II. Cost Allocation and Rate Design

A. Allocation of Direct Access Implementation Costs

One objective of this proceeding is to allocate between customer groups the costs of implementing direct access or "restructuring" costs. These restructuring costs are addressed in Pub. Util. Code § 376 applications. The utilities have filed separate applications asking the Commission to find eligible costs that would receive special ratemaking treatment under § 376.¹ The utilities have incurred costs for the following activities related to direct access: hourly interval meter installation and reading costs, billing system modifications, consumer education and electric education trust activities, customer information release to competitors, and PX start-up and development (or PX "initial charges").

Edison proposes recovering implementation costs through the TRA mechanism, arguing that such accounting treatment will obviate the need for an explicit cost allocation in this proceeding.² It would defer the matter to its post-transition period ratemaking application, which it filed on January 15, 1999.

PG&E proposes to enter pre-1999 restructuring costs into the TRA once and for all and to "functionalize" post-1998 restructuring costs into distribution, generation and transmission components for future recovery.

If the Commission allocates the costs in this proceeding, Edison, PG&E and SDG&E propose allocating these costs using Equal Percentage of Marginal Cost (EPMC) or a method referred to as the "system average percentage" (SAP) method. They believe this allocation is most consistent with the Commission's existing methods for allocating fixed costs. Edison observes that the Commission has endorsed EPMC because it most closely reflects the cost of service and promotes pricing which improves system efficiency.

ORA objects to Edison's proposal to defer the determination of appropriate cost allocation. It would have the Commission establish an accounting within the TRA mechanism that would track how various customer groups have contributed toward the payoff of transition costs. According to ORA, the Commission could then use this information in determining the mechanics of ending the rate freeze for each customer class.

ORA and TURN propose that the utilities allocate implementation costs on an "equal cents per kilowatt-hour"(kWh) basis.³ Under this allocation method, each customer would pay a share of implementation costs according to the quantity of electricity used. TURN comments that such costs do not vary with system usage and therefore are not necessarily good candidates for the EPMC allocation the Commission has normally used. It compares implementation costs with those of the CARE program and the Commission's treatment of those costs. As TURN observes, D.96-04-050 allocated CARE costs using an equal-cents per kWh method on the basis that the CARE program was unrelated to energy consumption and that equity concerns should be the primary basis for determining appropriate cost allocation. In pursuing its argument for an equitable allocation of direct access implementation costs, ORA and TURN observe that utility customers are not benefiting equally from direct access. ORA demonstrates that industrial and large commercial customers purchase 95% of electricity sold in the direct access program. ORA observes that even under its allocation proposal, small customers would still pay for 34% of restructuring costs, even though they have consumed only 5% of the energy sold through the direct access program.

TURN observes that § 367(e)(1) limits shifting the burden of stranded generation costs between customer classes but does not affect the Commission's discretion to allocate implementation costs because the Commission has not heretofore allocated such costs.

Enron, FEA, CLECA, DGS and Edison object to the TURN and ORA proposed method of allocation. Some observe that using an equal percent of kWh allocation is the equivalent of a "functionalization" of the costs, that is, a determination that the costs are associated with, in this case, generation. FEA points to uncontested utility testimony that demonstrates restructuring costs are related primarily to customer service and transmission. Enron, FEA and Edison observe that restructuring costs are fixed and therefore do not vary according to the amount of energy consumed. The costs should therefore not be recovered on the basis of energy consumption levels, as the ORA and TURN method would require. FEA believes the proposals of TURN and ORA violate the prohibition on cost shifting presented in AB 1890. Enron argues that functionalization is appropriately the topic of the § 376 proceeding, A.98-05-004, et al.

Discussion. We share the concern of TURN and ORA that using existing methods to allocate restructuring costs could be unfair to small customers. Large customers have been and are likely to be the primary beneficiaries of direct access for the foreseeable future. Existing cost allocation methods would not correspond to the distribution of benefits. Under existing methods, small customers in fact assume a share of costs that is wildly disproportionate to the benefits they have realized. Even the cost allocation methods ORA and TURN propose allocate considerably more restructuring costs to small customers than those customers have imposed on the system.

Our policy has consistently been that costs should be allocated to those customers who impose them. The methods the utilities propose for allocating restructuring costs do not accomplish that objective. Unfortunately, existing law limits our discretion to allocate implementation costs in this instance. As a preliminary matter, we do not agree with TURN that such costs are exempt from the cost shifting provisions of § 367 because they are "new." The fact that the costs have been incurred since the passage of AB 1890 does not exempt them from cost shifting provisions of the act. Section 367(e)(1) requires that transition costs be allocated "in substantially the same proportion as similar costs are recovered as of June 10, 1996..." The statute does not distinguish existing costs from new costs. However, § 367 applies only to transition costs. Restructuring implementation costs are not transition costs as defined by §§ 367 and 840. As the Commission found in D.97-12-042, restructuring costs are those costs which may be recovered pursuant to § 376 and only to the extent they displace recovery of transition costs and extend the period for recovery of transition costs.

Although § 367 does not identify restructuring costs as among those which must be allocated as they have been in the past, a departure from past practice is probably not permissible under the statute. As PG&E points out, changing the allocation of one type of cost affects the relative burden of the CTC among customer groups, indirectly changing the cost allocation in effect June 10, 1996 and in contravention of § 367. We are therefore constrained from adopting new cost allocations for restructuring costs.

For restructuring costs incurred through 1998, the utilities shall allocate restructuring costs using the total EPMC or system average percentage method through the transition period. We will determine treatment of post-transition period costs in the utilities' associated applications, as Edison proposes. In the interim, the utilities shall add a new column to the utilities' Revenue Sub-account in the Rate Group Transition Cost Obligation Memorandum Account, as ORA proposes, to track the costs allocated to each customer group. This accounting will permit flexibility in determining how to end the transition period for customer groups. These costs will not be included as separate rate components on customer bills because they would create customer confusion without a transparent corresponding benefit.

B. Allocation of Transition Costs

D.97-06-060 requires the utilities to track transition costs and payments by rate group.⁴ The utilities include these costs in accounts we have titled Rate Group Tracking Memorandum Accounts (RGTMA). The utilities have so far allocated the costs between rate groups by the EPMC method.

ORA argues that the Commission has not yet determined whether the costs should be allocated based on EPMC, which reflects total marginal costs components, or marginal costs based on generation only. ORA proposes that allocation be based on an equal percentage of generation marginal costs (EPGMC) factor on the basis that it would most fairly and efficiently recognize the allocation of generation usage between customer groups.

The applicants, Farm Bureau, FEA, and CLECA, object to ORA's proposal to allocate transition costs based on generation marginal cost. These parties argue that ORA's proposal would constitute cost shifting between customer groups in violation of AB 1890 and contrary to previous Commission decisions. They observe that ORA's own analysis demonstrates that its proposal would reduce small customers' rates by millions of dollars and increase them for larger customers by a corresponding amount.

Discussion. Commission decisions have not been entirely clear on the subject of precisely how to allocate transition costs between customers. Early decisions stated that cost-shifting should be avoided. The Commission Preferred Policy Decision states:

"Transition costs will be allocated to all customer classes using an equal percentage of marginal cost (EPMC) methodology, unless specific circumstances justify a different approach. Marginal cost pricing for electric services using the EPMC methodology is well established, and using this approach for the allocation of transition costs ensures a fair allocation among all customer classes and prevents inter- and intraclass cost-shifting. Using this approach also preserves the cost allocation that we have previously reviewed and approved " (D.95-12-063, p.142).

Although D.95-12-063 does not specify whether the EPMC allocation methodology is a factor of total EPMC or generation only, it refers to a "well established" methodology. The only well-established methodology in our ratemaking proceedings is that which the parties refer to as total EPMC.

Subsequently, D.96-12-077 reiterated Commission policy regarding the allocation of transition costs and cost shifting:

"Since rates for each customer class are frozen, revenues will be allocated essentially as they were on June 10. Preserving the June 10 revenue allocation corresponds on the revenue side to § 367 (e)(1)'s directive that transition costs are to be allocated among the various customer classes, rate schedules, and tariff options, and recovered from these categories `in substantially the same proportion' as similar costs were recovered in retail rates on June 10, 1996."(D.96-12-077, pp. 12-13).

Later, we hedged the issue to some extent prior to considering the impact of AB 1890 in the context of final allocations. D.97-12-039 found that we would use EPMC to allocate costs "unless specific circumstances justify a different approach." The order reinforces the Commission's established position by citing § 367(e)(1) but suggests the resolution of the matter was not necessarily final. Finding of Fact 9 states: "The transition cost allocation factors may be re-evaluated in the First Revenue Adjustment Proceeding."

Although our decision may have suggested an intent to consider departures from the traditional EPMC methodology, we find that AB 1890 prohibits such action. During the transition period, the Commission may not order the utilities to shift costs between customer classes. Specifically, Pub. Util. Code § 367(e)(1) mandates that transition costs:

"Be allocated among the various classes or customers, rate schedules, and tariff options to ensure that costs are recovered from these classes, rate schedules, contract rates, and tariff options, including self-generation deferral, interruptible, and standby rate options in substantially the same proportion as similar costs are recovered as of June 10, 1996."

No party disputes that the cost methodology the utilities already have in place is based on total EPMC. No party suggests that the EPMC methodology is not the one used to allocate costs as of June 10, 1996, consistent with past ratemaking decisions. The allocation method ORA proposes would depart from established practice and constitutes unlawful cost-shifting, as the utilities and other parties argue. We reject ORA's proposal to apply a generation-only EPMC cost methodology for transition costs.

C. Allocation of SDG&E's Transmission and Distribution Revenue Requirements

ORA originally opposed the method used by SDG&E to allocate transmission and distribution revenue requirements, arguing that it contravened the Commission's order in D.97-08-056. Following discussions between ORA and SDG&E, the parties resolved their differences. SDG&E agrees to allocate these revenue requirements as follows: combining the FERC approved transmission revenue requirement and the Commission-approved distribution revenue requirement, allocating to customer classes using the individual class transmission and distribution marginal cost and calculating the final distribution revenue requirement by subtracting transmission revenues from the combined revenue requirement. This method of allocation is not opposed by any party and is consistent with D.97-08-056. We therefore adopt it here.

D. Distribution Revenue Requirement Allocation to Schedule E-20T

BART proposes that it should not pay distribution costs because the distribution marginal cost revenues associated with its rate schedule, E-20T, is zero. According to BART, PG&E's proposal to allocate distribution costs to schedule E-20T violates Commission policy with regard to rates reflecting EPMC and costs, thereby creating inappropriate price signals for customers like BART.

PG&E opposes BART's proposal, arguing that the distribution revenue requirement includes not only the cost of distribution but also the costs of metering, customer services and billing activities, services which BART continues to receive. PG&E observes that its stipulation with ORA on cost allocation matters reduces BART's distribution revenue requirement by 40%, which according to PG&E increases the distribution allocation to residential rates by $5.7 million. To go further, according to PG&E, would provide an unlawful and unfair advantage over other customers.

We deny BART's request to exempt schedule E-20T customers from distribution costs. As PG&E observes, doing so allocates costs on a "functional" basis, that is, based only on transmission and customer costs. We have rejected allocating EPMC on a functional basis for other customer groups, finding that it would violate provisions in AB 1890 which preclude cost allocation shifts during the rate freeze period.

E. Stipulation Between ORA and SDG&E

On December 22, 1998, SDG&E and ORA filed a stipulation in this proceeding with respect to several contested issues. The stipulation provides for the following:

1. For small and residential customers, Public Purpose Program (PPP) and nuclear decommissioning costs are allocated using the SAP method and the frozen rate levels without adjustment for the 10% rate reduction;

2. SDG&E will charge $4,600 to new customers on Schedules A-V1, A-V2, and A-V3 for the cost of signaling equipment used to measure peak-pricing periods;

3. Transmission, generation, nuclear decommissioning, and PPP components of the $5.10 residential minimum bill will be calculated based on average minimum bill usage.

4. Non-generation revenue requirement should be updated after December 31, 1998 to reflect the impact of Commission decisions issued after July 1, 1998, provided to all parties to this proceeding and incorporated in the decision issued herein; and

5. Certain balancing accounts and memorandum accounts will be eliminated as set forth in ORA's revised Table 2-1 with the exception that ORA and SDG&E remain at odds with regard to netting the balances in various accounts.

ORA and SDG&E propose that their stipulation is reasonable and consistent with the law. No party opposes it. We adopt it as a reasonable resolution of outstanding disputes that is consistent with our policies and the law.

F. Stipulation Between Edison and ORA

ORA and Edison filed a stipulation on December 22, 1998 resolving several issues as follows:

The CARE Discount and the CARE Surcharge. ORA originally recommended that the CARE discount be allocated to distribution rates. Edison proposed that the CARE surcharge and discount should continue to be allocated to the PPP charge. The stipulations require applicants to allocate the CARE discounts to distribution rates and to allocate the CARE surcharge to the PPP charge. As a result, the PPP charge would be reduced by an amount equal to the CARE surcharge for customers exempt from the surcharge.

Allocation of PPP and Nuclear Decommissioning Revenue Requirements. Under the stipulation, Edison would use the SAP method to allocate PPP and nuclear decommissioning revenue requirements between customers to adjust June 10, 1996 rate levels, without adjusting for the 10% rate reduction applicable to residential and small commercial customers.

Balancing and Memorandum Accounts. The stipulation provides that Edison would eliminate various balancing and memorandum accounts which are no longer useful, as set forth in ORA's revised Table II-1. It provides that those memorandum and balancing accounts reflecting generation costs which were or will be transferred to the Transition Cost on Balancing Account (TCBA) will be addressed in the ATCP. Upon completion of that review, the Commission would consider whether to eliminate or retain various accounts in the subsequent RAP.

Updated Revenue Requirements. The stipulation provides that the revenue requirements to be addressed in this proceeding should be updated after December 31, 1998 to reflect any Commission decisions issued and to account for final recorded balances.

Low Emission Vehicle Costs and Special Contracts. The stipulation provides that the costs associated with low emission vehicles and special contracts should be reviewed in the next RAP proceeding.

Costs Incurred by Edison to Serve Santa Catalina Island. ORA and Edison agree that Edison should be permitted to recover Santa Catalina fuel costs through the TRA. They also agree that the commodity cost should be reflected on Santa Catalina customers' bills at a rate of $.0685 per kWh for 1999 for informational purposes.

Discussion. The stipulation filed by ORA and Edison is reasonable and consistent with the law and the record, with one exception. The treatment of Santa Catalina fuel costs is not lawful. Edison and ORA agree that Edison should be permitted to recover Santa Catalina Island diesel fuel costs through the TRA mechanism. In its testimony, Edison demonstrated that it has not recovered its Santa Catalina diesel fuel expenses because the TRA does not currently account for Santa Catalina fuel costs. This occurs because the PX and Independent System Operator (ISO) do not provide power services to Santa Catalina as a result of its geographic isolation. The revenues available to offset stranded costs ("headroom") is therefore larger than it would otherwise be because Santa Catalina's fuel costs are not deducted from the total monthly billed revenues. Edison originally proposed to recover Santa Catalina diesel fuel costs in the TRA mechanism as a separate item. ORA did not address the matter in testimony but subsequently agreed to Edison's proposal in the stipulation filed on December 22, 1998.

Notwithstanding ORA's ultimate concurrence with Edison's proposal, the proposal is unlawful. Pub. Util. Code § 367(c) states that certain costs of fossil plant operation may be recovered only through the ISO or PX:

"All going forward costs of fossil plant operation, including operation and maintenance, administration and general, fuel and fuel transportation costs, shall be recovered solely from independent Power Exchange revenues or from contracts with the Independent System Operator...." (Emphasis added).

Fuel costs for Santa Catalina Island which are incurred since the passage of AB 1890 are "going forward" costs and are therefore subject to the provisions of § 367(c). The statute does not make exceptions for the recovery of fuel costs in isolated regions, such as Santa Catalina.⁵ Edison's proposal to recover them through the TRA would offset headroom, thereby effectively permitting their recovery in distribution rates. We have already stated that these costs may not be recovered in distribution rates (D.97-11-073).

Whether or not Edison should be able to recover Santa Catalina fuel costs through the TRA as a matter of fairness, the recovery of those costs from a source other than the PX or ISO is precluded by § 367(c). Assembly Bill (AB) 1890 is a complex set of statutes that guides the evolution of electric industry restructuring. Under its provisions, the utilities are presented with certain benefits and advantages as a tradeoff for certain sacrifices. We must presume the loss of Santa Catalina fuel costs is one of those sacrifices. On that basis, we cannot adopt the component of the stipulation that would provide for such recovery.

We adopt the stipulation between ORA and Edison as it is presented with the exception of the provision permitting Edison to recover Santa Catalina fuel costs in the TRA. We are not concerned that removing one element from the larger package unduly compromises the parties' agreement: each remaining component of the stipulation is reasonable, supported by the record and lawful.

G. Stipulation between PG&E and ORA

PG&E and ORA filed a stipulation resolving several cost allocation and rate design issues as follows:

Distribution Revenue Requirement Allocation. The stipulation establishes a method for calculating the distribution revenue requirement allocation;

CARE Discount and Surcharge. The CARE discount will be expressed as a reduction to distribution charges on customers' bills. The CARE surcharge will be included in the PPP amount shown on customers' bills. The CARE surcharge exemption will be expressed as a lower PPP amount on exempt customers' bills. PG&E will implement the mechanism in utility accounts by setting the authorized level for the distribution revenue requirement in the TRA at the amount for distribution before being reduced for the CARE discount. The authorized level for the PPP revenue requirement in the TRA will be set at the amount for PPP before the CARE surcharge revenue is added.

Allocation of PPP and Nuclear Decommissioning. The portion of PPP which does not include the CARE surcharge and amounts for nuclear decommissioning will be allocated based on the system average percentage method.

Residential Minimum Bill Calculation. No later than September 1999, PG&E will calculate the minimum bill according to the customer's average usage by function and assign the residual amount (the difference between the $5 minimum bill and the rates for functions other than distribution) to distribution.

Elimination of Memorandum and Balancing Accounts. PG&E and ORA agree to eliminate the balancing and memorandum accounts as proposed in ORA's revised Table 2-1. The parties agree to consider generation accounts and the TCBA in the ATCP.

Update to Revenue Requirements. PG&E will change its rates after the Commission has issued a decision in PG&E 1999 general rate case proceeding A.97-12-020 and will update other revenue requirements after December 31, 1998 to reflect the impact of relevant Commission decisions issued after that date.

BART objects to that portion of the stipulation which affects schedule E-20T. As discussed above, BART's argument in this regard is premised on the assumption that we may adopt functional cost allocations, a practice we have found to be unlawful during the transition period for all rates and customer groups. With this clarification, we adopt the settlement between ORA and PG&E.