor ratio allocation method, and therefore Edison's method should be rejected. After noting that Edison's proposed allocations under the multi-factor approach were not adequately supported by its accounting data, the FERC ALJ said:

"SCE's proposal does not sufficiently establish that its method is more reliable than the allocation of costs by labor ratios. SCE has failed to demonstrate that the California restructuring situation has changed the nature of G&I or A&G costs and any allocation of such costs. The goal remains to assign the proper amount of costs to each function, i.e., transmission services. The timing of rate cases before this Commission, and also before the CPUC, has at times caused an amount of uncertainty regarding the assignment of G&I or A&G costs for recovery in regulated rates. But that fact alone does not provide a valid reason to now abandon the labor ratio method long endorsed by this Commission for many years. Thus, it is found that SCE has not demonstrated that the labor ratio method is unjust and unreasonable and that its proposed methodology is just and reasonable."⁶

Edison appealed from this and several other determinations in the FERC ALJ's Initial Decision. However, in Opinion 445, FERC affirmed the Initial Decision's determination on the labor ratio cost methodology in strong terms. Noting that this Commission had provided an opportunity to recover the TRRRMA costs in Resolution E-3544, FERC said:

"We will affirm the Initial Decision. The majority of the arguments raised by SoCal Edison on exceptions were presented at hearing and were properly disposed of in the Initial Decision. We also find that the Presiding Judge properly applied the Commission's existing policy for allocating A&G and G&I costs. In addition, the California Commission has made clear in its comments that SoCal Edison has the opportunity, if it so chooses, to seek state jurisdictional review and potential recovery of any non-transmission costs subject to the California Commission's jurisdiction. Given this opportunity, we find that SoCal Edison's claimed inability to recover its legitimately incurred costs, due to changes in jurisdiction, is unfounded." (92 FERC at p. 61,268.)

Edison has not accepted Opinion 445 as the final word on this matter. On August 25, 2000, Edison filed with FERC what it termed a Conditional Request for Rehearing of Opinion 445. After noting the suggestion in the passage above that Edison should seek recovery of the A&G and G&I costs at issue from the CPUC, the conditional rehearing request states:

"SCE intends to make a filing with the CPUC shortly to recover these costs. If the CPUC denies that request, however, SCE will be in the position where both agencies will have suggested the other agency as the proper forum for cost recovery, with SCE unable to recover the costs from either agency. SCE respectfully requests, therefore, that if the CPUC denies SCE's request, the Commission allow SCE to recover these costs through its FERC-jurisdictional rates. Any result short of this will result in SCE losing over $20 million/year solely due to changes in jurisdiction -- precisely the result the Commission sought to avoid in its Opinion. Moreover, this result would be inconsistent with the Commission's policy set forth in Order No. 2000 that a utility will not be penalized for turning over its transmission facilities from state to federal jurisdiction." (Conditional Request for Rehearing, pp. 2-3.)

In addition to these policy arguments, Edison's Conditional Request for Rehearing also maintains that Opinion 445 committed legal error by requiring Edison to prove that its multi-factor allocation methodology was superior to the traditional labor cost allocation methodology. On this issue, the conditional rehearing request states:

"The Presiding Judge rejected SCE's proposal because SCE failed to show that the use of labor ratios was unjust and unreasonable, citing the Commission's policy established in Minnesota Power & Light Co., 5 FERC ¶61,091 (1978) . . . The Commission affirmed the Presiding Judge on this issue . . . The Commission's imposition of this obligation on SCE is erroneous, however, because it impermissibly applies the burden of proof that applies to the Commission under Federal Power Act (FPA) Section 206 to a Section 205 proceeding. The courts have carefully distinguished between the burden of proof provisions in FPA Sections 205 and 206 . . . In a Section 205 proceeding, a utility need only show that its proposal is just and reasonable; it does not have to show that another method is unjust and unreasonable, or that its proposal is more accurate or reliable than another method." (Id. at 5, n. 6 (citations omitted)).

"The utilities propose that we effectively overlook the FERC's findings [that some costs are not transmission costs] and . . . determine that those same costs are reasonable by including them in distribution rates. We would only grant such a request with a showing that the specific costs are both reasonable and associated with distribution activities." (74 CPUC2d at 19; emphasis added.)