2. Background

Track 3 of Phase II of this proceeding was established in March 2007 to separately address NBCs and related issues. Specifically, Track 3 and this decision pertain to the applicability and implementation of new generation related NBCs that were established in D.04-12-048 and D.06-07-029. New generation resources are subject to either the D.04-12-048 NBC or the D.06-07-029 NBC.

By D.04-12-048, the IOUs are allowed to recover the uneconomic or stranded costs related to new generation resources from departing customers. By D.06-07-029, the IOUs are allowed to recover new generation power purchase agreement (PPA) net costs of capacity (total cost less revenues achieved through an energy auction process) from all benefitting customers in the IOUs' service territories. Customers subject to the D.06-07-029 NBC would be allocated resource adequacy (RA) credits for use in satisfying certain Commission RA requirements. The utility will identify new generation PPAs for which it elects to use the D.06-07-029 cost allocation methodology at the time it files an application for approval of the PPAs.

Subsequent to the establishment of Track 3, the majority of implementation issues related to the NBC established by D.06-07-029 have been resolved by D.07-09-044. That decision adopted an uncontested settlement that specified the principles for the D.06-07-029 energy auction and the implementation details for the corresponding allocation of benefits and costs.

A prehearing conference for Track 3 was held on July 12, 2007. Evidentiary hearings were held September 17 through September 21, 2007. Opening Briefs were filed on October 31, 2007. Reply briefs were filed on November 15, 2007, at which time this track of the proceeding was submitted for decision.

Testimony on NBC and related issues was prepared by each of the following parties:

PG&E

SCE

SDG&E

Alliance for Retail Energy Markets (AReM)

California Clean DG Coalition (CCDC)

California Municipal Utilities Association (CMUA)

Cogeneration Association of California (CAC) and Energy Producers and Users Coalition (EPUC), jointly

Hercules Municipal Utility (Hercules)

Merced Irrigation District (Merced ID)

Modesto Irrigation District (Modesto ID)

The Utility Reform Network (TURN)

Western Power Trading Forum (WPTF)

Each of the parties, with the exception of WPTF and CAC, filed opening briefs.¹⁰ In addition, the Division of Ratepayer Advocates (DRA), the City and County of San Francisco (CCSF) and the South San Joaquin Irrigation District (SSJID) each filed opening briefs. Reply briefs were filed by PG&E, SCE, SDG&E, AReM, CCDC, CMUA, EPUC, Merced ID/Modesto ID, TURN and DRA.

A list of acronyms and abbreviations used in this decision is included in Appendix B. A list of certain terms used in this decision is included in Appendix C.

2.1. D.04-12-048

In Rulemaking (R.) 04-04-003, the Commission issued D.04-12-048, which adopted the 2004 long-term procurement plans (LTPPs) of the IOUs. As part of that decision, to ensure a long term, reliable energy supply for California customers and to address the utilities' concern they could end up over procuring resources and incurring the stranded costs associated with these resources given the potential for a significant portion of their load to take service from a different provider, the Commission authorized the IOUs to recover stranded costs associated with new PPAs and utility-owned generation from all customers. Among other things, the Commission found and concluded the following:

In general, we agree that the utilities should be allowed to recover their net stranded costs from all customers, which may require the application of additional cost responsibility surcharges or other non-bypassable surcharges. (Finding of Fact 33.)

Ensuring that utilities be allowed to recover their net stranded costs from all customers meets the Commission's goals of providing "the need for reasonable certainty of rate recovery" (as required under AB 57 and noted in the June 4th ACR) as well as best ensuring that California meets its energy needs. (Conclusion of Law 13.)

Requiring departing customers to assume a fair share of their costs, and thus avoiding cost shifting, is also consistent with the Commission's policy of holding captive ratepayers harmless as required by state law. (See Conclusion of Law 14.)

While D.04-12-048 authorized the IOUs to recover the stranded costs of their electric resource commitments, the decision did not specify the implementation mechanism for the NBC. Consequently, implementation details were deferred to R.06-02-013,¹¹ and subsequently to Track 3.

Additionally, the issue of applicability of non-bypassable charges as it relates to forecasted departing load (e.g., historic municipal and distributed generation (DG) load shedding) was also included in Track 3.¹²

2.2. D.06-07-029

As part of R.06-02-013, the Commission issued D.06-07-029 which adopted a cost allocation mechanism (CAM) that allows the advantages and costs of new generation to be shared by all benefiting customers in an IOU's service territory. The decision designated that the IOUs should procure the new generation through long-term PPAs. By the CAM, the capacity and energy from the PPAs are unbundled and the rights to the capacity are to be allocated among all load serving entities (LSEs) in the IOU's service territory. Such allocated rights to the capacity can be applied toward each LSE's resource adequacy requirements. The LSEs' customers receiving the benefit of this additional capacity would pay only for the net cost of this capacity, determined as a net of the total cost of the contract minus the energy revenues associated with dispatch of the contract. Among other things, the Commission also found and concluded the following:

This mechanism disaggregates the energy and capacity components of the newly acquired generation, so that the only non-bypassable charge levied is for the net capacity costs, and the non-IOU LSEs retain the ability to manage their energy purchases. (Finding of Fact 21.)

It is reasonable, and consistent with law, for the Commission to adopt this limited and transitional cost allocation mechanism to support the development of new generation by having the costs and benefits shared by all customers. (Conclusion of Law 5.)

The IOUs shall make an election at the time they seek contract approval from this Commission whether or not they intend that the cost allocation mechanism adopted by this decision should apply to the contract. The Commission's decision on the IOUs' applications will determine the cost allocation mechanism that will apply. Contracts ineligible for this cost allocation mechanism, or contracts to which the IOUs elect not to apply this cost allocation mechanism at the time seeking Commission approval of the contract, are still subject to the rules of D.04-12-048. (Conclusion of Law 6.)

It is reasonable to defer many of the implementation details of this cost-allocation mechanism to Phase II of this proceeding along with associated ratemaking issues. (Conclusion of Law 10.)

In D.07-09-044, the Commission adopted an unopposed settlement agreement that included the procedures for energy auctions, the products offered by the IOUs in the energy auctions and the allocation of the benefits and net costs of the new generation contracts designated for the energy auction process. The Commission elaborated that additional implementation details would be addressed in Track 2 of the proceeding. Today's decision addresses any remaining CAM implementation issues identified by parties. The issue of applicability consistent with that described above for D.04-12-048 is also addressed in the context of the CAM.

¹⁰ Merced ID and Modesto ID filed joint opening and reply briefs.

¹¹ For instance, see p. 15 and Conclusion of Law 16 of Resolution E-4046.

¹² In a September 10, 2007 electronic-mail response to a September 7, 2007 electronic-mail inquiry issued by the parties during their preparation of the master briefing outline, the assigned Administrative Law Judge (ALJ) for Track 3 indicated that while it might have been appropriate to address this issue as part of forecasting in Track 2, it did not appear that it was clearly stated as an issue in that track, and therefore, it would be addressed in Track 3.