Next Steps

As described in the sections above, there is still significant work to do in the short term in implementing SB 1078, particularly in the areas of the market price referent, standard contract terms and conditions, and confidentiality. Parties provided comments on the best approach to moving forward on these and other issues.

We note that SB 1078 calls for a rulemaking on electric service provider participation in the RPS program (§ 399.12(b)(3)(C)), and a rulemaking on community choice aggregator participation in the RPS program (§ 399.12(b)(2)). To meet these statutory requirements, as well as to provide a more focused forum for the issues that require further development from this phase of this proceeding, we will open a new rulemaking. This new rulemaking, in addition to coordinating with the general procurement rulemaking, will also coordinate as needed with the transmission investigation I.00-11-001, which is addressing certain of the transmission-related aspects of SB 1078, and R.03-03-015, which is addressing a separate statutory provision for increased utility rates of return for utility-owned renewable generation.

There are several pressing matters to be addressed, including the adoption of standard contract terms and conditions. CEERT recommends that workshops on standard contract terms and conditions conclude by July 31, 2003. (CEERT Comments, p. 11.) Ridgewood recommends that the Commission resolve the issues relating to standard contract terms and conditions by December 31, 2003. (Ridgewood Comments, p. 7.) We will adopt CEERT's recommendation, and direct Collaborative Staff to hold workshops on this issue, concluding by July 31, 2003. The assigned ALJ will determine how to place the results of the workshops into the record.

Another issue that should be resolved promptly is further clarification of the definition of the environmental attributes that must be transferred to the utility for it to meet its RPS obligations. The approach taken today, while workable as a stopgap measure, is somewhat ad hoc. We do not intend to make significant changes from the general position we adopt today, but we hope that with some more work, the attributes included in a REC can be defined in a manner that will provide clearer guidance to the participants in the RPS process.

Both utilities and generators have also sought guidance for the consequences of inadequate PGC funds. For example, Ridgewood has asked the Commission to address the situation in which a generator is awarded PGC funds, but those funds subsequently become unavailable. (Ridgewood Comments, p. 8.) Again, we do not intend to make significant changes from the position we adopt today, but more detail regarding the consequences of inadequate or exhausted PGC funds would be helpful. We intend to examine this issue in coordination with the CEC.

PG&E expands on the decision's encouragement of repowering of wind facilities, and calls for similar treatment for all renewable technologies. (PG&E Comments, p. 14.) We will look at this broader issue of repowering renewable facilities on a going-forward basis.

This decision adopts an automatic penalty and a total cap on that penalty on an interim basis, subject to further refinement in the next phase of this proceeding, along with certain reporting requirements. We will hold evidentiary hearings, as necessary, on this subject in the next phase and allow for possible refinement of the penalty and the penalty cap amounts, but we will not allow re-litigation of the threshold question of whether to have automatic penalties. We will also consider the question of whether any penalty funds can be directed into PGC funds to be spent on additional renewable procurement and possible modifications to the reporting requirements.

Last but not least, we will also examine electric service provider and community choice aggregator participation in the RPS program, as required by SB 1078.