V. Issues Specific to an IOU Plan
We comment further below on issues specific to each Plan. We agree with UCS's recommendation, however, that conditional approval of these Plans does not constitute endorsement or adoption of proposed policy measures that have not yet been fully vetted or decided. (UCS Comments, page 4.) Rather, we conditionally approve each Plan subject to the amendments required and suggested herein. Each utility, however, remains ultimately responsible for proposing and executing reasonable Plans that achieve the requirement of 20% renewables by 2010, subject to our flexible compliance rules.
A. PG&E
PG&E's Plan states that transmission-related costs will be part of the evaluation, and "projects must bid to one of the selected [transmission] clusters." (Solicitation Protocol, page 18.) At the same time, PG&E states it intends to accept bids from any eligible renewable resource anywhere in California. If the bid must be to one of the clusters, it appears that PG&E intends for the project to incur the transmission cost to get the electricity to that cluster. This may or may not be consistent with PG&E agreeing to take electricity from anywhere in California. PG&E should amend its Plan to make PG&E's expectations clear regarding who pays the transmission cost, or whether that is negotiable, and make clear how out-of-service territory bids will be evaluated.
PG&E's Plan refers to a participant forfeiting its bid deposit if the participant withdraws other than pursuant to a "permitted withdrawal." (Solicitation Protocol, page 7.) It is unclear if "permitted withdrawal" is solely at PG&E's discretion, or if there are conditions which define permitted withdrawal. PG&E should make this term clear.
PG&E's Master PPA for a firm product requires sellers to abide by a certain standard of care. (Solicitation Protocol, Attachment I, Item 3.5, page 17.) If not required elsewhere in the PPA, PG&E should state in Item 3.5 that generating asset owners (GAOs) are subject to the Commissions' GO 167 (unless the GAO is exempted by the terms of GO 167). PG&E's other PPA (e.g., for intermittent sources) should contain this or a similar statement.
PG&E's Master PPA for a firm product requires that sellers perform maintenance only during the three months of March to May of each year. (Solicitation Protocol, Attachment I, Item 3.7(b), page 18.) Sellers are also obligated to a performance requirement of 80% (super-peak), 75% (shoulder) and 55% (night) during March to May, or are subject to performance adjustments (reduced payments). (Id., Item 4.5, page 25.) It does not appear that an allowance is made for scheduled maintenance. PG&E should modify this and its other PPAs to make reasonable accommodation for planned maintenance without performance adjustments, if not now allowed.
B. SCE
SCE was directed (as were PG&E and SDG&E) to "allow bids that have curtailability as an attribute." (D.05-07-039, Ordering Paragraph 9(b).) SCE's 2006 RPS Plan states that its 2005 RFO allowed for curtailability. (Procurement Plan, December 22, 2005, page 14.) SCE clarifies, however, that this means bidders can submit dispatchable bids. (Id.) SCE "defines dispatchable products as those generating facilities that are able to be turned on or off at any time by SCE, at its sole discretion..." (Id., page 14, footnote 7.) Dispatchable by SCE at its sole discretion, however, is not what we meant by accepting bids that have curtailability as an attribute. Rather, dispatchable by SCE may be one form of curtailability. SCE must also entertain bids in which the bidder agrees to curtail itself under certain conditions, not necessarily at SCE's sole discretion. That is, where the bidder "may also propose less-than-full deliverability of product output." (D.05-07-039, page 11.) We made this order to cast a wider net for projects. (Id., page 10.) SCE should amend its Plan to permit this wider net.
SCE's RFP states several references that guide a renewable generator's interconnection and operation. (SCE 2005 RFP, Item 6.10, pages 20-21.) With limited exceptions, all generating asset owners are subject to the Commission's GO 167. Unless otherwise exempt, an RPS generator is subject to GO 167.27 SCE should amend its plan to include reference to GO 167.
SCE's 2005 Pro Forma PPA states the terms under which a Development Fee shall be returned to a seller (e.g., successful initial operation). (PPA, § 304(c), page 19.) SCE states that it will be returned "without interest." In other cases, deposits are returned (or credited toward other fees, deposits or collateral) with interest. For example, SCE returns both the proposal deposit and short list deposit with interest. (SCE 2005 RFP, Item 3.05(c)(ii).) There is no known reason for this inconsistent treatment. SCE should amend its PPA to provide for the return of this and other similar fees, deposits or collateral with interest.
C. SDG&E
SDG&E's Plan does not state its 2006 IPT. Its Plan should be amended to do so.
SDG&E states that it "reserves the right to revise both its RFO and EEI Agreement prior to issuance." (Procurement Plan, page 6.) To the extent such revision is contrary to this or any Commission order, including the Commission's overall direction for the program, that reservation of rights is denied. (§§ 399.14(b) and (d).) The need or usefulness of SDG&E making this statement in its Procurement Plan is unclear. We suggest SDG&E delete this statement when its Plan is amended pursuant to this order.
SDG&E requires RFO Responses to provide "pricing for energy to the point of interconnection with the CAISO grid and to the point of delivery into SDG&E's service area." (Draft RFO, Item 4.13, page 11.) Just as discussed above for PG&E, SDG&E should amend its Plan to make SDG&E's expectations clear regarding who pays the transmission cost, or if that is negotiable, and how out-of-service territory bids will be evaluated.
SDG&E's draft RFO refers to a "Scope of Work" that appears not to be defined. SDG&E should do so, or change the term to "scope of request" consistent with the reference to Section 1.0. (Draft RFO, Item 7, page 18.)
SDG&E's Plan refers to a credit application. (Draft RFO, Item 12, page 27.) It also refers to an Offer Response Form, Additional Narrative Information Sheet, and Consent Form. (Draft RFO, Item 14.0, page 29.) These documents are neither included with SDG&E's document, nor is the website to which parties are referred available. SDG&E should provide copies with its amended Plan.
SDG&E's Plan states that it has not decided whether or not to have a solicitation in 2006, and will make that decision when the 2005 solicitation is complete. We think that is poor judgment. There is clearly a band of uncertainty with regard to demand, supply and transmission issues, making it unclear whether the 20% by 2010 goal can be achieved without constant effort and repeated, vigorous solicitations. This is not the time for any IOU to err on the side of inaction.
For example, a solicitation now might reveal more projects within SDG&E's service area, and without the need for expensive new transmission, than SDG&E currently foresees. The best way to tell this is not with surveys and studies, but an actual test of the market. We understand that a solicitation is not without cost. The cost to SDG&E of such solicitation, however, can be properly managed and controlled by SDG&E. As such, it should not be large. Further, if SDG&E has requested funding from ratepayers, the reasonable costs of the solicitation are already included in SDG&E's rates recoverable from ratepayers (or reasonable amounts will be included in future rates if requested by SDG&E). There is no cost to bidders if no bidder responds. If they do, however, it provides all stakeholders the opportunity to determine whether or not these bids are good for California. On balance, the cost of a solicitation by SDG&E is minor compared to the larger interest of the state reaching its RPS goal of 20% by 2010.
Moreover, there is nothing that prohibits SDG&E from achieving 20% before 2010. We think SDG&E should aggressively pursue this possibility. Further, we think SDG&E's Plan and PPAs should be improved as discussed herein, and this is an opportunity for SDG&E to do so.
We will not order SDG&E to conduct a solicitation, but we will evaluate SDG&E's decision should SDG&E later (beyond the flexible compliance rules) fail to achieve a 1% IPT, or 20% by 2010, and seek a reduction or waiver of a penalty. Absent very good reason to the contrary, we expect to see each IOU conduct a solicitation at least once each year, and-if IOUs assist us craft it-on a continuous basis.28
27 Qualifying Facilities (QFs) are generally exempt. (See GO 167, § 2.8.2.) If an RPS generator is a QF, it may be exempt. RPS generators are not otherwise categorically exempt from GO 167.
28 In comments filed May 15, 2006, SDG&E explains that at the time it filed its 2006 Plan it had not decided whether or not to conduct a solicitation in 2006 because, at that time, it was "unable to predict with any reasonable degree of certainty what the outcome of its 2005 solicitation would be, or what impact the results of the 2005 solicitation would have on the need for a 2006 solicitation." (May 15, 2006 Comments, page 13.) Given the lead time to develop projects, transmission issues and other concerns and constraints, we continue to view SDG&E's early lack of commitment to a 2006 solicitation with concern. Nonetheless, SDG&E now reports "SDG&E has since decided that it will in fact conduct another renewables solicitation in 2006." (Id., page 13.)
