III. PG&E's Proposal

PG&E proposes to calculate a credit to direct access customers as follows: For the period December 28, 2000 to January 16, 2001, (since DWR assumed power buying on behalf of PG&E on January 17, 2001), PG&E would use the Schedule PX price to set the DA credit, with the energy cost capped at the level ultimately determined by the Federal Energy Regulatory Commission (FERC) to be just and reasonable. PG&E believes issuing bill adjustments to the DA customers and ESPs who received the benefit of a DA credit that was based on unjust and unreasonable prices is justified for this period to adhere to the avoided cost principle and prevent the shifting of costs from DA customers to other ratepayers. For periods subsequent to January 18, 2001, the date PG&E could no longer purchase energy from the PX, PG&E seeks authority to adopt the DA credits for past periods as determined by PG&E using the combination of URG and DWR costs for the period after January 18, 2001, continuing through PG&E's implementation of bottoms-up billing for DA customers. Bottoms-up billing charges DA customers only the distribution and transmission component of the bundled customer bill.

A. The Period December 28, 2000 to January 18, 2001

PG&E proposes that for the period December 28, 2000 to January 18, 2001, DA customers retain the benefit of DA credits already calculated, but that such credits should be limited by FERC's final determination of what the just and reasonable rates for wholesale energy during that period were. FERC is considering those rates in a proceeding affecting bulk power markets and wholesale energy prices in California.²

PG&E argues that its proposal does not violate any rule against retroactive ratemaking. It is based on simple fairness and sound policy. The DA credit during the period December 28, 2000 - January 18, 2001 was determined based on the cost of energy that PG&E purchased from the PX and ISO. When it approved PG&E's Schedule PX tariff, the Commission approved a credit calculation for DA customers that was based directly on FERC rates (as passed through to PG&E by the PX and the ISO). PG&E says that if FERC changes those rates retroactively, through refund and as the FERC announced on November 1, 2000 that it may do³ --- the same considerations of policy and fairness which led the Commission to base the credit on actual energy costs compel a retroactive adjustment to DA credits.

PG&E asserts that if FERC determines that market prices paid to generators and used in the DA credit calculation were unjust and unreasonable, it would require the ISO to recalculate hourly prices, and the ISO and PX to rerun the settlement/billing process. What remains for this Commission to do is merely to recognize that a billing adjustment is required to give effect to the result of the FERC's investigation. In the opinion of PG&E, such an adjustment would not be retroactive ratemaking. First, this proceeding is not a general rate proceeding; thus, the prohibition against retroactive ratemaking does not apply. See Southern Cal. Edsion Co. v. Pub. Utils. Com., (1978) 20 Cal 3d 813, 816. Second, what PG&E proposes is not a change in a rate, but a true-up of its calculation under an existing effective tariff. PG&E believes that if it were the case that PG&E's energy costs during December 2000 and January 2001 were found to be higher than what was used to calculate DA credits, DA customers would be requesting an upward adjustment in their credits.

New West Energy Corporation (New West) and the Alliance for Retail Energy Markets and the Western Power Trading Forum (AReM/WPTF) oppose PG&E's proposal on the grounds that (1) it constitutes retroactive ratemaking and (2) retroactive rebilling would seriously impact DA customers. They argue that retroactive rebilling would be a nightmare for DA customers. The impact of allowing retroactive rebilling has far reaching impacts on DA customers who include the price of energy in their services and products. Those DA customers could not recoup increased costs two years later. The process to find past DA customers and recompute bills would be confusing, difficult, and inequitable. Some DA customers would see increased costs, while others who had moved out of state or could not be located for whatever reason, would avoid the effect of the recalculation. AReM/WPTF believe that the interests of ratepayers are best served by minimizing the need to revisit the past and imposing costs on customers long after they are able to make economic decisions based on a realistic understanding of their costs.

We agree with AReM/WPTF. In our opinion it would be unreasonable to recompute the DA credit should FERC order refunds. We are confronted, initially, with three unknown factors: whether FERC will order refunds: when FERC will order refunds ( and when the order becomes final), and the amount of those refunds.⁴ As of this writing, FERC has the matter under consideration. Any order of refunds, if substantial, is expected to be appealed. It is impossible to predict the date of a final order. The period in question, December 28, 2000 to January 18, 2001, is two years old and counting. It is unfair for ratepayers who paid their utility bills two years ago to be subject to an unknown liability to be paid at an unknown future date. We need not elaborate on the intensive effort required by PG&E to recompute individual bills nor the intensive efforts and spent resources of end users to verify those recomputed bills. Because we deny PG&E's proposal we do not reach the question of whether approval of the proposal would constitute retroactive ratemaking.

B. The Period January 19, 2001 to the Implementation of Bottoms-Up Billing

PG&E proposes to use its current methodology for calculating the DA credit for the period from and including January 19, 2001 to the implementation date of a final Commission order in this proceeding. PG&E maintains that its current methodology strikes a balance between the philosophical underpinnings of the DA credit, which was based on avoided cost assuming a functional, efficient market for energy, and Commission efforts to deal with the dysfunctionality of that market after the demise of the PX.

PG&E states that its ability to purchase electricity in excess of its own generation including must-take generation from the PX's day-ahead and day-of markets ended effective January 18 and January 19, 2001, respectively. On January 31, 2001, the Commission issued D.01-01-061, adopting an interim accounting methodology for URG, which was subject to later adjustment and true-up. Because of the immediate need for a reasonable cost proxy for utility retained generation, PG&E calculated the Schedule PX price using an estimate of its cost-of-service for its retained generation. In D.01-03-081, the Commission elaborated on the payment mechanisms used for recovery of the costs of DWR power sales to PG&E's end-user customers. PG&E has used those payment amounts, as modified by subsequent decisions, as the basis for the pricing of DWR-provided power under Schedule PX.

Thus, since the demise of the PX, PG&E has used a measure of the cost of energy to determine the DA credit, but (due to the same demise) is not based on its actual avoided costs. In place of the forward-market price of power from the PX and other avoided costs, PG&E now uses a weighted average generation cost for retained generation, power purchases and DWR power, increased by ISO administrative costs. PG&E also adjusts prices for distribution losses, the uncollectible allowance, and a procurement adder as required by Schedule PX. PG&E does not propose to retroactively adjust credits that were rendered using its current methodology. No party objects to PG&E's proposal. It is a reasonable approach that recognizes the market realities and will be adopted.

C. Bottoms-Up Billing

PG&E proposes to provide bottoms-up billing to DA customers, once its new billing system is in place. Under this method, there is no credit. DA customers would pay the sum of transmission (including reliability services), distribution, nuclear decommissioning, public purpose programs, and the fixed transition amount (FTA), where applicable, as well as any nonbypassable charges approved by the Commission for DA customers. DA customers would not pay the average three-cent per kWh and one-cent per kWh generation surcharges; however, they would pay charges the Commission may impose on them, for example, DWR bond charges, applicable DWR power costs, PG&E's ongoing CTC, and PG&E's historic uncollected charges.

In order to implement bottoms-up billing for DA customers, PG&E proposes to amend its tariff to include in distribution rates the costs of the nonfirm discounts, rate limiter adjustments, and power factor adjustments (including standby reactive charges). Since these costs had previously been allocated to generation, they could be avoided by a DA customer billed on a bottoms-up basis. By putting these costs in distribution rates, DA customers will not avoid paying for these discounts. This was approved in the Phase 2 Post-Transition Electric Ratemaking (PTER) decision (D.00-06-034, Ordering Paragraph No. 14). No party objects to PG&E's proposal. This approach is reasonable because it complies with previous decisions and it will be adopted.