II. The Effective Date of Suspension

For the reasons set forth below, we find that direct access should be suspended as of July 1, 2001. Direct access contracts executed prior to July 1, 2001, pursuant to which electricity flowed prior to July 1, 2001, are not suspended, but are subject to the implementation restrictions imposed by this decision.

A. Facts

The Department of Water Resources has been buying electricity for the retail end use customers of the California utilities (Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E)) since January 17, 2001. It has spent over $10 billion to date and is estimated to spend an additional $8 billion through December 31, 2002. DWR has entered into long-term contracts with various generators to supply electricity to the customers of the three utilities. All DWR purchases to date, including interest, plus the cost of future purchases under the long-term contracts and on the spot market, are the obligations of the ratepayers of the three utilities.³ The undisputed facts show that between July 1, 2001 and September 20, 2001, approximately 11% of the total electric load of the utilities has shifted from bundled service to direct access service. This shift means that 11% of $18 billion ($1.98 billion) will become the obligation of the remaining bundled customers of the utilities should direct access suspension remain fixed at September 20. This result puts bundled customers at a disadvantage and is unfair, unreasonable, and violates Water Code §§ 80002.5 and 80104. Our power to regulate the collection and payment of DWR expenses is specifically authorized by Water Code §§ 80108 and 80104.

1. SCE

Uncontroverted information provided to the Commission by SCE shows that by the second quarter of 2001, the direct access load in its service territory had dropped to less than 1% of SCE's load from a high of 14.8% in December 1999. In June 2001, the direct access load was 1%; by July 31, it reached 3.1%; by October it reached 11.6%.

TABLE 1

Date	Number of DA customers	% of SCE's Cumulative Load
5/31/98	26,761	0.1%
12/31/98	46,898	12.1%
12/31/99	81,883	14.8%
5/31/00	83,896	16.5%
12/31/00	65,965	10.7%
4/30/01	39,882	0.7%
6/15/01	37,774	1.0%
7/31/01	36,411	3.1%
9/21/01	39,789	6.5%
10/26/01	43,570	11.6%

SCE states that since October 2001, its direct access load has increased, and, because Direct Access Service Requests (DASRs) are still being processed and new load is added as customers add new facilities, it expects direct access load to exceed 15%.

2. PG&E

Uncontroverted information provided to the Commission by PG&E shows that in December 2000, PG&E's direct access load was 11.3% of its total load. In the period January 2001 to June 2001, the direct access load was reduced to 1.3% of total load. By October 2001 direct access load had reached 12% of total load and is expected to go as high as 16% when all pending DASRs are processed. The trend in direct access load between May 2000 and October 2001 is shown in Table 2.

TABLE 2

3. SDG&E

Uncontroverted information provided by SDG&E shows that as of November 2001, 50% of its largest customers take direct access service, accounting for 19.4% of its total load.

4. Staff Load Summary

The Commission staff has provided the following table showing the penetration of direct access on the loads of SCE, PG&E, and SDG&E through October 2001.

TABLE 3

We must also add to the departing load figures above an estimate of further increases in direct access load caused by increased usage by direct access customers, contract extensions, and new facilities added to existing contracts. Regardless of the precision of the estimate, a shift of the DWR revenue requirement from direct access customers to bundled customers will occur.

5. The Department of Water Resources (DWR)⁴

The California DWR has been purchasing power for the electric customers of PG&E, SCE, and SDG&E since January 17, 2001 and will continue to purchase power for the foreseeable future. In D.02-02- in A.00-11-038, et al., this Commission determined the method by which the DWR revenue requirement would be met. We allocated DWR costs "in relation to the relevant cost driver, namely the net short position by utility." (D.02-02- at p. 3.)

D.02-02- implements cost recovery of the revenue requirement of DWR relating to its power purchase program pursuant to AB1X. On November 5, 2001, DWR submitted to the Commission its most recent revenue requirement of $10,003,461,000, ⁵ representing the total to be collected from utility customers of the three major California utilities covering the period January 17, 2001 through December 31, 2002. In D.02-02- we held that DWR will collect its revenue requirement through charges remitted from billings to retail customers of the three major electric utilities based on cents per-kWh charges.

The underlying events that caused the need for DWR to purchase power for the utilities are exactly the same events that caused the Legislature to suspend direct access and cause us to adopt July 1, 2001 as the effective date of suspension. In D.02-02- we said:

We note that the high DWR contract prices now in effect in California reflect the exorbitant wholesale electricity costs caused by the crisis manufactured by wholesale electricity sellers and traders over the past year. These rates measure, in part, the terrible price California has had to pay to restore stability. Individual Commissioners and Governor Gray Davis have previously endorsed contract renegotiations to reduce prices that were set when market prices were at or near their peak. (Exhibit 160, Weil, p. 4.) DWR now forecasts that from October 1, 2001 through the end of 2002, average DWR contract prices will be 3.3 times average residual net short prices. (Reference Item C, DWR, November 5 revenue requirement document, p. 16, Table 6; compare DWR contract costs to residual net short costs for Q4 2001 and all of 2002.) DWR assumes that residual net short energy will be purchased in spot markets. (D.02-02- at p. 4.)

The action that we take today in regard to direct access follows the same statutory scheme enacted in response to emergency conditions confronting California's major electric utilities and their customers. On January 17, 2001, Governor Davis issued a Proclamation that a "state of emergency" existed within California resulting from unanticipated and dramatic increases in the wholesale price of electricity. The Governor's Proclamation stated that "unanticipated and dramatic increases in the price of electricity have threatened the solvency of California's major public utilities, preventing them from continuing to acquire and provide electricity sufficient to meet California's energy needs." Governor Davis therefore ordered DWR to assume responsibility for procurement of a major portion of electric power resources for customers of California's three major electric utilities in order to help stabilize market conditions. DWR commenced meeting the utilities' net short requirements⁶ through a combination of contractual power purchases and spot market purchases, including purchases of ancillary services.

Water Code § 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 §80104 explains that "[u]pon the delivery of power to them, 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."

Water Code § 80110 provides that DWR is entitled to recover in rates amounts sufficient to enable it to comply with Section 80134, which are the revenues that may be pledged for support of bonds that DWR is authorized to issue pursuant to Section 80130. Section 80134(a) provides:

"The department shall, and in any obligation entered into pursuant to this division may covenant to, at least annually, and more frequently as required, establish and revise revenue requirements sufficient, together with any moneys on deposit in the fund, to provide all of the following:

(1) The amounts necessary to pay the principal of and premium, if any, and interest on all bonds as and when the same shall become due.

(2) The amounts necessary to pay for power purchased by it and to deliver it to purchasers. ..."

In D.02-02- we established charges to recover the revenue requirement for DWR. The revenue requirement includes forecasts and representations about future events, including issuance of bonds with estimates of reserve requirements and interest rates that may or may not reflect actual conditions at the time the bonds are sold. We made provision for adjustments of the DWR revenue requirement. In periodic updates, variances between forecast and actual results can be taken into account. An overcollection in one year would reduce the next year's revenue requirement and the charges needed to recover it. In D.02-02- we adopted the DWR revenue requirement for the period January 17, 2001 through December 31, 2002, allocated it between the three utilities, and applied the allocation to each utilities' electric sales volumes on a cents-per-kWh basis, to produce the revenue to pay for DWR AB1X - authorized costs.

DWR's updated revenue requirement for all three utilities totals $10.003 billion, as summarized in Appendix A of this decision. The revenue requirement represents total expenditures of $18.014 billion, less the proceeds from external bond financing. The remaining balance of $10.003 billion is the DWR revenue requirement to be recovered from utility customers covering the period January 17, 2001 through December 31, 2002.

DWR's estimated administrative and general expenses of $99 million are summarized by quarter in Appendix A. Interim loan costs of $1.281 billion are included under "Financing Cost" in Appendix A. These loan costs represent principal and interest payments on a $4.3 billion interim financing entered into by DWR on June 26, 2001. The interim loan proceeds reduce the amount of revenues that would otherwise be required currently from customers. DWR plans to retire this interim financing from the proceeds of long-term bonds. AB1X authorizes DWR to issue up to approximately $13 billion in bonds to support its power purchase program. The bonds are projected to be issued at the end of June 2002 and to have a final maturity date of May 1, 2016. Until the bonds are sold, DWR is relying on the interim borrowing arrangements. Future ratepayers will be obligated to repay bond principal, together with accrued interest, in addition to paying for DWR power that they consume.

In D.02-02- we described the need for annual revisions of DWR's revenue requirement as prescribed in Water Code § 80134(a), and we scheduled June 1, 2002 as the date DWR would submit its revenue requirement forecast for the period January 1, 2003 through December 31, 2003. Recognizing that DWR's revenue requirement is based on forecasts that may prove incorrect over time, we requested DWR to make the necessary adjustments to reflect the variance between actual and forecasted costs. At the designated time for DWR to submit its revised forecast for the coming year, DWR will also submit its true-up of the prior periods' differences between forecasted and actual data. The difference between actual costs incurred and actual revenues collected by DWR will result in either an undercollection or overcollection, to be assigned to the bundled customers of each utility.

Appendix A to this decision sets forth the details of the DWR revenue requirement that was implemented in D.02-02- . Appendix A to this decision is a duplicate of Appendix A in D.02-02- , of which we take official notice. For the purposes of this decision we are concerned (as was the Legislature) with the shift in costs as direct access customers leave the system.

From Appendix A the following costs are fixed for the period January 17, 2001 through December 31, 2002:

(millions)

1. Administrative and General (A&G) $ 98.8

2. Demand Side Management (DSM) 288.9

3. Financing 1,281.0

$1,668.7

use $1.7 billion

DWR has based its revenue requirement forecast on its estimate that 11% of total load has left bundled service since July 1, 2001.⁷ The UDCs have made a similar estimate. The cost shift of fixed overheads is $187,000,000 over two years ($1.7 billion x .11 = $187 million). This $187 million does not include the avoided responsibility for the excess costs portion of $5.2 billion in DWR contracts, nor the avoided responsibility for the repayment of the $8.5 billion in bonds to be issued later this year.

B. Modification of the Suspension Date

To comply with legislative intent, to fulfill the purpose of the applicable statutes, to form the broadest base upon which to build the repayment structure required to meet the DWR revenue requirement, to prevent a cost shift of over $187 million dollars between now and December 31, 2002, and to assure that amounts recovered from customers for DWR costs are just and reasonable, we determine that it is in the public interest to modify the date of suspension of direct access from September 20, 2001. Therefore, direct access is suspended as of July 1, 2001. Direct access contracts executed prior to July 1, 2001, pursuant to which electricity flowed prior to July 1, 2001, are not suspended, but are subject to the implementation restrictions imposed by this decision.

The increase in direct access load between July 1, 2001 and September 20, 2001 is extraordinary. Some refer to it as "the gold rush." From 2% of total utility load as of June 2001, the direct access load increased by 11% as of September 2001.

In addition to the shift in DWR fixed costs for the period January 17, 2001 - December 31, 2002, of $1.7 billion, reductions in electric loads due to direct access place burdens on the remaining electric customers of the investor-owned utilities in two ways. First, there are out-of-pocket costs, which have been incurred by DWR for electricity purchases since January 17, 2001, which have yet to be reflected on customers' bills. This uncollected amount is currently estimated to be approximately $8.5 billion. (This is expected to be financed through the issuance of DWR's revenue bonds.) If, for example, 11% of customer load leaves the system through direct access, the uncollected amount must be borne by the 89% of customer load remaining; an incremental $935 million (i.e., 11% of the $8.5 billion currently uncollected), as well as associated financing costs.

The second burden on the remaining customers results from the future costs of the "net short." Under AB1X, DWR is purchasing energy under long-term contracts to provide electric energy that cannot be met by utility generation, and purchasing energy on the spot market for demand in excess of its contracts. The cost of that purchased power is to be paid by the utilities' bundled customers. AB1X provided for the Commission to suspend direct access in recognition of the fact that DWR would be entering into long-term contracts and that bundled customers must pay the bill. Direct access customers are typically commercial and industrial customers with high load factors. The departure of their load, to the extent it had been covered by existing DWR power contracts, will increase DWR's per unit costs by either forcing DWR to sell its excess energy on the spot market or by reducing the average system load factor on generating facilities subject to DWR contracts. In either event, DWR's per unit costs to its remaining customers increases. When spot market prices are generally lower than the DWR average per unit contract costs, reduction in load will result in an increase in the average cost of DWR energy (by resulting in less lower cost, spot market purchases).

The arguments of those who protest changing the suspension date of direct access from September 20, 2001, to July 1, 2001 fall into two broad categories: 1) customers have executed contracts with ESPs in reliance on our September 20 date, and 2) changing the suspension date to July 1, 2001 is an impairment of contracts entered into between July 1 and September 20. Both arguments are without merit.

1. Reliance

California Manufacturers & Technology Association (CMTA) and others argue that because the Commission never acted formally to suspend direct access until September 20, 2001, the Commission allowed the direct access program to remain effective and, accordingly, customers continued to execute direct access contracts up until September 20, 2001. Thus, those customers that executed direct access contracts during this period were doing exactly what the Commission allowed them to do.

As a matter of public policy, they believe it is critical that the Commission adhere to a stable set of rules which affect customers, ESPs, and the utilities. They claim it would be extremely disruptive at this juncture for the Commission to attempt to establish a direct access suspension date earlier than September 20, 2001. Customers have bargained for their direct access contracts and if those contracts were to be nullified by establishing an earlier suspension date, customers would lose the benefit of their bargain, primarily in the form of lower electric costs. Moreover, in many cases an earlier suspension date would cause customers to incur substantial contract termination costs. Even in those instances where so-called "regulatory out" clauses exist, CMTA argues, customers nevertheless would be harmed by virtue of having to pay higher electric costs by returning to bundled utility service. An abrupt and possible retroactive increase in costs for many business customers would be extremely harmful to their business operations and overall viability.

CMTA's argument is not persuasive. The right to acquire direct access is a legislative and regulatory right. It was established in AB 1890 (Pub. Util. Code § 365(b)(1)) and was implemented through Commission decisions (e.g., D.97-10-087, 76 CPUC 2d 294) and utility tariffs (Rule 22). All contracts made regarding direct access are subject to modification by the Commission.

The background of direct access is set forth in D.97-05-040 (72 CPUC 2d 441). In D.97-05-040, the Commission ordered the utility distribution companies (UDCs) to file their direct access implementation plans (DAIPs), along with their pro forma tariffs. Prior to the submission of the DAIPs, the UDCs were ordered to meet with interested parties in an attempt to reach agreement on the procedures needed to implement direct access. Workshops were scheduled, which resulted in the formation of the Direct Access Alliance (Alliance), represented diverse participants in the direct access market. The utilities began talks with representatives from the Alliance seeking consensus on direct access tariffs and service agreements for statewide use. The participants were able to reach a consensus on a set of proposed tariffs for statewide use. D.97-10-087 was the result.

In regard to the issue of modification of direct access, D.97-10-087 is specific and clear. It holds that the Commission has exclusive jurisdiction to resolve interpretations of, modification of, or compliance with any of the direct access tariff provisions or the ESP-UDC service agreement. (76 CPUC 2d at 310.) We ordered the following tariff provision to be included in the tariffs of the three UDCs:

"The CPUC shall have initial jurisdiction to interpret, add, delete or modify any provision of this tariff or the ESP-UDC Service Agreement, and to resolve disputes regarding the UDC's performance of its obligations under the UDC's electric rules and tariffs, the ESP UDC Service Agreement and requirements related to Direct Access service, including any disputes regarding delays in the implementation of Direct Access." (D.97-10-087, 76 CPUC 2d at 310.)

A service agreement between the UDCs and ESPs was approved. (Appendix B to D.97-10-087), subject to terms and conditions (Appendix A of D.97-10-087) which "apply to both UDC customers and electric energy service providers who participate in Direct Access." (D.97-10-087, 76 CPUC 2d at 336.) (Emphasis added.)

Among those terms and conditions is that:

"The CPUC shall have initial jurisdiction to interpret, add, delete or modify any provision of this tariff or the ESP-UDC Service Agreement and to resolve disputes regarding the UDC's performance of its obligations under the UDC's electric rules and tariffs, the ESP-UDC Service Agreement and requirements related to Direct Access service, including any disputes regarding delays in the implementation of Direct Access." (Id. at p. 340.)

In regard to direct access we provided that the ESP was subject to the UDCs tariffs and our jurisdiction.

"The ESP must satisfy the following requirements before an ESP can provide Direct Access services in the UDC's service territory:

"(1) All ESPs must submit an executed standard Energy Service Provider Agreement (UDC-ESP Service Agreement) in the form attached hereto." (Id. at p. 342.)

Finally, in regard to the UDC-ESP Service Agreement we provided that:

"1.2 The form of this Agreement has been developed as part of the CPUC regulatory process, was intended to conform to CPUC directions, was filed and approved by the CPUC for use between UDC and ESPs and may not be waived, altered, amended or modified, except as provided herein or in the relevant direct access tariff, or as may otherwise be authorized by the CPUC." (Id. at p. 366.)

"21.2 This Agreement may be subject to such changes or modifications as the CPUC may from time to time direct or necessitate in the exercise of its jurisdiction, and the Parties may amend the Agreement to conform to changes directed or necessitated by the CPUC." (Id. at p. 373.)

Direct access is authorized by statute, implemented by Commission decisions, and binds ESPs and UDC customers alike through Commission approved terms and UDC tariffs, both of which specifically provide for modification by the Commission.

Not only do Commission decisions and utility tariffs provide for modification of direct access agreements, but the issuance of a series of proposed decisions show that a July 1 suspension date was a distinct possibility.

1. On June 15, 2001, a draft decision was issued proposing a July 1, 2001, suspension date.

2. On August 15, 2001, a revised draft decision was issued proposing a September 1, 2001, suspension date.

3. On August 27, 2001, a revised draft decision was issued proposing a July 1, 2001, suspension date.

4. On September 20, 2001 a decision was issued suspending direct access as of September 20, 2001, and expressly stating that the suspension date would be revisited and, perhaps, be made effective on a date earlier than September 20, 2001.

Given the changes in various draft decisions, the specific reservation of authority to change the suspension date, and the prior decisions of the Commission reserving the right to modify the terms and conditions of direct access, we cannot accede to the view that electric customers relied on a permanent September 20 suspension date. Those customers want it both ways. They want the option to return to utility service at anytime, as many did in the first half of 2001 (see Table 3, above), but be able to choose direct access when it suits them. That 11% or more of load can switch back and forth between utility service and ESP service creates uncertainty for both DWR in its purchases and the UDCs in their service obligations, all to the detriment of the bundled customers. Direct access customers benefited when DWR entered into long-term contracts: the spot price of electricity came down, below DWR contract prices, making ESP contracts attractive, and a safety net of a return to UDC service was provided should spot prices again run wild. Meanwhile, the bundled customer pays the freight. This free ride is unreasonable and discriminatory.

We choose July 1 because the showing in this proceeding is that 11% of electric load has shifted from the UDC retail load to direct access load during the period July 1 through September 20, resulting in a cost shift of over $187 million⁸ to be recovered from the remaining retail end use customers: the customers taking bundled service. It is unjust and unreasonable to permit a substantial group of customers to avoid paying for costs incurred for their benefit.

Direct access is driven by economics. When consumers believe it is cheaper to buy electricity from an ESP they will enter into a direct access contract, rather than choose a UDC. Table 3, above, shows that clearly. DWR began stabilizing the California electric market in January 2001, by February the direct access market dropped 70%; by March another 50% was sliced from the direct access market. This figure (2% of total load) remained constant until the Assigned ALJ's Proposed Decisions proposed conflicting dates to suspend direct access. The uncertainty of the suspension date - July 1 or September 20, initiated the gold rush. But, what was clear to all parties was the reservation in D.01-09-060 of the Commission's intent to consider reverting the suspension to a date earlier than September 20, with July 1 being the likely date.

To accede to those who oppose the change of the suspension date to July 1, would be to permit them 1) to avoid paying their fair share of the DWR costs to stabilize the California electric market, 2) to avoid paying for the excess costs of the DWR long term contracts, 3) to avoid paying for the costs of the bonds DWR is expected to issue shortly and, 4) to grant them the option to return to bundled service should the economics become favorable or their ESP fail. It should not be forgotten that the UDCs are the default provider of electric service for all in their service territory. To permit the September 20 date to stand is unfair to all bundled customers. It permits a fortuitous group of customers to benefit and at the same time avoid the cost of that benefaction.

2. Impairment of Contracts

Our authority to change the suspension date from September 20 to July 1 is well grounded in our statutory authority (Pub. Util. Code § 701, 1708), our decisions in this area, discussed above, UDC tariffs filed in conformance with our decisions,⁹ and case law.

The constitutional restriction against impairment of contracts has no bearing here where a state is exercising its regular police power in the public interest. The contracts clause of the United States Constitution (Article 1, Sec. 10, cl. 1) prohibiting the government from impairing contracts is not to be read literally and does not bar legislation designed to further a significant public interest objective from impacting private contracts.¹⁰

The purpose of AB1X is to ensure that the State of California is paid for the obligations incurred by DWR during the statewide electricity crisis on behalf of utility customers, including the recently switched direct access customers. Clearly the contractual rights of a subset of utility customers who have chosen direct access must yield to this larger purpose.

An analysis of Water Code § 80110 is instructive regarding the suspension date. First, the section specifically states that this Commission's authority "as set forth in Section 451 of the Public Utilities Code shall apply...." Pub. Util Code § 451 states that all charges "shall be just and reasonable." Second, rather than choosing a date to suspend direct access, the Legislature authorized the Commission to pick the date.¹¹ Had the Legislature suspended direct access on the date of enactment of Water Code § 80110 (February 1, 2001) the direct access load would have been approximately 13% of total load (Table 3, above). By authorizing this Commission to choose the date flexibility was introduced into the process to assure maximum benefit to all ratepayers, that is, to produce just and reasonable rates. All who benefit from DWR purchases will bear the burden. To hold to the September 20 date with a total direct access load approaching 15%, not only would negate the Legislature's purpose in suspending direct access, but also would be a greater burden than if the Legislature had suspended direct access on February 1, 2001. Essentially, the proponents of September 20 (and assignments and add-ons) imply that the legislative interest was to provide a choice based on happenstance, the fortuitous choice of a date, rather than choice based on an analysis of the facts as applied to the purpose of the statute. The purpose of the statute is to recover the DWR revenue requirement from as broad a base of ratepayers as reasonably possible. July 1^st does it; September 20^th, does not.

We have been granted by the Legislature the power to determine the date upon which suspension of direct access is to occur (Water Code § 80110) and have determined that we are acting in our quasi-legislative capacity. (Rulemaking 02-01-011, Ordering Paragraph 5; Pub. Util Code § 1701.1.) In the exercise of the power granted to us by the Legislature we have determined that the effective date of the suspension should be July 1.

The argument that we have no authority to choose a date earlier than September 20 is not persuasive. We believe an analysis based on the holding in United States v. Sperry Corp. (1989) 493 US 52, 107 L Ed 2d 290, 110 S Ct. 387, is dispositive.

Congress in 1985 enacted a statute requiring reimbursement to the United States for government expenses incurred in connection with the arbitration of claims. The statute was made retroactive to June 7, 1982. Sperry had been a successful claimant and had received its award prior to the enactment of the statute.

In upholding the statute, the Court said:

"[R]etroactive legislation does have to meet a burden not faced by legislation that has only future effects. `It does not follow . . . that what Congress can legislate prospectively it can legislate retrospectively. The retroactive aspects of legislation, as well as the prospective aspects, must meet the test of due process, and the justifications for the latter may not suffice for the former.' But that burden is met simply by showing that the retroactive application of the legislation is itself justified by a rational legislative purpose." Pension Benefit Guaranty Corporation v R. A. Gray & Co. 467 US 717, 730, 81 L Ed 2d 601, 104 S Ct 2709 (1984) (quoting Usery v. Turner Elkhorn Mining Co. 428 US 1, 16-17, 49 L Ed 2d 752, 96 S Ct 2882 (1976) (citation omitted).

[2b] We agree with the United States that the retroactive application of § 502 is justified by a rational legislative purpose. Retroactive application of § 502 ensures that all successful claimants before the Tribunal are treated alike in that all have to contribute toward the costs of the Tribunal. If Congress had made the application of § 502 prospective only, the costs of the Tribunal would have fallen disproportionately on the claimants whose awards, for whatever reason, were delayed, and Congress might have had to increase the percentage charge on those claimants to recoup a sufficient portion of the Federal Government's costs. Claimants who were fortunate enough to obtain awards prior to the enactment of the statute would have obtained a windfall by avoiding contribution. It is surely proper for Congress to legislate retrospectively to ensure that costs of a program are borne by the entire class of persons that Congress rationally believes should bear them. Cf. Pension Benefit Guaranty Corporation v R.A. Gray & Co., supra, at 730, 81 L Ed 2d 601, 104 S Ct 2709; Usery v Turner Elkhorn Mining Co., supra, at 18, 49 L Ed 2d 752, 96 S Ct 2882. (U.S. v Sperry 493 US at 64-65, 107 L Ed 2d at 304.)

The rationale of Sperry fits the facts of changing the date of direct access suspension from September 20, to July 1. The legislative purpose of Water Code § 80110 is to ensure that all ratepayers are treated alike in that all have to contribute to the DWR revenue requirement, which has benefited all ratepayers. If we suspend prospectively only, the DWR revenue requirement would have fallen disproportionately on those who, for whatever reason, chose not to switch to direct access. Direct access customers who were fortunate enough to sign contracts prior to September 20 would receive a windfall by avoiding contribution. It is surely proper for this Commission to regulate retrospectively to ensure that the costs of a program are borne by the entire class of persons that the Legislature believes should bear them.

3. Backbilling

SDG&E, and others, argue that to impose a suspension date prior to September 20 would require the utility to backbill for the period between the new suspension date and September 20. They say that a direct access transaction that occurred before September 20, 2001 contemplates that an ESP actually sold power to a customer, its customer incurred an obligation to pay for that power, and the customer paid the ESP for that power. The UDCs now cannot unwind that completed transaction and recast it into a bundled service transaction. The UDC cannot bill for service it did not provide.

We agree that the utility cannot bill for service it did not provide, and that backbilling would be an inappropriate result of our choosing a suspension date prior to September 20. Our purpose in choosing a suspension date is to obey the legislative direction and fix the time at which direct access and the direct access provisions of contracts are suspended "until the department no longer supplies power hereunder." (Water Code § 80110.) Backbilling simply is not an issue.

However, finding backbilling to be a nonissue does not eliminate the need to resolve the issue of cost responsibility of direct access customers for the DWR's revenue requirement. This issue is to be resolved in A.00-11-038, et al. (See ALJ Ruling of December 24, 2001, transferring the issue from A.98-07-003, et al., to A-00-11-038, et al.) As discussed elsewhere in this opinion, the purpose of direct access suspension is to assure that those who benefit from DWR's electricity purchases do not escape responsibility to pay for that benefit.

Upon the delivery of power to them, 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.