VI. Legal Authority for Imposing Cost
Responsibility Surcharges

We conclude that requisite legal authority exists as a basis to authorize and implement the cost responsibility surcharges adopted in the instant order. Particularly, this authority is found in AB 1X. Water Code Section 80110 gives the Commission authority to assess "charges" so that DWR can recover the costs it incurred or incurs from retail end use customers in the service territories of the three major utilities. (Water Code § 80110, see also, e.g., § 80104. [Direct obligation of the retail end use customer.]) Water Code § 80134(a) specifies what these costs are enumerated as subitems 1 through 6.

Further, under Pub. Util. Code § 701, the Commission has broad authority to regulate and to "do all things...which are necessary and convenient in the exercise of such power and jurisdiction."¹² Moreover, as a general matter and consistent with the law, the charges or rates imposed by this Commission must be "just and reasonable" and must not be unfairly discriminatory. (See Pub. Util. Code §§ 451 and 453.) In accordance with these statutory requirements, bundled customers may not be arbitrarily charged for obligations which rightfully are the responsibility of DA customers.

A. DWR-Related Costs

Within the broad statutory authority outlined above, the Commission has specific authority to establish charges for the collection of costs incurred by DWR pursuant to AB 1X. We conclude that this authority applies not just to bundled customers, but also extends to charges imposed on DA customers to the extent that DWR purchased power on their behalf or for their benefit. (See, e.g., Water Code § 80000 [enactment necessary to protect the public during the energy crisis].

DWR began buying electricity on behalf of the retail end use customers in the service territories of the California utilities: for PG&E and SCE on January 17, 2001, and for SDG&E on February 7, 2001. AB 1X provides for funds to DWR from revenues generated by applying charges to the electricity that it purchased on behalf of retail end-users. AB 1X requires that DWR include in its revenue requirement "...amounts necessary to pay for power purchased by it...." (Water Code Section 80134(a)(2).)

Water Code Section 80002.5 states that "[i]t is the intent of the Legislature that power acquired under this division shall be sold to all retail end use customers served by electrical corporations, ...." Water Code Section 80104 explains that "the retail end use customers shall be deemed to have purchased that power from the department. Payment for any sale shall be a direct obligation of the retail end use customer to the department." Thus, consistent with the provisions of the Water Code, those DA customers that took bundled service on or prior to September 20, 2001 are responsible for paying a share of the DWR revenue requirements. The DWR costs for which DA customers bear responsibility include both previously incurred costs as well as an ongoing cost component. For previously incurred costs, DWR has not yet received full payment. The State of California is in the process of finalizing the sale of bonds to finance DWR's prior undercollections, and bond charges are being determined in A.00-11-038 et al. In Section IX, we address the legal and policy issues relating to DA customers' responsibility for paying a share of the bond costs.

B. Non-DWR Related Costs

Certain parties argue that the IOUs' ability to collect utility-related costs from DA customers expired under the provisions of AB 1890 effective after March 30, 2002, and that without specific legislation, the attempt to charge such costs violates the rule on retroactive ratemaking and Public Utilities Code Section 728. When customers entered into their DA agreements, the Commission had already established non-bypassable charges to be paid by DA customers, as authorized by AB 1890. These parties claim that AB1X does not give the Commission the authority to impose a new surcharge for non-DWR costs, and do not believe any other statute gives the Commission the authority to impose surcharges that are not in any way related to the delivery of electricity to DA customers.

We also conclude that legal authority exists for imposing charges on all DA customers for their share of the uneconomic utility-related costs. In this regard, Public Utilities Code Section 370 expressly states that DA customers are required to bear enumerated "transition" costs:

The commission shall require, as a pre-requisite for any consumer in California to engage in direct transactions permitted in Section 365, that beginning with the commencement of these direct transactions, the consumer shall have an obligation to pay the costs provided in Sections 367, 368, 375, and 376, and subject to the conditions in Sections 371 to 374, inclusive, directly to the electrical corporation providing electricity service in the area in which the consumer is located.

Public Utilities Code Section 369 provides further that "[t]he commission shall establish an effective mechanism that ensures recovery of transition costs referred to in Sections 367, 368, 375, 376, and subject to the conditions in Sections 371 and 374, inclusive, from all existing and future consumers in the [utility's] service territory . . . ."

These "transition costs" were originally envisioned as a byproduct of a industry restructuring program to provide for a competitive environment pursuant to legislative enacted in AB 1890. As originally envisioned, AB 1890 provided for an "orderly" transition to a competitive generation market which would be completed by March 2002. (Pub. Util. Code § 330.)¹³

Public Utilities Code Section 368(a) established that electric rates would remain fixed at the June 10, 1996 levels, except for residential and small commercial customer rates which were reduced by 10%. These frozen rates, along with a residual component of rates specifically delineated as the Competition Transition Charge (CTC), allowed the utilities to accrue the revenues to collect transition costs.

The Commission was further directed by § 367(e)(2) to ensure that bundled service customers "shall not experience rate increases as a result of the allocation of transition costs."

AB 1890 provided certain exceptions to the general rule that all CTC must either be recovered within the rate freeze period, or not collected. The Commission's second Post Transition Ratemaking (PTR) order (D.00-06-034) considered these exceptions. There, the Commission directed that, at the end of the rate freeze, all customers, bundled and DA, will pay a CTC charge that will be adjusted annually, to cover ongoing recoverable above-market QF power costs and some minor employee-related transition costs. According to the decision, both groups of customers will pay a CTC charge that will be trued up annually and that this charge will be based on a forecast of expected above-market costs.

When the Commission addressed this "Tail" CTC in D.00-06-034, it envisioned a largely unregulated generation market after the end of the rate freeze. Because utilities would be at risk in the market for recovery of their generation costs, it was important that they have assurance of recovery of these identified costs through an ongoing CTC charge.

After the extreme escalation in wholesale prices which began in Summer 2000, however, it became apparent that California's transition to electricity deregulation was not working. Beginning 2001, the Legislature responded by enacting emergency measures to deal with the energy crisis. Among these measures was Assembly Bill No. 6 from the First Extraordinary Legislative Session (AB 6X). AB 6X prohibited divestiture of any "facility for the generation of electricity owned by a public utility" prior to January 1, 2006 and stated that "[t]he Commission shall ensure that public utility generation assets remain dedicated to service for the benefit of California ratepayers." AB 6X also amended existing statues to delete any reference to the market valuation of the utilities' generation assets, which had been an essential step in the calculation of the utilities' uneconomic costs. (Pub. Util. Code, § 367, subd. (b).)

Certain parties argue that in view of AB 6X, there is no risk of non-recovery of generation costs and no need for ongoing CTC because such costs will be included in cost of service based rates. Yet, nothing in AB 6X rescinds the intent of the Commission that all customers, including DA, should pay a charge for the uneconomic cost of QF power. While the utilities' generation portfolio are likely to contain both above market and below market assets, they will collect the costs of the overall portfolio from their customers, as provided in this order.

The recovery of the uneconomic costs associated with QF and other purchased power contracts initiated before December 20, 1995 is allowed by AB 1890 (Section 370) through ongoing CTC. AB 1890 further directed the Commission to collect three distinct categories of costs from all customers after March 31, 2002. Under Section 367(a)(2), the Commission must collect the following categories from all ratepayers: (1) "employee-related transition costs" through December 31, 2006, (2) "power purchase contract obligations" for the duration of the contracts, and (3) above-market Incremental Cost Incentive Prices (ICIP) associated with SCE's San Onofre nuclear generating plant through December 31, 2003.¹⁴ Electric restructuring implementation costs are also allowed to be recovered after the rate freeze.¹⁵

The Commission is giving further consideration to issues surrounding the end of the rate freeze, along with the extent and disposition of transition (stranded) costs left unrecovered. (D.02-01-011, p. 25 (slip op.).) Moreover, the Commission is also giving further consideration to what rate levels are necessary to assure utilities are reasonably creditworthy and financially healthy, in order for utilities to fulfill their responsibility to procure and deliver reliable, safe and adequate electricity. The result may or may not require a continuation of rates at frozen rate levels. We recognize that the timing of the end of the rate freeze, the corresponding impact on transition cost recovery, and the definition of what were formerly considered stranded costs are issues that are being considered in A.00-11-038 et al., in the rehearing of D.01-03-082, as ordered by D.02-01-001. We are also considering in that proceeding the impact of AB 6X and AB 1X on the various provisions of AB 1890. Here, we find that ongoing CTC should be included in DA CRS. This determination of DA CRS concerning non-DWR costs may be subject to subsequent adjustment, depending on our further consideration and determination in A.00-11-038 et al., and other related pending proceedings. We do not prejudge or intend to prejudge the the outcome of these pending matters in today's decision.

In SCE's case, Resolution E-3765 has already extended the rate freeze to collect the 2000-2001 wholesale purchased power undercollection. The Commission has proposed a similar remediation in the U.S. Bankruptcy Court for PG&E, and if adopted by the court, would satisfy this part of AB 1890 for PG&E. Since SDG&E ended its rate freeze before December 31, 2001, this provision of AB 1890 would not apply to it.

Another category of costs included in the scope of costs subject to CRS is the past wholesale undercollection from the 2000-2001 energy crisis incurred by the utilities before DWR began procuring electricity on the behalf of utility customers. The responsibility for direct access customers to pay for SCE's undercollection reflected in its Procurement Related Obligations Account (PROACT) has been addressed in A.98-07-003. We issued D.02-07-032¹⁶ in that proceeding, establishing a Historical Procurement Charge (HPC) of 2.7 cents/kWh for all DA customers, to remain in effect until a CRS is established in this proceeding. The HPC is intended to allow the PROACT balance to be recovered from DA customers to the extent they are responsible for those costs that will be incurred. Effective with the implementation of a DA CRS in this proceeding, D.02-07-032 orders that the HPC charge shall drop to 1.0 cents/kWh until the undercollection of $391 million is recovered.