The proposed decision of the ALJ in this matter was mailed to the parties in accordance with Pub. Util. Code § 311(d) and Rule 77.1 of the Commission's Rules of Practice and Procedure. Comments were filed on June 9, 2003, and reply comments were filed on June 16, 2003. The alternate proposed decision mailed to the parties on June 5 in accordance with Pub. Util. Code § 311(e) and Rule 77.6 of the Commission's Rules of Practice and Procedure. Comments were filed on June 12, 2003, and reply comments were filed on June 16, 2003. Because the alternate proposed decision differed only in two significant areas from the proposed decision, many parties either commented only on the incremental differences in the alternate proposed decision, or incorporated their PD comments into their APD comments or submitted concurrent comments or reply comments. As such, this section includes a summary of comments received on both mailed decisions (referred to as "the decision") and also specific comments on the alternated proposed decision (referred to as "the alternate proposed decision"). Comments were received from PG&E, SCE, SDG&E, TURN, ORA, UCS, Green Power, CEERT, CalWEA, AReM, IEP, CBEA, Ridgewood, Solargenix, Chateau, Vulcan, and Natural Resources Defense Council (NRDC). Reply Comments were received from PG&E, SCE, SDG&E, TURN, ORA, UCS, Green Power, CEERT, CalWEA, CBEA, Ridgewood, and Vulcan.
PG&E and TURN attempt to relitigate their respective (and opposing) positions on the issue of utility creditworthiness. We decline to revisit this issue. PG&E argues that its return to an investment grade credit rating "would be handicapped by additional contractual obligations." (PG&E Comments, p. 2.) Consistent with the statute, we are not requiring PG&E to procure renewable energy prior to becoming creditworthy, so there are no such contractual obligations.
Numerous parties address the decision's treatment of RECs. Some state support for the decision (e.g., NRDC, PG&E), while others press for future development of a REC trading system (e.g., AReM). While we do not change the decision's fundamental definition of a REC, we do note that the definition is preliminary, and that this is an area that should be examined further and provide some clarification about the need for the benefits of additional renewable procurement, to be paid for by California ratepayers, to accrue to California.
CBEA asks for clarification on two issues relating to RECs: first, that when a utility purchases renewable energy, that the corresponding RECs do not include transfer of fuel subsidies to the utility; and second, that utilities that obtain RECs via the RPS program cannot trade those RECs. (CBEA Comments, p. 4.) We believe that the decision has already resolved these issues, and in a manner consistent with CBEA's request.54 We also provide the clarification requested by Ridgewood regarding credits for destruction of methane.
Green Power takes a more general and theoretical approach, drawing a distinction between what it calls direct and indirect attributes, and arguing that direct attributes should not be bundled with RECs, while indirect attributes may possibly be bundled with RECs. (Green Power Comments, pp. 3-8.) Green Power's approach may ultimately prove useful in sorting out what has proven to be a difficult and contentious issue in this proceeding, but it is currently too abstract to use as a basis for modifying the approach taken in the decision.
Green Power, CBEA, and Ridgewood urge that the Commission promptly take further action to clarify the definition of which attributes are included in the REC that is transferred to the procuring utility. This is a reasonable request, and we will address this issue further in the immediate future.
The majority of comments on the issues of the market price referent and least cost and best fit focused upon the decision's splitting of energy and capacity, and the corresponding treatment of energy and capacity in the bid-ranking process. (See, e.g., Comments of IEP, CEERT, CalWEA, Solargenix, SCE, SDG&E and TURN.) There appears to be some uncertainty and concern regarding how the decision addressed this issue. While we believe the general approach is sound, we will modify it to reflect the differences between the products being offered, and further clarify how it is described. As-available bidders will be allowed to elect not to use the Commission-established capacity values, and may bid an all-in capacity and energy price, while bidders of firm products must bid an all-in capacity and energy price.
TURN also seeks clarification regarding the treatment of location specific costs of the proxy plants, and states that it assumes the intent of the decision "is to allow parties to identify regionally differentiated emissions offset costs for purposes of calculating a statewide average MPR." (TURN Comments, pp. 5-6.) TURN does not quite have it correct. While we are looking at emissions offset costs, our intent was to start with a statewide MPR, and then adjust it as necessary by region, but only for previously established costs. Since the costs have already been established, and there are relatively few regions falling into the category described (i.e., South Coast Air Quality Management District, Bay Area Air Quality Management District), this should be a manageable task.
Comments were also received on the Proposed Decision's treatment of bidders with pre-existing PGC awards. (See, Comments of Chateau, IEP, and TURN.) This is an issue that overlaps between our authority and that of the CEC, as the CEC will be establishing rules for eligibility and distribution of PGC awards. Accordingly, the decision's treatment of this issue may have been somewhat oversimplified, and we modify its holding, consistent with the general concept (as enunciated by IEP) of "no double dipping."
The alternate proposed decision provides numerous clarifications to accurately adopt the joint TURN/SDG&E flexible compliance methodology, as both TURN & SDG&E and numerous other parties pointed out in their Comments were necessary. With the exception of SCE and PG&E, the parties were in support of this more stringent standard. The alternate proposed decision also adopts automatic penalties in lieu of an order to show cause process, based on the support of all parties except the three utilities and in concert with the previous testimony of CEERT and TURN referenced in their Comments.
Most parties appear to support the decision's resolution of the issue of developing standard contract terms and conditions, which allows for more participation and detailed development of those terms and conditions by the parties themselves. (See, e.g. Comments of SDG&E and CEERT.) The principle comments opposing the decision's approach come from parties who were unsuccessful in their attempts to force the adoption of their specific contract or a new standard-offer contract. (See Comments of CalWEA and Vulcan.) We do not change our basic approach, but we will, however, slightly modify our treatment of bilateral contracts, and provide additional guidance for the process of developing standard contract terms and conditions.
As a general matter, the Comments were supportive of the decision, but often asked for more guidance or certainty as to the next steps to be taken, largely as a consequence of the preliminary and highly expedited nature of this proceeding. We have endeavored to provide some additional detail for how this case will proceed.
Generally, most parties supported the two main provisions of the alternate proposed decision that differ from the proposed decision: flexible compliance and upfront penalties. All parties except PG&E and SCE were in favor of the alternate proposed decisions adoption of the TURN/SDG&E flexible compliance methodology. All parties, with the exception the three utilities, were in support of adopting upfront penalties and several parties had provided extensive testimony on this subject.54 NRDC's Comments indicate that it correctly understands that RECs obtained by the utilities for compliance with the RPS program are to be retired. (NRDC's Comments, p. 6.)