Settlement Terms

The settlement is Appendix A to this decision. A 51-page Street Lighting Cost of Service Model attached to and filed with the settlement has been omitted from Appendix A for brevity, but is part of the settlement and is in the proceeding record. ⁴

The settlement resolves all of the disputed issues among the settling parties, save one: Whether Assembly Bill 1X (AB1X) precludes increases in total rates for residential usage up to 130% of baseline. The parties have agreed to brief that issue, and we address it in a section to follow. FEA, the sole active, non-settling party, contests only settlement Section 2.

In settlement Section 1, the settling parties agree for the purpose of revenue allocation in this proceeding to use marginal customer costs that are an average of the rental and new customer only methodologies; and marginal demand costs that are developed using the regression method ORA recommended, including 10 years of historical data and five years of forecast data. SDG&E agrees to file marginal energy costs in its next RDW application if it considers them meaningful, and to present its reasoning if it does not.

In settlement Section 2, the settling parties agree to allocate SDG&E's TY2004 COS revenue requirement to customer classes in one of three ways, depending on the system average percentage change (SAPC) in revenue requirement determined in the COS proceeding. If the needed change is a 9% increase or less, the revenue requirement would be allocated on an equal percentage of marginal cost (EPMC) basis with a cap of 3% above the SAPC, and a floor 9% below SAPC. If the needed change in revenue requirement is a 12% or greater increase, revenues would be allocated to the customer classes such that each class received the SAPC. For revenue requirement increases between 9% and 12%, the cap and floor would be phased out in a step-linear fashion. FEA contested only this settlement Section 2, arguing instead for a revenue allocation with no caps or floors and based entirely on EPMC.

Sections 3 and 4 address how to implement an RDW decision if it should become effective on a different date than the COS decision. Section 4 also accepts SDG&E's proposal to change the way its FF&U (franchise fees and uncollectibles) revenue requirement is included in rates. Currently, distribution rates include FF&U associated with these components: distribution, Public Purpose Programs (PPP), Nuclear Decommissioning (ND), Trust Transfer Account (TTA), and Competition Transition Charges (CTC). While the distribution component FF&U is included in the COS proceeding, the others are not. Under settlement Section 4, SDG&E would adjust ND and CTC rates by the FF&U factor adopted in the COS proceeding, and adjust distribution rates to recover its FF&U on the PPP and TTA components.

In Section 5, the parties agree to modify the current requirement that SDG&E serve its preliminary marginal cost study update on interested parties well in advance of filing its RDW application, and instead allow the update in future years to be filed concurrently with the application.

The settling parties address residential rate changes in Section 6. They agree that each fixed rate component should be modified by a single factor derived from the percentage change in the residential class' 2004 COS allocated revenue requirement amount (determined as summarized in Section 2 above). Variable distribution rates would be adjusted in one of two ways. If the Commission decides that AB1X precludes increases in total rates for residential usage up to 130% of baseline, then the first 130% of baseline distribution rates would not be permitted to increase and the revenue shortfall would be made up from within the residential class on a uniform percentage basis from those tiers over 130% of baseline. If, however, the Commission decides that it is permissible under AB1X to do so, then rates for all residential distribution tiers would be changed on a uniform percentage basis.

In Section 7, the settling parties agree that the basic service fees in small commercial rate Schedules A and A-TC should not change. Any change in revenue requirements to the small commercial class should be applied to the distribution energy rates on a uniform percentage basis. To implement SDG&E's COS change, Schedule A energy charges would be adjusted by equal cents per kWh (kilowatt hour). Small commercial's Schedule A seasonal energy rates differential, currently 2.015 cents/kWh, would be reduced by 0.552 cents/kWh, and a rate adder applied for the first 12 months to ensure the same annual revenue recovery as the current seasonal rates.

Settlement Section 8 deals with large commercial and industrial rates. The settling parties agree that the transmission level basic service fee should be increased by 15%. Non-utility generators sought to have their auxiliary loads (also called station loads or station power) at generating plants netted against their generation during the billing month. To address the issue, the settling parties have agreed to establish a new transmission multiple bus basic service fee on Schedule AL-TOU that would be applicable to customers delivering to or being served from one or more than one transmission service level bus on a single premises. For customers selecting that option, SDG&E would subtract generation delivered from loads served before applying retail rates to the net (but not less than zero). The settlement acknowledges the possibility that future actions by the California Independent System Operator or the Federal Energy Regulatory Commission on this topic might later supersede any conflicting provisions in the settlement. Next, the parties agree that the distribution energy rates for Schedules AL-TOU, AL-TOU-DER, AD, AL-TOU-CP, and A6-TOU should be set at zero, with any resulting shortfall to be recovered by a uniform percentage change to the demand charges on those rate schedules. Any decrease to the average rates for Schedule AY-TOU or PA-T-1 should first be applied to the distribution energy rates and any remaining decrease, or any increase, would be applied on a uniform percentage basis to the distribution demand charges. Lastly, Schedule A-TOU distribution energy rates should receive the same change as those on Schedule A. The settling parties agree that Schedule S-I (Interruptible Service), which currently serves only one customer, should be closed to new customers. Distribution standby rates for transmission, primary substation and secondary substation level service should be set at zero, and for primary and secondary level service should be increased by 15%

The settling parties agree in Section 9 that changes in agricultural Schedule PA should be made only to the distribution energy rates.

In settlement Section 10, the parties accept the Street Lighting Cost of Service Model attached to and filed with the settlement. Inputs to the model that would normally change as a result of changes adopted in the current COS proceeding would instead be reflected in a subsequent proceeding.

Settlement Section 11 proposes various language changes in tariff Schedules S, DA, and AL-TOU-CP, and a Rule 1 definition. Only one - tightening the definition of Maximum Demand in Rule 1 - was opposed in initial testimony, and that concern is resolved by adding a clarifying sentence in Rule 1 referring to the new transmission multiple bus basic service fee on Schedule AL-TOU described in settlement Section 8.b.