II. Background

Since 1998, PG&E and SCE have offered service to two distinct classes of customers. Bundled service customers received the full range of electric services from the utilities, which include energy procurement and delivery. PG&E and SCE customers could also choose, under the DA option, to purchase energy from an electric service provider (ESP). PG&E and SCE continue to deliver electricity to both DA and bundled service customers.

Total rates were frozen at levels in effect on June 10, 1996 for all customers. Bundled service customers paid these frozen rates for the duration of the transition period (January 1, 1998 through March 31, 2002 or a Commission-authorized earlier end date). These frozen tariff rates included a generation rate component. The generation rate was unbundled into a market price and a competition transition charge (CTC) component. The CTC was calculated residually as the difference between the fixed generation rate component and the market price, where the market price was based on the utility's cost of procuring power from the PX and the California Independent System Operator (ISO). All customers pay the CTC and the CTC revenues were to be used to pay for the utility's stranded generation costs, also known as transition costs.

The utilities calculated a market price for billing purposes utilizing the cost and quantities of power purchased from the PX. This PX price was used to determine the contribution to the recovery of CTC (when compared to the generation rate component of frozen rates) and also represented the utilities' avoided cost of procuring energy. The PX component of the generation rate was either applied to recover the cost of purchasing power for bundled service customers or given as a credit to DA customers. The credit reflected the fact that DA customers had chosen to procure their energy through an ESP rather than the utility. So long as the market price, or DA credit, remained below the generation component of the customer's frozen rate, the DA customer continued to make a contribution to CTC in exactly the same manner as a similarly situated bundled service customer.

Because the DA credit was based on the market price from the PX, it was possible that the credit would exceed either the generation bill component or the entire bill. If the PX price exceeded the generation rate component, then customer's bill reflected a negative CTC, i.e., no contribution to recovery of stranded costs. If the PX credit exceeded the entire amount of the bill, meaning that the PX credit was greater than the sum of the generation, distribution, transmission, public purpose, and the other rate components, the customer would receive a negative bill or a credit. In other words, the DA customer would receive a credit for the entire utility bill. This is also known as a "credit" bill.

Prior to June 1999, under the zero minimum bill tariff provision in effect at that time, DA customers receiving the PX credit could experience, at a minimum, a monthly bill of $0. In D.99-06-058, the Commission eliminated the zero minimum bill provision. The elimination of the zero-minimum bill provision allowed DA customers to receive the entire PX credit even if it resulted in a negative (credit) bill. Prior to market dysfunctions in mid 2000, PX credits in excess of total monthly charges were generally carried over to succeeding months and were netted against positive bills.

The dysfunction of California energy markets in mid 2000 through mid 2001, undermined the original basis for calculating the DA credit. The prices charged the utilities during the waning days of the PX were substantially higher than the cost of producing the energy; were regularly higher than the generation component of frozen rates; and in fact, were frequently so high that the DA credit exceeded the entire amount of a DA customer's bill for the services the DA customer did take from the utility and the generation rate component. The PX collapsed in January 2001. Afterwards, consistent with Commission decisions adopting an interim accounting methodology for utility retained generation (URG) and payment mechanisms for recovery of the costs of Department of Water Resources (DWR) power purchases, the utilities based their DA credit on a combination of the costs of URG and DWR-provided power as an approximation of the cost of energy. These changes in the California electricity market require a new method of computing direct access charges.

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