11. Rehearing and Judicial Review

This decision construes, applies, implements, and interprets the provisions of AB1X (Chapter 4 of the Statutes of 2001-02 First Extraordinary Session). Therefore, § 1731(c) (applications for rehearing are due within 10 days after the date of issuance of the order or decision) and § 1768 (procedures applicable to judicial review) are applicable.

Findings of Fact

1. The record of the public participation hearings confirms that past electric rate increases and the prospect of more increases are deeply impacting the citizens, businesses, and economy of SDG&E's service territory, and that additional rate increases will inflict additional hardship upon the region. Accordingly, we intend to approve only those rate increases that are required to maintain system reliability and that are required as a matter of law.

2. DWR is authorized to procure power, and to determine and recover its revenue requirement for power that it sells to retail end use customers served by electrical corporations.

3. DWR is currently procuring and providing power to SDG&E's retail end use customers.

4. The Draft Decision on the DWR revenue requirement in A.00-11-038, et al. proposes that SDG&E be directed to begin disbursements of proceeds to DWR on a monthly basis using a system average charge of 9.02 cents per kWh for each kWh sold by DWR to SDG&E's customers, and this charge results in a system-average rate increase for SDG&E that is at the lower end of a possible range of such increases.

5. Taking into account a DWR charge of 9.02 cents per kWh, the current rate of SDG&E's disbursements to DWR, and the forecast that 58% of SDG&E's total bundled retail sales will be supplied by DWR, a system average rate increase of 1.46 cents per kWh will implement the DWR revenue requirement allocable to SDG&E's customers on an interim basis pending the DWR revenue requirement decision in A.00-11-038, et al.

6. To the extent that the actual percentage of DWR sales to SDG&E's retail end use customers is either less than or exceeds the 58% forecast percentage of DWR sales to those customers for any month, the customer's bill for that month will not exactly provide the imputed utility rate for the kWhs the utility provides.

7. It is not our intent that the utility ultimately recover either more or less than the imputed utility rate for the kWhs it provides.

8. Our objectives in this decision include establishing rates that will ensure that the DWR revenue requirement allocable to SDG&E's ratepayers is collected from such ratepayers while avoiding or mitigating rate shock; observing and giving effect to the second sentence of § 332.1(f); observing and promoting principles of equity in the allocation of revenue responsibility and rate design; promoting energy conservation in the establishment of rate structures; and observing and recognizing legal requirements and practical constraints.

9. The constraints on obtaining and analyzing evidence concerning the underlying cost components limit our ability to apply cost-based principles in assigning revenue responsibility to customer classes and in designing individual rate structures.

10. FEA's cost-based revenue allocation methodology is complex, has not been adequately examined in this expedited proceeding, and requires acceptance of untested assumptions about costs underlying the DWR revenue requirement.

11. Given the unpredictability of the current flawed electric market, it is reasonable to simplify cost allocation methods.

12. Subsidizing agricultural customers by capping average rate increases at 20% for TOU rates and 15% for non-TOU is consistent with our adopted policy in D.01-05-064; there is no record evidence justifying a different policy on agricultural subsidies in this case; and extending such subsidies to SDG&E's customers is consistent with legislative intent in § 332.1(f).

13. Water Code § 80110 provides that residential customer usage up to 130% of baseline quantities is exempt from increases in electricity charges, and proposals to exempt residential CARE and medical baseline customers from rate increases are uncontested.

14. Allocating shortfalls from the CARE and medical baseline exemptions and the agricultural rate caps to all other customers on an equal cents per kWh basis is uncontested and is generally consistent with our allocation of shortfalls in D.01-06-064.

15. The 1/3 residential; 1/3 commercial; 1/3 industrial allocation method adopted in Decision 01-05-064 does not work for SDG&E, which has a combined commercial/industrial classification and a much different mix of customer classes than either PG&E or Edison.

16. Allocating the revenue shortfall from the 130% of baseline exemption only to non-exempt residential consumption would create severe rate spikes, and set an unnecessarily high conservation price signal which would apply to less than 15% of total forecast sales.

17. It is equitable to allocate the shortfall from the 130% of baseline exemption on an equal cents per kWh basis to all non-exempt customers.

18. There is no evidence supporting tiered rate design for non-residential rates.

19. No party opposes SDG&E's proposed adoption of the 5-tier rate design structure that was adopted in D.01-05-064 for PG&E and Edison.

20. Tiered residential rates are appropriate both because of their conservation effects and because of the statutory exemption of consumption up to 130% of baseline quantities.

21. The design of rates requires the exercise of judgment, and cannot rely solely on mathematical formulas. We have exercised our institutional judgment and experience in designing a tiered residential rate structure that balances the need to provide conservation signals, the need to collect the revenue requirement allocated to the residential class, and the need to prevent undue bill impacts.

22. We intend to preserve the five-tier residential rate structure until we have had an opportunity to more fully consider all aspects of SDG&E's rate design in a proceeding dedicated to that purpose.

23. Due to billing system constraints, SDG&E may not be able to implement the medical baseline rate exemption immediately.

24. If the commodity rates for residential TOU rate schedules are not tiered like the non-TOU residential rate schedules, customers will have an incentive to switch rate schedules simply to avoid an increase.

25. The large customer rates adopted today are consistent with the requirement of § 332.1(f) that we consider adjustments to the initial frozen rate of 6.5 cents per kWh based on consideration of comparable energy components of rates for comparable customer classes served by PG&E and Edison.

26. Renaming the ERCRSA as the ERSA, and recording large customer shortfalls and overcollections in the ERSA separately from the small customer shortfall, will maintain consistency with current tariffs and facilitate the transfer of any applicable TCBA overcollections to the ERSA to offset the required retroactive credits to February 7, 2001.

27. The primary purpose of the ERSA mechanism is to record SDG&E's costs for URG, ancillary services and ISO costs, and related revenues, refunds, and authorized balancing account transfers. DWR-related revenues collected by SDG&E on behalf of DWR shall be segregated from SDG&E's revenues.

28. The voluntary program for large customers adopted by D.00-12-033 is unnecessary with implementation of the frozen rate component under ABX1 43, does not work as intended due to SDG&E's inability to true-up accounts to reflect DWR costs, and has no customers currently enrolled.

29. It is of critical importance to implement the DWR increases on a timely basis to provide assurance to DWR that it will receive its identified revenue requirement, thereby maintaining the ability of the State of California to procure power on behalf of retail end use customers.

30. The circumstances leading to our decision today include the following: we must act expeditiously to increase rates in order to implement the DWR revenue requirement to protect the ability of DWR to procure electricity; we are

implementing an urgency statute enacted "to safeguard economic viability of the communities in the San Diego region;" we are implementing rate designs to promote demand reduction in order to mitigate the frequency and duration of rolling blackouts throughout California; and on January 17, 2001 Governor Gray Davis declared a state of emergency in connection with the electric crisis. These circumstances, and the fact that we did not receive the latest revised DWR revenue requirement request until August 7, 2001, constitute an unforeseen emergency.

31. Parties were provided notice of the expedited schedule, and no objections to the reduced comment period were raised. We therefore assume that all parties have stipulated to a reduction of the 30-day periods specified in § 311(d).

32. In this order, we are not approving the individual components underlying SDG&E's calculations, including those with respect to URG, ISO charges, and sales forecasts.

33. There has not been adequate opportunity to consider issues pertaining to franchise fees in this proceeding.

Conclusions of Law

1. In accordance with Water Code §§ 80110 and 80134, and pending a decision in A.00-11-038 et al. regarding the DWR revenue requirement, an interim DWR charge of 9.02 cents per kWh for each kWh sold by DWR to SDG&E's retail end use customers should be included in total electric rates for SDG&E.

2. The Commission is obligated by law to implement the DWR revenue requirement and to establish rates for SDG&E's customers, payable to DWR, that will provide for the collection of the DWR revenue requirement that is attributable to SDG&E's customers.

3. Pursuant to Water Code §§ 80016, 80110, and 80134, and our general obligation, under the Public Utilities Act, to ensure the provision of safe and reliable service by the utilities we regulate, we should order rate increases necessary for the collection of the allocated DWR revenue requirement.

4. The rate increases adopted herein are intended to provide for the collection of the DWR revenue requirement that is attributable to SDG&E's retail end use customers, as reflected in the interim DWR charge of 9.02 cents per kWh.

5. Allocating responsibility for the total revenue requirement, including the revenue requirement associated with the DWR revenue requirement implemented by this decision, to customer classes and designing rates to collect the revenue requirement is an exercise of the Commission's ratemaking authority.

6. This decision does not approve the individual components underlying SDG&E's calculations and assumptions with respect to URG and ISO costs for any purpose unrelated to this decision, and does not prejudge our deliberations in A.00-11-038, et al. either with respect to URG revenue requirements of the DWR revenue requirements and allocation thereof.

7. SDG&E should be authorized and directed to establish a balancing account mechanism to ensure that the utility recovers neither more nor less than its imputed utility rate.

8. The § 332.1(b) ceiling for SDG&E's small customers does not prohibit assigning rate increases that result from implementing DWR's revenue requirement to small customers, and the Section 332.1(f) requirement for a frozen rate for large customers does not prohibit assigning rate increases that result from implementing DWR's revenue requirement to large customers.

9. In applying our institutional expertise and experience as well as our understanding of law and policy to make hard choices based on the law, California energy policy and the record before us, it is reasonable to expect that we will reach conclusions similar to those reached in D.01-05-064 on issues having the same or similar policy and factual contexts.

10. While it is generally appropriate to allocate revenue responsibility among customer classes on the basis of cost causation principles, an equal cents per kWh allocation of revenue responsibility is appropriate under the present circumstances, and should therefore be adopted.

11. Consistent with D.01-05-064, we should approve caps on increases for agricultural rates of 20% for TOU rates and 15% for non-TOU rates.

12. Consistent with D.01-05-064, the revenue shortfall from the 130% of baseline exemption should be allocated on an equal cents per kWh basis to all non-exempt customers.

13. Consistent with D.01-05-064, we should adopt a five-tier residential rate structure for SDG&E.

14. SDG&E's proposal to implement the medical baseline exemption in phases should be adopted.

15. SDG&E's proposal to rename the ERCRSA as the ERSA and to record the large customer shortfall in the ERSA should be adopted. Any large customer shortfalls or overcollections should be recorded separately from the small customer shortfall in the ERSA. Any large customer revenues received for URG costs and ancillary services and ISO-related costs should be recorded in the large customer portion of the ERSA.

16. SDG&E should be authorized to transfer any undercollection or overcollection from the memorandum account approved in D.01-05-060 to the large customer portion of the ERSA, and to terminate the memorandum account.

17. The voluntary bill stabilization program for large customers adopted by D.00-12-033 should be terminated.

18. The rate increases that result from implementing the DWR revenue requirement at issue in this decision should not be made applicable to direct access customers at this time.

19. This order should be effective today so that these rate changes may be implemented expeditiously.

20. CARE customers and medical baseline customers should be exempt from the rate increase approved in this order.

21. The revenue shortfall from the exemptions for CARE customers and medical baseline customers should be shared by all other customers on an equal cents per kWh basis.

INTERIM ORDER

IT IS ORDERED that:

1. San Diego Gas & Electric Company (SDG&E) shall establish a California Department of Water Resources (DWR) charge of 9.02 cents per kilowatt-hour (kWh) for energy sold by DWR to SDG&E's retail end use customers, which charge shall be established, implemented, and administered in accordance with Decision (D.) 01-09-013.

2. The electric rates charged by SDG&E shall be increased by 1.46 cents per kWh on a system-average basis to provide for collection of the DWR revenue requirement attributable to SDG&E's customers, as such revenue requirement is reflected in the interim DWR charge of 9.02 cents per kWh established pursuant to Ordering Paragraph 1. Such rates shall be set in accordance with the revenue allocation and rate design determinations set forth in the foregoing discussion, findings, and conclusions.

3. Within seven days of the effective date of this decision, SDG&E shall file an advice letter to implement new rates pursuant to Ordering Paragraph 2. The advice letter shall be effective September 30, 2001. The rates filed in the advice letter shall reflect the rates shown in Appendices B and C of this decision, subject to adjustment for the medical baseline allowance. SDG&E shall include with its advice letter detailed and complete work papers showing the revenue allocation and rate design calculations underlying the new rates for each rate schedule. On the same day that SDG&E files its advice letter, it shall serve electronic copies of the workpapers on Energy Division and all active parties in this phase of the proceeding. Specifically, SDG&E shall file tariffs that effect the following principles:

a. Utility Retained Generation shall be assigned to all customer classes. The system average rate increase is 1.46 cents/kWh, and rates shall be set using annual sales to bundled service customers of 16,828,800 Megawatt-hours, consistent with Exhibits 9 and 26. The revenue increase shall be allocated on an equal cents per kWh basis before revenue shortfalls are taken into account.

b. CARE-eligible customers and non-CARE medical baseline customers are exempt from the rate increase adopted in this Order. The revenue shortfall resulting from exempting these customers shall be allocated to all other customers, but not to residential consumption below 130% of baseline, on an equal cents per kWh basis.

c. The rates attached to this Order do not reflect exemption of non-CARE medical baseline customers and non-residential CARE customers from the rate increases adopted herein. In its compliance advice letter, SDG&E shall reflect the exemption of those customers. SDG&E shall show in the workpapers supporting its compliance advice letter how the revenue allocation and rate design was modified to reflect the exemption of these customers.

d. Increases in agricultural rates shall be capped at 20% for TOU rates and 15% for non-TOU rates. Any revenue shortfall created by capping agricultural rates shall be

allocated to all non-exempt customers, but not to residential consumption below 130% of baseline, on an equal cents per kWh basis.

e. The revenue shortfall from exempting residential consumption below 130% of baseline shall be allocated to all non-exempt customer classes.

f. SDG&E shall reflect a 5 tier-rate residential rate design with incremental block tiers with the following tiers:

3. If SDG&E is unable to implement the medical baseline rate exemption on the effective date of the rate increases, SDG&E shall: (a) implement this rate exemption no later than 30 days following the effective date of the rate increases, (b) apply on December 2001 bills a credit to medical baseline customers for any amount previously billed in excess of applicable rates adopted herein, and (c) notify medical baseline customers no later than October 1, 2001 that they will receive a credit for any amount billed in excess of the applicable rates adopted in this decision.

4. SDG&E is authorized and directed to establish a balancing account mechanism and shall book into the balancing account the difference between the imputed utility rate based on today's decision and the effective utility rate it has billed, multiplied by the number of kWhs billed at that effective utility rate. The balancing account shall become effective concurrent with the effective date of the DWR charge and rate increases ordered herein.

5. SDG&E is authorized to rename the Energy Rate Ceiling Revenue Shortfall Account as the Energy Revenue Shortfall Account (ERSA) and to establish separate recording of revenues and expenses for small customers and large customers in accordance with the foregoing discussion. SDG&E is further authorized to transfer any balance in the memorandum account established pursuant to D.01-05-060 to the large customer portion of the ERSA, and to thereafter terminate the memorandum account.

6. The voluntary bill stabilization program established by D.00-12-033 shall be terminated by SDG&E effective with the effective date of the Advice Letter filing made pursuant to this decision.

7. This proceeding shall remain open.

This order is effective today.

Dated September 20, 2001, at San Francisco, California.

I dissent.

/s/ RICHARD A. BILAS

Commissioner

APPENDIX A

List of Appearances

Applicant: Thomas Brill and Keith W. Melville, Attorneys at Law, for San Diego Gas & Electric Company.

Interested Parties: Goodin, MacBride, Squeri, Ritchie & Day LLP, by Jeanne M. Bennett, for Enron Energy Services, Inc.; Peter Bray, for the New Power Company; Brubaker & Associates, by Maurice Brubaker, for Brubaker & Associates; Christine Costa, Attorney at Law, for Southern California Edison Company; Sam De Frawi, for Navy Rate Intervention; Arter & Hadden, LLP, by Daniel W. Douglass, Attorney at Law, for Alliance for Retail Energy Markets; Norman J. Furuta, Attorney at Law, for Federal Executive Agencies; Adams, Broadwell, Joseph & Cardozo, by Marc D. Joseph, Attorney at Law, for Coalition of California Utility Employees (CUE); Luce, Forward, Hamilton & Scripps, LLP, by John W. Leslie, Attorney at Law, for Shell Energy Services, LP & The Alliance for Retail Energy Markets; Ronald Liebert, Attorney at Law, for California Farm Bureau Federation; Warren Savage, for Santee Chamber of Commerce; Christopher J. Warner, Attorney at Law, for Pacific Gas and Electric Company; James Weil, for Aglet Consumer Alliance; Bernardo R. Garcia, for Utility Workers Union of America, Bernardo Garcia, et al.; Robert Finkelstein, Attorney at Law, for The Utility Reform Network; Richard J. McCann, for M. Cubed; Anderson & Poole, P.C., by Edward G. Poole, Attorney at Law, for CA Independent Petroleum Association, Independent Oil Producers Agency, Western Manufactured Housing Community Association; Jennifer Tachera, Attorney at Law, for the California Energy Commission; and Darwin Farrar, Attorney at Law, for the Office of Ratepayer Advocates.

Intervenor: Michael Shames, Attorney at Law, for Utility Consumers' Action Network.

Protestants: Harold Ball, for Helix Water District & County Water Authority; Sara Steck Myers, Attorney at Law, for the City of San Diego and Frederick M. Ortlieb, Deputy City Attorney, for the City of San Diego.

(END OF APPENDIX A)

APPENDIX B

http://www.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/9807.htm

APPENDIX C

http://www.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/9808.htm

APPENDIX D

Abstract from September 4, 2001 Draft Decision in A.00-11-038, et al.

DWR's updated (as of August 7, 2001) revenue requirement for all three utilities totals $12.6 billion. DWR clarifies that it seeks to collect $12.6 billion from electric retail customers, and $477 million from sales of DWR surplus contract energy. The revenue requirement of $12.6 billion covers the period from January 17, 2001 through December 31, 2002, and reflects an aggregate amount for all three electric utilities.

DWR prepared its revenue requirement forecast in cooperation with its consultant, Navigant Consulting. The financial model used by Navigant has been reviewed by Montague Derose & Associates (financial advisor to DWR), Public Resources Advisory Group (financial advisor to the State Treasurer's Office), and analysts of JPMorgan (investment bankers for the State Treasurer's Office). In addition, PriceWaterhouseCoopers is in the final stages of completing an independent audit of the mathematical accuracy of the financial model. These reviews pertain principally to the financial results of the models. Navigant is responsible for the forecasts of net short energy requirements and the resources used to meet the forecasts that support the revenue requirements.

In its August 7 update, DWR provides the following support for its determination that its revenue requirements are just and reasonable, including:

· DWR used a competitive solicitation method for obtaining power supply bids.

· Power purchases by DWR are at cost and DWR is a governmental agency that receives neither equity return nor any form of economic return for its energy purchases.

· Projected spot market purchases not obtained via contract are estimated based upon a competitive, marginal cost, market clearing price projection.

· DWR's revenue requirement will be adjusted or trued-up over time to reflect only those costs which are actually incurred by DWR for power supply acquisition and administration.

· Actual and projected costs are below prior cost estimates submitted to the Commission in May 2001 and earlier market projections.

Water Code Section 80100, added by AB1X, provides the relevant considerations for DWR when it undertakes to purchase power, following its consultation with the Commission, utilities and public agency utilities:

(a) The intent of the program described in this division is to achieve an overall portfolio of contracts for energy resulting in reliable service at the lowest possible price per kilowatt hour.

(b) The need to have contract supplies to fit each aspect of the overall energy load profile.

(c) The desire to secure as much low-cost power as possible under contract.

(d) The duration and timing of contracts made available from sellers.

(e) The length of time sellers of electricity offer to sell such electricity.

(f) The desire to secure as much firm and nonfirm renewable energy as possible.

The Draft Decision noted that it would be impossible for the Commission to determine whether each element of Water Code Section 80100 has been appropriately considered by DWR. The Legislature has assigned to DWR, and not to the Commission, the responsibility to consider these factors and to conduct and determine reasonableness of costs under Section 451. The Draft Decision presumed that the considerations urged by DWR satisfy at least elements (a), (c), (d) and (e) of Section 80100. It then proceeded to the quantitative process of converting the power purchase program into a set of charges that when applied to volumes will produce revenues to pay for DWR AB1X-authorized costs.

DWR computes its revenue requirement in a two-step process. Step 1 involves the aggregate determination of DWR's gross expenditures. In Step 2, DWR applies a portion of its forecast bond proceeds to its gross expenditures and then determines the remaining amount that it needs to collect from utility customers and submits that amount to the Commission as its AB1X-authorized revenue requirement. The difference between total projected expenditures of $21.446 billion and the total revenue requirement of $12.6 billion results from DWR's determination of its estimate of bond proceeds which offset total expenditures. DWR's estimated revenue requirement is broken down on a quarterly basis by each of the six categories specified in Water Code Section 80134, together with certain additional detail:

· Operating expenses, in which DWR has included power purchase, fuel, transmission, scheduling and demand side management

· Reserves

· Pooled money investment rate on general funds advanced

· Repayment of the General Fund

· Administrative costs

DWR incorporated the following adjustments in its August 7th revenue requirement update:

DWR reports that the cumulative result of these modifications has been to lower the share of the net short energy requirements for SDG&E customers and, to an extent, for Edison customers, and to increase the net short energy requirements for PG&E customers. According to DWR, these changes will result in projected DWR sales of 116,084 GWhs, as compared with 118,920 GWhs in the July 23 submittal, a reduction of 2,836 GWhs. DWR's projected net short for PG&E is now 55,417 GWhs, compared to 48,078 GWhs. DWR's projected net short for Edison is now 42,307 GWhs, compared to 49,083 GWhs. DWR's projected net short for SDG&E is now 18,631 GWhs, compared to 21,769 GWhs. The change in net short energy provided for the customers of the respective utilities reflects a more precise assignment of DWR purchases in the major ISO zones, NP 15 (roughly the area served by PG&E, which is North of Path 15) and SP 15 (roughly the area served by SCE and SDG&E, which is South of Path 15). DWR bases this projection on its new net short energy cost projection changes, and applies a "postage stamp "allocation of the costs to the customers of all three utilities. A postage stamp allocation spreads costs on a uniform cost per kWh basis to all customers.

The non-DWR parties in A.00-11-038, et al. generally claimed that DWR has not provided adequate documentation and explanation of its revenue requirement. Parties assert that they have not been permitted a thorough review and analysis of the methodology and assumptions underlying the revenue requirement, and that further proceedings are needed to establish a reasonable estimate of the revenue requirement.

DWR states that its revenue requirement is based on reasonable forecasts and proposes to work with PG&E and Edison to seek a balance between self-provisioning of ancillary services and their respective net short energy and ancillary service costs. DWR agrees that such cost tradeoffs would be reflected in future adjustments of its revenue requirement. Similarly, DWR agrees that any necessary revisions to its natural gas price forecasts that result in a lower revenue requirement will be incorporated prospectively.

The procedural process for the compilation, review, and implementation of the DWR revenue requirement must conform to the governing requirements of the California Water Code pursuant to AB1X. Water Code Section 80110 provides that DWR "shall be entitled to recover, as a revenue requirement, amounts and at the times necessary to enable it comply with Section 80134, and shall advise the commission as the [DWR] determines to be appropriate." The Draft Decision determined that the procedural process employed in A.00-11-038 provided an opportunity for parties to review and comment upon the DWR revenue requirement. This procedural process was intended to facilitate DWR's receiving its revenue requirement "at the time[] necessary."

The Draft Decision did not address parties' contentions regarding the manner in which DWR fulfills the procedural and substantive obligation to "conduct" any reasonableness review under Section 451, and to make a determination that its revenue requirement is reasonable. It determined that the decision about what process DWR must follow in conducting and determining "any just and reasonable review under Section 451" is not one the Commission should be making, especially as it is a topic of ongoing litigation. It went on to note that the determination of whether DWR's power procurement costs are just and reasonable has been expressly committed to DWR. The Draft Decision noted that the forecasts of certain costs included in DWR's revenue requirement submission are projections of costs which may or may not be incurred; however, as provision is made for subsequent adjustments of the DWR revenue requirements in periodic updates, variances between forecast and actual results can be taken into account in the process of revising DWR charges going forward. The Draft Decision stated that an overcollection in one year will reduce the next year's revenue requirement and the charges needed to recover it, and an intent to continue to cooperate with DWR to facilitate the process of accurately identifying relevant costs and implementing necessary recovery measures as mandated by statute.

AB1X provides that DWR is entitled to recover as a revenue requirement the amounts enumerated in Water Code Section 80134. The Commission's authority under Public Utilities Code Section 451 is made applicable to AB1X costs, except that "any just and reasonable review...shall be conducted and determined by " DWR. As a result, the Draft Decision determined that it is proper for the Commission to implement this revenue requirement, provided it is mathematically correct and reflects only those categories of costs that are authorized in AB1X. The Draft Decision accepted DWR's assurance that the mathematical calculations underlying the DWR revenue requirement are correct, and that the reported costs reflect only those categories authorized by AB1X, with one exception. It found that the costs for load reduction that DWR has included in the revenue requirement are not covered under any of the permissible categories set forth in the statute. Therefore, in general the Draft Decision excluded these costs as reflected in DWR's submission in implementing the DWR revenue requirement.

AB1X requires that DWR include in its revenue requirement "...amounts necessary to pay for power purchased by it..." (Water Code Section 80134(a)(2).) Amounts in the Electric Power Fund are to be spent on the "...cost of electric power...." (Water Code Section 80200(b)(2).) The term "power" is specifically defined as "electric power and energy, including but not limited to, capacity and output or any of them." (Water Code Section 80010(f).) The Draft Decision concluded that this definition does not include other expenditures unrelated to electric power supply, including costs for load reduction.

The Draft Decision, however, retained in the DWR revenue requirements the DSM costs representing the "California 20/20 Rebate Program" for this year. This particular program has already been authorized by the Commission as a utility-tariffed program. Pursuant to Resolution E-3733, dated May 3, 2001, the Commission ordered the three utilities to file tariffs that implement Executive Orders issued by Governor Gray Davis for a one year rate reward rebate program. As explained in that resolution, Governor Davis has issued Executive Orders charging DWR with responsibility for implementing this program. The term of the Executive Orders is due to expire on December 31, 2001. The Draft Decision therefore included costs of the 20/20 Program in the DWR revenue requirement through December 31, 2001 for the actual period that the program is in effect, but did not include 20/20 Program costs beyond the limited term during 2001 that the tariffs and Executive Orders are in effect.

As explained in the Draft Decision, DWR proposed to separately allocate a portion of the total requirement to each of the three utility service territories. The changes between DWR's July 23rd version and August 7th version are set forth below, in GWh and in thousands of dollars:

· Net short volumes (in GWh)

Utility

Revised Net Short (Aug. 7, 2001)

Previous Net Short

(July 3, 2001)

Difference

Percent Change

Edison

42,037

49,083

(7,046)

(14.36%)

PG&E

55,417

48,078

7,338

15.26%

SDG&E

18,631

21,769

(3,138)

(14.42%)

· DWR Revenue Requirement by Utility (in thousands of dollars)

Utility

Aug. 7, 2001 Version

July 23, 2001 Version

Difference

 

2001

2002

2001

2002

2001

2002

Edison

2,087.451

2,516,710

2,171,703

3,631,572

(84,252)

(1,114,862)

PG&E

3,361,933

2,565,851

2,131,312

3,066.374

1,230.621

(500,523)

SDG&E

836,865

1,231,576

827,315

1,243,652

(9,550)

(12,076)

Totals

6,286,249

6,314.137

5,130.330

7,941,598

1,136,819

(1,627,461)

At the workshop held in A.00-11-038, et al., DWR acknowledged that allocation was the Commission's responsibility, and proposed an allocation to facilitate the process. DWR representatives explained the methodology that was used to allocate its revenue requirement among the three utilities. DWR first aggregated its revenue requirement for covering the net short position for all three utilities for the forecast period, and then divided by the total mWh volumes associated with that revenue requirement. DWR thereby derived a uniform cents per mWh cost for DWR-supplied energy. A pro-rata share of the total revenue requirement was then assigned to each of the three utilities by multiplying the derived cost per mWh of DWR-supplied energy by the estimated volumes representing the net short position for each utility.

DWR's inter-utility revenue allocation results in a significant difference on a per-kWh basis. Based on its July 23 filing, the allocations were $108/mWh for PG&E, $118/mWh for Edison, and $95/mWh for SDG&E. As DWR explained in its August 1 data response, the differences in allocation result from applying a disproportionate share of bond proceeds as an offset to costs for SDG&E in comparison to the other utilities. The Draft Decision stated that by allocating a disproportionate share of bond proceeds in this manner, DWR is inconsistent with a cost-of-service allocation approach. DWR's intent was to allocate bond proceeds among the service territories of the three utilities so that DWR's current revenue requirement could be collected from customers within the currently approved rate structures (and the rate structure DWR assumed would be approved for SDG&E). DWR claims that its revenue requirement for the customers of all three utilities can be accommodated within the three cent per kWh rate surcharge applied by the Commission to customers of Edison and PG&E. DWR also projects that its revenue allocation would result in no more than a 2.99 cents per kWh increase for SDG&E customers. The Draft Decision stated that the reference to this DWR projection does not constitute a prejudgment of the any ratemaking or revenue allocation issue pending before the Commission in the instant proceeding.

By allocating a relatively greater share of bond proceeds to SDG&E as compared with the other two utilities, current rate levels for SDG&E customers are correspondingly lower than they would otherwise be. Conversely, by applying more bond proceeds to reduce certain customers' current rate levels, those customer groups would assume responsibility for the repayment of higher debt levels in future years, leading to a correspondingly higher rate level for those customer groups relating to the higher future debt service obligations.

The Draft Decision concluded that the allocation of revenue requirements based upon cost of service provides for an equitable and economically efficient matching of cost responsibility with service rendered. It noted that the allocation methodology applied by DWR is not based on the traditional cost-of-service approach that has long been the standard applied by this Commission in allocating costs to be recovered from utility customers, and that DWR's approach, by contrast, disregards the different geographic regions and customer groups served, and allocates a uniform or "postage-stamp" charge to the customers of each of the utilities. The Draft Decision found the DWR allocation approach is specifically designed to achieve objectives DWR feels are important.

"The primary purpose of the Public Utilities Act . . . is to insure the public adequate service at reasonable rates without discrimination." United States Steel Corp. v. Public Utilities Com., 29 Cal. 3d 603, 610 (1981), quoting Pacific. Tel. & Tel. v. Public Utilities Com. 34 Cal.2d 822, 826 (1950). Although the Commission may justify variances from cost of service in allocating rate responsibility among customers, there must be an adequate rationale for doing so. California Manufacturers Ass'n v. Pub. Utilities Com., 24 Cal.3d 251, 261 (1979). DWR's asserted justifications for departing from traditional cost-based allocation of revenue responsibility - the detrimental consequences of arbitrary or mistaken allocations of spot market purchases or contracted-for power - are uniquely within the power of DWR to avoid. Conversely, the arguments by the other parties, particularly the utilities, articulate a strong rational basis for retaining a cost-based approach for allocating revenue responsibility to the customers of the respective utilities. Toward Utility Rate Normalization v. Public Utilities Com., 22 Cal.3d 529, 543-544 (1978).

The Draft Decision adopted an allocation of the DWR revenue requirement that is based on the cost of service for each of the utilities' service territories, but separately allocated energy procurement on a geographic basis, depending on whether the energy is delivered over facilities in northern California or in southern California. As the geographical dividing point, the Draft Decision used what is commonly known as Transmission Path 15. Energy sources procured north of Path 15 were allocated to PG&E customers. Energy sources procured south of Path 15 were allocated to customers of Edison and SDG&E.

DWR provided summary information in A.00-11-038 et al. that allowed the Commission's Energy Division to calculate the amount of energy costs that were allocated to each utility service area before the DWR combined these costs for its "postage stamp" calculations. These energy costs consist of contract power, residual net short purchases, and ancillary services, and are based on DWR's estimates of the contract volumes and residual net short volumes in each utility service area. The table below shows these original cost allocations, along with the "postage stamp" allocations from DWR's August 7 submittal.

Original DWR Cost-Based Allocation ($000)

 

Contract Power

Residual Net Short

Ancillary Services

Total Power Costs

  
           

PG&E

$5,176,168

5,183,811

450,689

10,810,668

  

SCE

3,249,520

3,078,861

465,105

6,793,486

  

SDG&E

1,279,933

1,174,809

141,065

2,595,807

  
 

$9,705,622

9,437,481

1,056,859

20,199,962

  
           
           
 

DWR "Postage Stamp" Allocation ($000)

Difference

 

Contract Power

Residual Net Short

Ancillary Services

Total Power Costs

  
           

PG&E

$4,766,813

5,127,008

445,672

10,339,493

-471,175

SCE

3,418,778

3,098,794

414,816

6,932,388

138,902

SDG&E

1,520,031

1,211,679

196,371

2,928,080

332,273

 

$9,705,622

9,437,481

1,056,859

20,199,962

  

The Draft Decision intrepreted this table as showing that DWR's postage stamp allocation has lowered the amount of total power costs allocated to PG&E by $471 million, and shifted that revenue responsibility to Edison ($138 million) and SDG&E ($332 million).

To the "cost-based" power costs shown in the above table, the Draft Decision added the other DWR revenue requirement components (e.g., administrative and general expenses, uncollectibles, 2001 "20/20" program costs, and financing costs), to produce the total of all costs DWR expects to incur over the period of January 17, 2001 through December 31, 2002: $22.467 billion. Subtraction of $10.38 billion in net bond proceeds yields the amount that must be collected from ratepayers: $12.086 billion.

The Draft Decision used the same "cost-based" allocator to allocate the bond proceeds between the three utilities. Thus, since PG&E, Edison, and SDG&E were allocated 54%, 33% and 13% of total DWR costs, each utility is assigned the same percentage of bond proceeds.

As a result of the cost-based allocation approach used, the following allocation of DWR revenue requirements among the three utilities resulted. The revenue requirement allocations for the period January 17, 2001 through December 31, 2002 were $6,532,650,000 for PG&E, $4,017,786,000 for Edison, and $1,536,351,000 for SDG&E. The Draft Decision stated that the need for any change in rates for SDG&E customers in order to meet DWR's costs of serving SDG&E customers would be addressed in the instant decision.

To implement this cost-based allocation, the Draft Decision calculated DWR charges of 13.99 cents per kWh for PG&E, 10.03 cents per kWh for Edison, and 9.02 cents per kWh for SDG&E. These rates were calculated for PG&E and Edison by taking the allocated revenue requirement, and subtracting the generation revenues that each utility should have collected and disbursed to DWR from January through May of 2001, to obtain the revenue requirement from June 2001 through December 2002. That revenue requirement is then divided by DWR's forecast sales for the same period, to obtain the specific rate that each utility must use to calculate its payments to DWR, from June 1, 2001 onward. For SDG&E, the Draft Decision performed the same calculation by taking the allocated revenue requirement, and subtracting the generation revenues that SDG&E should have collected and disbursed to DWR from January until September 15, 2001, to obtain the revenue requirement from September 15, 2001 through December 2002. That revenue requirement was then divided by DWR's forecast sales for the same period, to obtain the specific rate that SDG&E must use to calculate its payments to DWR.

(END OF APPENDIX D)

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