11. Comments on Proposed Decision

The proposed decision of ALJ Gottstein in this matter was mailed to the parties in accordance with Public Utilities Code §311(d) and Rule 77.1 of the Rules of Practice and Procedure. As set forth in §311(d), the 30-day waiting period for proposed decisions may be shortened upon the stipulation of all parties to the proceeding. By assigned ALJ ruling dated September 9, 2002, parties were asked to address if they would stipulate to shortening the waiting period by one day. We received no opposition; therefore we shorten the waiting period by one day. In addition, pursuant to Rule 87, we shortened the comment period on the proposed decision.

Comments were filed on September 6, 2002 by the utilities, DWR, ORA and Aglet Consumer Alliance. The utilities and DWR filed reply comments on September 12, 2002.

As described in this decision, we clarify our expectations with respect to the utility and DWR filings that will follow, describe where the utilities' recovery of DWR-contract related administrative costs will be considered by the Commission, expand our discussion of gas tolling and reasonableness review issues and make other corrections and clarifications in response to the comments.

Findings of Fact

1. Currently, DWR retains title to the energy from its contracts notwithstanding the fact that energy is traded to and distributed by the utilities under the Servicing Arrangements.

2. The language of AB57 makes it clear that the Legislature contemplated that DWR contract energy would be allocated to the utilities as implied by the April 2 Scoping Memo.

3. Under the operational approach, the utilities are responsible for integrating the scheduling and dispatch of the specific DWR contracts allocated to them with their existing generation assets, contracts and new procurements.

4. The operational approach best reflects the reality that, as of January 1, 2003, DWR is no longer in the business of procuring electric power on behalf of SCE, SDG&E and PG&E's customers, and the utilities resume that responsibility.

5. Retaining a separate DWR resource portfolio, as proposed under the "planning approach," perpetuates a two-tiered procurement system in California that was put in place on a temporary basis, and only under emergency circumstances.

6. Adopting a planning approach for 2003, as a transition to operational contract allocation, would effectively limit the utilities' procurement authority to a one year period. This, in turn, could limit both suppliers' interest in utility solicitations and the utilities' ability to acquire the necessary resources at more favorable prices.

7. The PG&E and joint SCE/SDG&E proposals for contract allocation under the operational allocation approach are identical except for their allocation of the Coral and Sunrise contracts.

8. As discussed in this decision, resolving the contract allocation issues in this proceeding does not require us to select among the competing allocation principles and comparison metrics, to the exclusion of all others.

9. The various allocation principles and associated comparison metrics presented in this proceeding have disadvantages when considered in isolation.

10. The utility proposals appear to have been driven by results, and not by the underlying allocation principles they propose and argue for in their filings: Irrespective of the comparison metric used (energy or capacity allocated, residual net short, any of the cost metrics), the utility consistently comes out ahead with the application of its preferred allocation methodology.

11. The ALJ alternate contract allocation that allocates the Sunrise contract to SDG&E and the Coral contract to PG&E strikes a reasonable balance between the competing proposals of PG&E and SCE/SDG&E and the various principles and comparison metrics considered.

12. The ALJ alternate contract allocation spreads the delivery risk associated with the Sempra, Coral and Sunrise contracts more equitably among all three utilities when compared to the utilities' proposals.

13. The ALJ alternate contract allocation reaches a reasonable outcome in terms of SP-15 and NP-15 zonal allocations by assigning to the southern utilities all contract quantities that designate a SP-15 delivery point, and all to PG&E all contract quantities that designate a NP-15 delivery point.

14. PG&E's preferred allocation and the permutation of the Coral split that PG&E presented in its July 30 comments would allocate a significant portion of the Coral contract quantities designated for NP-15 to the south.

15. The ALJ alternate contract allocation produces a resolution of the contract allocation issues without requiring any utility to manage the contract of its affiliate.

16. Adopting an advance trigger mechanism for contract reallocation, as proposed by the utilities, would insert an unacceptable level of additional uncertainty and complexity into the procurement process going forward.

17. SCE's position that total costs must follow contract allocation is based on the premise that the utility operator must see the total cost of each resource in making economic dispatch decisions.

18. To achieve economic dispatch, the operating utility needs only to see and compare the variable costs of each DWR contract with the other resources in its portfolio.

19. Allocating variable contract costs to each utility based on today's contract allocation is required for economic dispatch.

20. Under the operational allocation approach adopted today, Decisions regarding the sale of surplus power from DWR contracts will be made by the utility on a portfolio basis, as follows: For all the resources in its portfolio (including the allocated DWR contracts), the utility will dispatch all of the must-take quantities plus all of the dispatch quantities up to the market price for each product. The utility then determines whether it needs to purchase additional quantities to meet its residual net short or, if it finds itself in a long position, whether it makes more sense to sell excess power from its portfolio, ramp down utility-owned generation plants, or take some combination of these and other actions based on least-cost economic dispatch principles.

21. DWR's proposed dispatch priority for DWR must-take contracts could work at cross purposes with economic dispatch because it may make more sense to supply incremental power from lower-cost utility generating assets to customers, even if this means that DWR power (as a component of the utility's portfolio) is sold on the market at a "loss."

22. DWR's concerns over ending up with a higher computed average rate should not drive the utility's dispatch decisions.

23. As discussed in this decision, the utilities should not impose a dispatch or curtailment hierarchy among resources based on the timing of their acquisition, or make other artificial distinctions between DWR contracts and other resources within their integrated resource portfolio.

24. Under the operational approach to contract allocation, we need to establish an accounting protocol to credit revenues resulting from sales of excess power to the corresponding (DWR or utility) revenue requirement.

25. The surplus sales accounting protocol that SCE and SDG&E propose would impose an artificial hierarchy to dispatched quantities, based on the timing of resource acquisition, that does not represent the way surplus sales will be generated in an integrated utility portfolio. Similarly, SDG&E's proposed sequential protocol for dispatch and curtailment among must-take contracts is inconsistent with the manner in which resource portfolio decisions will be executed.

26. DWR's proposal for accounting for surplus sales ensures that its must-take contract quantities are priced at retail sales for the purpose of booking revenues into its account, rather than at the much lower rates associated with sales of surplus sales. The utilities' proposals tend to result in the opposite, i.e., place DWR contract quantities more on the margin so that utility sales revenues (at retail rates) are higher than under DWR's proposed protocol or the pro rata approach.

27. Sales revenues should be accounted for based on the composite of resources that the utility dispatches from its portfolio, rather than the timing with which the utilities procured specific resources.

28. As discussed in this decision, sequencing protocols for dispatch or curtailment of must-take resources, such as the ones that SDG&E proposes, are not necessary or appropriate in a procurement environment where the utility dispatches all must-take resources from an integrated utility portfolio. They are also not required to implement the pro rata approach to accounting for surplus sales (or the corollary, retail revenues) adopted in this decision.

29. Retaining legal title of the DWR contracts requires that DWR continue to perform financial reporting responsibilities (e.g., for the DWR revenue requirements proceeding and Trust indenture reporting), and be financially responsible for paying all contract-related bills.

30. As described in this decision, the utilities should perform all of the day-to-day scheduling and dispatch functions for the DWR contracts allocated to their portfolios, just as they will perform these functions for their existing resources and new procurements. This includes performing the billing and collecting "settlement" functions for DWR contracts, and verifying all invoices.

31. Gas tolling provisions are not unusual in contracts that involve combustion turbine technologies. From an operational standpoint, they provide the contract administrator with an opportunity to minimize an important component of variable costs (i.e., fuel) under the contract through regular review of fuel plans and consideration of alternate gas supply options.

32. To have DWR continue in the role of administering the gas tolling provisions of the contracts ignores the fact that it is (1) exiting the electric procurement business in all other respects and (2) not accountable to utility ratepayers for the gas tolling decisions it might make in the future.

33. It makes operational sense to have the utility to conduct the fuel plan review and consider alternate gas supply options for those contracts with tolling arrangements, since this function goes hand in hand with the objective of economic dispatch (to minimize operating costs) for which the utility is now clearly responsible. Making utilities financially responsible for fulfilling gas-purchasing obligations would lead to asymmetry in cost allocation, as discussed in this decision. It would also single out gas costs under tolling agreements for inclusion in utility revenue requirements, when the utilities are not financially responsible for any other aspect of the DWR contracts.

34. Divorcing utility decision-making responsibility from financial responsibility is an invitation to disaster without some form of Commission reasonableness review.

35. The utilities' arguments that the Commission has no authority to engage in reasonableness review of DWR contract administration do not account for the language in AB 57, Section 1, (d) that confers responsibility upon this Commission "to assure that each electrical corporation optimizes the value of its overall supply portfolio, including Department of Water Resources contracts and procurement to Section 454.5 of the Public Utilities Code," and that under subsection (d)(2) of Section 454.5 the Commission may "establish a regulatory process to verify and assure that each contract was administered in accordance with the terms of the contract."

36. Today's decision concerning the operating responsibilities of the utilities with respect to DWR contracts, and which functions we expect to remain with DWR, will have an impact on the division of costs and associated revenue requirements between them. DWR's revenue requirement should decrease as it relinquishes its administration of the contracts and, conversely, the utilities will incur costs commensurate with assuming the administrative functions associated with these contracts.

37. Having the utilities account for the administrative costs associated with DWR contracts in the same manner as the administration costs associated with other procurement contracts (i.e., in each utility's general rate case), will enable the Commission to review them in the context of overall administrative cost levels to determine the need for any rate increases to base rates.

38. The utilities should be expected to manage the DWR contracts in a reasonable manner, subject to Commission review and oversight.

39. Parties have stipulated to a one-day shortening of the 30-day statutory waiting period before the Commission takes action, pursuant to Pub. Util. Code Sec. 311(d).

Conclusions of Law

1. The requirement of ABX1-1 that DWR retain title to DWR contract energy does not serve as a bar to allocation of operational control over DWR contract energy.

2. Current practices under the Servicing Arrangements are nowhere legally mandated, except under those agreements, and are subject to modification at our discretion.

3. An operational allocation of DWR contracts to the utilities is reasonable, consistent with the law, and should be adopted.

4. The ALJ alternate contract allocation, as presented in Table 1, is reasonable and should be adopted.

5. Economic dispatch should be the operating rule for the utility's portfolio of resources, including the DWR contracts we allocate today.

6. A reasonable policy approach is that the allocation of the variable costs of DWR contracts should follow our adopted contract allocation. We will implement this approach in the DWR 2003 revenue requirements proceeding.

7. As discussed in this decision, it is reasonable to prorate revenues from the sale of surplus power between DWR contracts and other resources in the utility's portfolio based on the relative quantities dispatched from those sources.

8. Effective January 1, 2003, it is reasonable that the utilities fully assume the operational and administrative functions for DWR contracts described in today's decision.

9. Requiring that the utilities administer the gas purchases for contracts with gas tolling provisions is as legally permissible as requiring that the utilities administer the other aspect s of the DWR contracts. As discussed in this decision, DWR should reimburse the utilities for their reasonable gas procurement costs.

10. The Commission should review utility DWR contract administration practices for their reasonableness, including dispatch decisions related to these contracts, and enunciate the applicable standard of review in a subsequent decision. The forum for this review should be the annual procurement proceedings, where the utility procurement process as a whole is reviewed.

11. The Servicing Arrangements between DWR and the utilities should be modified to reflect the new operational arrangements under contract allocation. In addition, as discussed in this decision, separate operational agreements between the utilities and DWR should be developed to address the operational functions that go beyond the responsibilities addressed in the existing Servicing Arrangements. The utilities should work with DWR to establish the frequency and format of any information necessary to fulfill DWR's remaining responsibilities, as described in this decision, and provide that information to DWR on a timely basis.

12. Recovery of the utilities' administrative costs associated with DWR contract allocation should be addressed in each utility's general rate case, where we also consider the administrative costs associated with non-DWR contracts.

13. In order to allow the Commission to take action on a timely basis, it is reasonable to shorten the waiting period by one day, pursuant to §311(d) and Rule 87.

14. In order to move forward with procurement planning as expeditiously as possible, this order should be effective today.

INTERIM ORDER

IT IS ORDERED that:

1. The Department of Water Resources (DWR) contracts are allocated to the resource portfolios of Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E), collectively "the utilities," as shown in Table 1.

2. Effective January 1, 2003, the utilities shall fully assume all the operational, dispatch and administrative functions described in this decision for the DWR contracts allocated pursuant to Ordering Paragraph 1. Between now and January 1, 2003, the utilities shall work with DWR to facilitate a smooth transition. The reasonableness of the utilities' administration of the DWR contracts we allocate today, including how they elect to dispatch the contract power quantities relative to other resources in their portfolio, shall be at issue over the life of the contracts. The forum for the Commission's review of the reasonableness of DWR contract administration shall be the annual procurement proceeding, where the utility procurement process as a whole is reviewed. The Commission shall enunciate the standards of review in a subsequent decision.

3. As discussed in this decision, the Servicing Arrangements between DWR and the utilities shall be altered to reflect the new operational arrangements under contract allocation that we adopt today. DWR shall negotiate with SCE and SDG&E appropriate modifications to their respective Servicing Agreements and DWR shall request of us appropriate modifications to the Servicing Order governing PG&E. DWR shall submit its proposed modifications in Application (A.) 01-06-044, A.01-06-039 and A.00-11-038 et al. by October 1, 2002. Comments are due by October 11, 2002 and replies are due by October 16, 2002. The Assigned Commissioners and Administrative Law Judges in this proceeding and the above-referenced proceedings on utility Servicing Arrangements will coordinate closely to ensure that the modifications are consistent with today's order.

4. As discussed in this decision, the utilities and DWR shall jointly file proposed operational agreements and proposed standards for our reasonableness review no later than October 1, 2002 in this proceeding. If there remain specific issues where agreement cannot be reached by the filing date, the utilities and DWR shall highlight those differences in a companion comparison exhibit. Comments are due by October 11, 2002 and replies are due by October 16, 2002.

5. Economic dispatch shall be the operating rule for the utility's portfolio of resources, including the DWR contracts we allocate today. The utilities shall not implement protocols that impose a dispatch or curtailment hierarchy among resources based on the timing of their acquisition, or make other artificial distinctions between DWR contracts and other resources in their resource portfolio.

6. The allocation of the variable costs of DWR contracts shall follow today's adopted contract allocation. In developing its revenue requirements proposal, DWR shall present a contract-by-contract delineation between fixed (or sunk) and variable costs for our consideration in the 2003 DWR revenue requirements proceeding.

7. As discussed in this decision, revenues from the sale of surplus power shall be prorated between DWR contracts and other resources in the utility's portfolio based on the relative quantities dispatched from those sources. This involves the following steps: (1) calculating the amount of surplus sales based on the excess of total utility portfolio resources (including the DWR contracts allocated today) relative to loads, (2) allocating those sales revenues between DWR and the utilities based on the relative quantities dispatched from utility resources and the DWR contracts, and (3) calculating the revenue from retail customers using the difference between dispatched quantities and the surplus sales quantities calculated under (2). The utilities shall work with DWR to develop specific accounting and reporting procedures consistent with this policy, and shall submit these procedures in DWR's 2003 revenue requirements proceeding within 10 days from the effective date of this decision.

8. Each utility shall file updated tables reflecting revised estimates of its residual net short position based on the allocation of DWR contracts we adopt today. The residual net short positions shall be presented separately on an energy and capacity basis for each month in 2003 under low, reference and high case scenarios. As part of these filings, the utilities shall include hourly residual net short duration curves for the low, reference and high case scenarios. In addition, each utility shall file electronic workpapers in Excel format providing estimates of the residual net short position on an hourly basis for each of the modeled scenarios. This compliance filing shall be filed in this proceeding within 10 days from the effective date of this order.

9. The electronic service protocols established in this proceeding by Assigned Commissioner's Ruling Establishing Category and Providing Scoping Memo, dated April 2, 2002, shall be used for all filings and submittals required by this decision.

This order is effective today.

Dated September 19, 2002, at San Francisco, California.

HENRY M. DUQUE

CARL W. WOOD

GEOFFREY F. BROWN

MICHAEL R. PEEVEY

Commissioners

I will file a dissent.

/s/ LORETTA M. LYNCH

President

ATTACHMENT 1

LIST OF ACRONYMS AND ABBREVIATIONS

ATTACHMENT 1

LIST OF ACRONYMS AND ABBREVIATIONS

AB Assembly Bill

ALJ Administrative Law Judge

April 2 Scoping Memo April 2, 2002 Assigned Commissioner Ruling
Establishing Category and Providing Scoping Memo

California Power Authority California Consumer Power and Conservation
Financing Authority

CERS California Energy Resource Scheduling

DWR Department of Water Resources

ISO Independent System Operator

MW megawatts

NP-15 north of Path 15

OIR Order Instituting Rulemaking

ORA Office of Ratepayer Advocates

p. page

PG&E Pacific Gas and Electric Company

PHC prehearing conference

pp. pages

R. Rulemaking

RT Reporter's Transcript

"SC to SC" Scheduling Coordinator to Scheduling Coordinator

SCE Southern California Edison Company

SDG&E San Diego Gas & Electric Company

SP-15 south of Path 15

"the utilities" PG&E, SDG&E and SCE, collectively

(END OF ATTACHMENT 1)

ATTACHMENT 2

Contract Allocation of Must-Take Contracts Under Different Options

Must-Take Contracts

DWR Analysis Support

Utilities' Contract Allocation Proposals (July 19th Filing)

ALJ Alternate (July 26th)

"Straw-Man" Allocation (June 11th, 2002 Letter)

Spliting of Contract - No Affiliate Contracts (Option 1A)

Spliting of Contract - Allow Affiliate Contracts (Option 1B)

No Spliting of Contract - No Affiliate Contracts (Option 2A)

No Spliting of Contract - Allow Affiliate Contracts (Option 2B)

PG&E

SCE

SDG&E

NP-15 Deliveries

Allegheny 2 150 MW 6x16 in NP-15 for 2003

PG&E

PG&E

PG&E

SDGE

SCE

PG&E

PG&E

-

PG&E

Calpine 1 Product 1

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Calpine 2 Product 2

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Capitol Power

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Clearwood

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Constellation - Product 2 400 MW 7x24 May to Oct. '03

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Coral 25% of Base Quantities, all Additional Quantities

PG&E

PG&E

PG&E

PG&E

PG&E

25% PG&E Remainder to SCE/SDG&E2

PG&E

-

PG&E1

El Paso 50 MW 6x16 in NP-15

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Intercom

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Santa Cruz

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Soledad

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

SP-15 Deliveries

Allegheny1 Excluding NP-15 deliveries

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SDGE

SCE

SCE/SDG&E2

SCE

-

SCE

Constellation 200 MW 6x16 through Jun. '03

55% - SCE 45% - SDGE

PG&E

PG&E

PG&E

PG&E

SCE/SDG&E2

SDG&E

SDG&E

SCE *

Coral 75% of Base Quantities

55% - SCE 45% - SDGE

PG&E

PG&E

PG&E

PG&E

25% PG&E Remainder to SCE/SDG&E2

PG&E

-

PG&E1

Dynegy

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SDGE

SCE

SCE/SDG&E2

Firm Product- SCE Unit Contingent Product- SDG&E

Unit Contingent - SDG&E

SCE *

El Paso 50 MW 6x16 in SP-15

55% - SCE 45% - SDGE

PG&E

PG&E

PG&E

PG&E

SCE/SDG&E2

SDG&E

SDG&E

SCE *

Morgan Stanley

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

PGE&T Wind

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SDGE

SDGE

SCE/SDG&E2

SCE

-

SCE

Primary Power

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

Sempra

100% - SCE

100% - SCE

70% - SCE 30% - SDGE

SCE

SDGE

SCE/SDG&E2

SCE

-

SCE

Whitewater Cabazon

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

Whitewater Hill

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

Williams Prod B1, B2, &B3

55% - SCE 45% - SDGE

50% - SCE 50% - SDGE

70% - SCE 30% - SDGE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

Contract Allocation of Dispatchable Contracts Under Different Options

Dispatchable Contracts

DWR Analysis Support

Utilities' Contract Allocation Proposals (July 19th Filing)

ALJ Alternate (July 26th)

"Straw-Man" Allocation (June 11th, 2002 Letter)

Spliting of Contract - No Affiliate Contracts (Option 1A)

Spliting of Contract - Allow Affiliate Contracts (Option 1B)

No Spliting of Contract - No Affiliate Contracts (Option 2A)

No Spliting of Contract - Allow Affiliate Contracts (Option 2B)

PG&E

SCE

SDG&E

NP-15 Deliveries

Calpine 1 - Product 2

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Calpine 2 - Product 3

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Calpine 3

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Calpine SJ

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Calpeak (3 units) New Site, Panoche, and Vaca-Dixon

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

GWF

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Pacificorp

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

Wellhead (3 units) Fresno, Gates, and Panoche

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

PG&E

-

PG&E

SP-15 Deliveries

Alliance

SCE

SCE

SCE

SCE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SCE *

Calpeak (3 units) Border, El Cajon, and Escondido

SDGE

SDGE

SDGE

SDGE

SDGE

SCE/SDG&E2

SDG&E

SDG&E

SDG&E

Dynegy 1,000 MW On-Peak System Contingent

55% - SCE 45% - SDGE

SCE

SCE

SDGE

SCE

SCE/SDG&E2

SDG&E

SDG&E

SCE *

High Desert

SCE

SCE

SDGE

SCE

SDGE

SCE/SDG&E2

SCE

-

SCE

Sunrise

SDGE

SDGE

SCE

SDGE

SCE

SCE/SDG&E2

PG&E

-

SDG&E1

1) On July 26th, ALJ Meg Gottstein requested an alternate allocation scenario reallocating the Sunrise contract to the South and Coral fully to PG&E. SCE and SDG&E were allowed to redistribute the SP-15 contracts in order to produce this additional scenario.

(*) "Italics" indicates a change from SCE/SDG&E July 19th allocation.

2) PG&E July 19th filing expressed no opinion on the allocation breakdown between SCE and SDG&E.

ATTACHMENT 3

COMPARISON OF
NET SHORT CALCULATIONS

ATTACHMENT 3

COMPARISON OF NET SHORT CALCULATIONS

· DWR's calculations represent a 7-year average of net short projections (2003-2009) from PROSYMRun35 including forecast of direct access migration.

· PG&E's calculations represent a 7-year average of net short projections (2003-2009) from PROSYMRun35 excluding forecast of direct access migration.

· SDG&E's primary calculation is based on sales projections used to allocate DWR's 2001-2002 revenue requirement, per D.02-02-052. If a forecasted net short is used, SDG&E recommends adjusting DWR's calculations to correct for resources that SDG&E claims were erroneously excluded from the PROSYMRun35.

· SCE's range is based on current data for the 2001-2002 net short for each utility: (1) the sales projections used to allocate DWR's 2001-2002 revenue requirement, per D.02-02-052; (2) DWR's June 2002 update and (3) DWR's PROSYMRun35 for the year 2003.

	Net Short Calculations
Utility	DWR	PG&E	SDG&E	SCE
PG&E	41%	40%	--	46%-48%
SCE	40%	44%	--	35%-38%
SDG&E	19%	16%	16%*	14%-19%

*14% to 18% if forecasted net short is used.

ATTACHMENT 4

Assessment of Allocation of Capacity, Energy Residual Net Short and Surplus
(Summary of 7-Year Average - 2003 through 2009)
7-Year Average		DWR Support Analysis (July 26th Workshop)					Utility Proposals (July 19th Filings)		ALJ Alternate (July 26th)
		Straw Man	Option 1A	Option 1B	Option 2A	Option 2B	PG&E Proposal (July 19th)	SCE and SDG&E Proposal (July 19th)
PG&E	Allocated Capacity (% of Total Contract Capacity)	39%	43%	43%	43%	43%	37%	47%	43%
	Allocated Energy (% of Total Contract Energy)	40%	42%	42%	42%	43%	38%	44%	41%
	Residual Net Short (% of IOU Load)	7%	6%	6%	6%	6%	10%	4%	7%
	Must-Take Surplus (% of IOU Load)	2%	3%	3%	3%	3%	2%	3%	3%
SCE	Allocated Capacity (% of Total Contract Capacity)	41%	39%	36%	37%	32%	n/a	33%	38%
	Allocated Energy (% of Total Contract Energy)	42%	40%	39%	38%	35%	n/a	39%	42%
	Residual Net Short (% of IOU Load)	7%	8%	9%	8%	11%	n/a	9%	8%
	Must-Take Surplus (% of IOU Load)	4%	4%	4%	3%	3%	n/a	4%	5%
SDG&E	Allocated Capacity (% of Total Contract Capacity)	20%	18%	21%	20%	25%	n/a	19%	19%
	Allocated Energy (% of Total Contract Energy)	18%	18%	19%	20%	22%	n/a	17%	17%
	Residual Net Short (% of IOU Load)	9%	8%	6%	8%	4%	n/a	16%	11%
SCE & SDG&E Combined (Additive of Independent Analysis - Not Optimized)	Allocated Capacity (% of Total Contract Capacity)	61%	57%	57%	57%	57%	63%	53%	57%
	Allocated Energy (% of Total Contract Energy)	60%	58%	58%	58%	57%	62%	56%	59%
	Residual Net Short (% of IOU Load)	7%	8%	8%	8%	10%	n/a	10%	8%
	Must-Take Surplus (% of IOU Load)	4%	3%	3%	3%	4%	n/a	4%	4%
Notes: Allocated energy including dispatchable energy production, residual net short and surplus energy based on estimating utilization of contracts by each utility independently using deterministic hour-by-hour analysis. Percentages may not add to 100% due to rounding.

Assessment of Power Costs (Summary of 7-Year Average - 2003 through 2009)
7-Year Average		DWR Support Analysis (July 26th Workshop)					Utility Proposals (July 19th Filings)		ALJ Alternate (July 26th)
		Straw Man	Option 1A	Option 1B	Option 2A	Option 2B	PG&E Proposal (July 19th)	SCE and SDG&E Proposal (July 19th)
PG&E	Costs Follow Contract (Nominal $000's)	$1,572,479	$1,682,527	$1,682,527	$1,674,375	$1,674,375	$1,462,490	$1,821,548	$1,659,386
	Costs Follow Contract ($/MWh)	$70.80	$71.50	$71.50	$71.56	$71.56	$70.70	$72.06	$71.13
	Pro-Rata Cost Allocation (Nominal $000's)	$1,555,886	$1,648,155	$1,648,155	$1,639,499	$1,639,499	$1,449,101	$1,771,223	$1,634,498
	Pro-Rata Cost Allocation ($/MWh)	$70.05	$70.05	$70.05	$70.05	$70.05	$70.05	$70.05	$70.05
SCE	Costs Follow Contract (Nominal $000's)	$1,713,681	$1,591,963	$1,536,860	$1,542,951	$1,403,449	n/a	$1,635,419	$1,664,115
	Costs Follow Contract ($/MWh)	$68.01	$67.31	$67.33	$66.76	$70.34	n/a	$67.18	$68.07
	Pro-Rata Cost Allocation (Nominal $000's)	$1,762,357	$1,648,688	$1,595,429	$1,599,658	$1,396,658	n/a	$1,702,660	$1,711,373
	Pro-Rata Cost Allocation ($/MWh)	$70.05	$70.05	$70.05	$70.05	$70.05	n/a	$70.05	$70.05
SDG&E	Costs Follow Contract (Nominal $000's)	$784,308	$795,978	$851,080	$853,141	$992,644	n/a	$613,500	$746,966
	Costs Follow Contract ($/MWh)	$73.05	$72.01	$71.76	$71.50	$66.26	n/a	$71.85	$71.79
	Pro-Rata Cost Allocation (Nominal $000's)	$752,225	$773,625	$826,884	$831,310	$1,034,310	n/a	$596,584	$724,596
	Pro-Rata Cost Allocation ($/MWh)	$70.05	$70.05	$70.05	$70.05	$70.05	n/a	$70.05	$70.05
SCE & SDG&E Combined	Costs Follow Contract (as a % of Total)	61%	59%	59%	59%	59%	64%	55%	59%
	Pro-Rata Cost Allocation (as a % of Total)	62%	60%	60%	60%	60%	64%	56%	60%
Note: Energy production and contract costs based on PROSYM Run35. Allocated power costs do not include ancillary service costs, balancing
accounts/charges and offsets from sales surplus energy which are also part of the total revenue requirement.