10. Need for Expedited Consideration
Rule 77.7(f)(9) of the Commission's Rules of Practice and Procedure provides in relevant part that:
"...the Commission may reduce or waive the period for public comment under this rule...for a decision where the Commission determines, on the motion of the party or on its own motion, that public necessity requires reduction or waiver of the 30-day period for public review and comment. For purposes of this subsection, "public necessity" refers to circumstances in which the public interest in the Commission adopting a decision before expiration of the 30-day review and comment period clearly outweighs the public interest in having the full 30-day period for review and comment. "Public necessity" includes, without limitation, circumstances where failure to adopt a decision before expiration of the 30-day review and comment period...would cause significant harm to public health or welfare. When acting pursuant to this subsection, the Commission will provide such reduced period for public review and comment as is consistent with the public necessity requiring reduction or waiver."
We balance the public interest in quickly addressing these contract allocation matters against the public interest in having a full 30-day comment cycle on the decision draft. We conclude that the former outweighs the latter. A reduced period for review and comment balances the need for parties' input with the need for timely action. Comments were filed on ______________.
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. 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.
27. 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.
28. 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.
29. 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.
30. 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.
31. 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.
32. 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. Nothing in today's decision should preclude the utility from considering DWR as a potential supplier for that gas should it determine that DWR has access to supplies at more favorable terms and quantities than either the utility or contract supplier.
33. The utilities should be expected to manage the DWR contracts in a reasonable manner, subject to Commission review and oversight.
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. The Servicing Arrangements between DWR and the utilities should be modified to reflect the new operational arrangements under contract allocation. 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. The resulting agreements should be incorporated into the Servicing Arrangements for Commission consideration.
10. The prudency 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, should be at issue over the life of the contracts. The forum for the Commission's review of the prudency of DWR contract administration should be the annual procurement proceedings, where the utility procurement process as a whole is reviewed.
11. The public interest in quickly addressing DWR contract allocation issues outweighs having a full 30-day comment period on the decision draft.
12. In order to move forward with procurement planning as expeditiously as possible, this order should be effective today.
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. Whatever level of scrutiny the Commission determines is reasonable for operational and administrative decisions associated with non-DWR contracts in the utility's procurement portfolio shall also apply to the DWR contracts allocated today.
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. SCE, SDG&E and PG&E shall negotiate with DWR to propose appropriate modifications to their respective Servicing Agreements for our consideration in Application (A.) 01-06-044, A.01-06-039 and A.00-11-038 et al., respectively. SCE, SDG&E and PG&E shall file their proposals within 30 days from the effective date of this decision. Comments are due within 15 days after DWR's submittal, and replies are due 10 days thereafter. 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 this purpose.
4. 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.
5. 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.
6. 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. The utilities shall work with DWR to develop specific accounting and reporting procedures consistent with this policy, and shall file these procedures in DWR's revenue requirements proceeding.
procedures consistent with this policy, and file these procedures in DWR's revenue requirements proceeding.
Dated , at San Francisco, California.
TABLE 1 : Adopted DWR Contract Allocation | ||
Long-Term Contract |
Contract Category |
Adopted Allocation |
Allegheny 2 150 MW 6x16 in NP-15 for 2003 |
Must-Take |
PG&E |
Calpine 1 Product 1 |
Must-Take |
PG&E |
Calpine 2 Product 2 |
Must-Take |
PG&E |
Capitol Power |
Must-Take |
PG&E |
Clearwood |
Must-Take |
PG&E |
Constellation - Product 2 400 MW 7x24 May to Oct. '03 |
Must-Take |
PG&E |
Coral |
Must-Take |
PG&E |
El Paso 50 MW 6x16 in NP-15 |
Must-Take |
PG&E |
Intercom |
Must-Take |
PG&E |
Santa Cruz |
Must-Take |
PG&E |
Soledad |
Must-Take |
PG&E |
Allegheny1 Excluding NP-15 deliveries |
Must-Take |
SCE |
Constellation 200 MW 6x16 through Jun. '03 |
Must-Take |
SCE |
Dynegy |
Must-Take |
SCE |
El Paso 50 MW 6x16 in SP-15 |
Must-Take |
SCE |
Morgan Stanley |
Must-Take |
SDG&E |
PGE&T Wind |
Must-Take |
SCE |
Primary Power |
Must-Take |
SDG&E |
Sempra |
Must-Take |
SCE |
Whitewater Cabazon |
Must-Take |
SDG&E |
Whitewater Hill |
Must-Take |
SDG&E |
Williams Prod B1, B2, &B3 |
Must-Take |
SDG&E |
Calpine 1 - Product 2 |
Dispatchable |
PG&E |
Calpine 2 - Product 3 |
Dispatchable |
PG&E |
Calpine 3 |
Dispatchable |
PG&E |
Calpine SJ |
Dispatchable |
PG&E |
Calpeak (3 units) New Site, Panoche, and Vaca-Dixon |
Dispatchable |
PG&E |
GWF |
Dispatchable |
PG&E |
Pacificorp |
Dispatchable |
PG&E |
Wellhead (3 units) Fresno, Gates, and Panoche |
Dispatchable |
PG&E |
Alliance |
Dispatchable |
SCE |
Calpeak (3 units) Border, El Cajon, and Escondido |
Dispatchable |
SDG&E |
Dynegy 1,000 MW On-Peak System Contingent |
Dispatchable |
SCE |
High Desert |
Dispatchable |
SCE |
Sunrise |
Dispatchable |
SDG&E |
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 (Option 1A) |
Spliting of (Option 1B) |
No Spliting of Contract - No Affiliate Contracts (Option 2A) |
No Spliting of Contract - Allow Affiliate (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 - |
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 |
Utility Proposals |
ALJ Alternate |
|||||||||
Straw Man |
Option 1A |
Option 1B |
Option 2A |
Option 2B |
PG&E |
SCE and SDG&E |
||||||
PG&E |
Costs Follow Contract |
$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 |
$70.80 |
$71.50 |
$71.50 |
$71.56 |
$71.56 |
$70.70 |
$72.06 |
$71.13 |
||||
Pro-Rata Cost Allocation |
$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 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
||||
SCE |
Costs Follow Contract |
$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 |
$68.01 |
$67.31 |
$67.33 |
$66.76 |
$70.34 |
n/a |
$67.18 |
$68.07 |
||||
Pro-Rata Cost Allocation |
$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 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
n/a |
$70.05 |
$70.05 |
||||
SDG&E |
Costs Follow Contract |
$784,308 |
$795,978 |
$851,080 |
$853,141 |
$992,644 |
n/a |
$613,500 |
$746,966 |
|||
Costs Follow Contract |
$73.05 |
$72.01 |
$71.76 |
$71.50 |
$66.26 |
n/a |
$71.85 |
$71.79 |
||||
Pro-Rata Cost Allocation |
$752,225 |
$773,625 |
$826,884 |
$831,310 |
$1,034,310 |
n/a |
$596,584 |
$724,596 |
||||
Pro-Rata Cost Allocation |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
$70.05 |
n/a |
$70.05 |
$70.05 |
||||
SCE & SDG&E Combined |
Costs Follow Contract |
61% |
59% |
59% |
59% |
59% |
64% |
55% |
59% |
|||
Pro-Rata Cost Allocation |
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. |
||||||||||||
Assessment of Above Market Costs (Analysis by SCE) (Present Value of Above Market Costs - as Calculated by SCE) |
|||||||||||||||||
|
Above Market Costs "AMC" (as calculated by SCE in their July 24th public document and August 5th filing) |
DWR Support Analysis (July 26th Workshop) |
Utility Proposals |
ALJ Alternate (July 26th) |
||||||||||||||
Straw Man |
Option 1A |
Option 1B |
Option 2A |
Option 2B |
PG&E Proposal (July 19th) |
PG&E Option B 1] (July 30th) |
SCE and SDG&E Proposal (July 19th) |
||||||||||
PG&E |
Present Value of AMC (as a % of Total) |
38% |
43% |
43% |
43% |
43% |
37% |
42% |
46% |
42% |
|||||||
SCE |
Present Value of AMC (as a % of Total) |
40% |
37% |
42% |
33% |
37% |
n/a |
42% |
37% |
40% |
|||||||
SDG&E |
Present Value of AMC (as a % of Total) |
21% |
20% |
15% |
25% |
20% |
n/a |
17% |
17% |
18% |
|||||||
SCE & SDG&E Combined |
Present Value of AMC (as a % of Total) |
62% |
57% |
57% |
57% |
57% |
63% |
58% |
54% |
58% |
|||||||
Percentages may not add to 100% due to rounding. |
|||||||||||||||||
Note: Assessment of Above Market Costs (AMC) as calculated by SCE in their July 24th public document and August 5th filing. |
|||||||||||||||||
