Appendix F

Page 1

Preliminary Data Inputs and

Computations to Determine

Direct Access Cost Responsibility Surcharge

1. Forecast URG cost and kWh: Forecast each year for the following calendar year each utility's revenue requirement and projected kWh output for its URG resources including bilateral and QF contracts. Each utility should provide the Commission with an hour-by-hour projection of the cost and availability of each of their (URG) resources for the entire year.


2. Forecast bundled and DA loads: Forecast each year for the following calendar year hourly loads from each utility's bundled and post July 1, 2001 DA customers. The "DA-in" loads are defined as the total of the bundled and post July 1, 2001 DA customer loads. The "DA-out" loads are defined as only the total bundled customer loads.


3. Use production cost model to project resource mix: Using PROSYM or an equivalent production cost model, forecast the electric resource mix for PG&E, SCE, and SDG&E simultaneously for each hour of the following calendar year. This simulation should incorporate URG resources, DWR's long-term contracts, sales of DWR power off system for any hour at projected sales prices for that hour, and purchases of electricity under short-term (spot) arrangements.

4. Determine annual net DWR costs for two distinct DA scenarios: Using the production cost model developed for (3), develop two scenarios for each year, namely, DA-in scenario and the DA-out scenario. Each scenario should identify the total annual cost (for all three utilities combined) of DWR long-term contract power less revenue generated by off system sales of DWR power ("net DWR costs").¹

APPENDIX F

Page 2

5. Determine the annual cost of spot purchases for the two scenarios: Using the production cost model developed for (3), determine the total annual amount and cost of spot purchases for each utility under each scenario.


6. Develop total portfolio cost by utility for DA-in scenario: For each utility, determine its share of annual net DWR costs identified in (4) for the DA-in scenario by using Commission established allocation factors. To this amount, add the utility specific total annual cost of spot purchases also identified in (5) for the DA-in scenario and the utility-specific URG costs identified in (1). This is the utility specific DA-in total portfolio cost.


7. Develop total portfolio cost by utility for DA-out scenario: For each utility, determine its share of annual net DWR costs identified in (4) for the DA-out scenario by using Commission established allocation factors. To this amount, add the utility specific total annual cost of spot purchases also identified in (5) for the DA-out scenario and the utility-specific URG costs identified in (1). This is the utility specific DA-out total portfolio cost.


8. Determine the Direct Access Cost Responsibility Surcharge by utility: For each utility, take the DA-in total portfolio cost and divide it by the total annual DA-in load. This is the DA-in average total portfolio cost. Then take the utility's DA-out total portfolio cost and divided it by the total annual DA-out load. This is the DA-out average total portfolio cost. Subtract the utility's DA-in average total portfolio cost from its DA-out average total portfolio cost and multiply this difference times its DA-out load. This is the total DA Cost Responsibility amount for the utility for that year. Divide the utility's DA CRS amount by the annual DA loads to produces the DA CRS on a cents/kWh basis.

APPENDIX F

Page 3

9. Determine the separate Direct Access Cost Responsibility Surcharge for the two separate components: (1) DWR Power Charge (to be remitted to DWR) and (2  URG-related charge (to be retained by the utility).

Compare the average cost of URG-related resources in the total portfolio to the Commission-designated market proxy to determine the above-market portion of URG applicable to the DA CRS. Multiply this cents per kWh value by the kWh volumes in the portfolio attributable to URG-related resources, and then divide by total load (both bundled and DA) subject to the ongoing CTC charge to determine the URG component of the DA CRS. Subtract that value from the figure derived in Step 8 to determine the DWR component of the DA CRS. Each of these charge components should then be assessed against all non-exempt DA load, recognizing that different exemptions apply to the two components.

(END OF APPENDIX F)

134003