III. Discussion

A. Overview of Utility Plans

1. PG&E

PG&E is seeking power purchase agreements (PPAs) with a delivery term of 10 to 20 years beginning in 2006 or later. Participants may offer delivery terms of 10, 15, or 20 years or a term between 10 and 20 years that is mutually agreeable and approved by the Commission. PG&E has not specified any limitations on the resource types it will entertain. It will accept bids for projects in its service territory, and from projects in SP-15 and ZP-26. It requires delivery of the energy to NP-15.

PG&E will accept bids that propose utility ownership of the project. The types of proposals PG&E will consider are "turnkey" proposals, in which the developer sells the project to PG&E for a pre-determined price at the time the project enters commercial operation, and "buyout" proposals, in which the developer gives PG&E the option to purchase the facility at a pre-determined price after it has been in operation for a certain number of years. PG&E proposes to exercise the option in either the fifth or the tenth year of a power purchase agreement.

2. SCE

SCE is seeking PPAs with delivery terms of 10 to 20 years, with commercial operation commencing between January 1, 2006 and December 31, 2008. Non-standard term length contracts are permitted if agreed to by the parties, subject to Commission approval. SCE is not limiting the types of resources that bid, nor is it proposing limits on the location of the projects. SCE specifies delivery of energy to SP-15.

SCE has elected to allow affiliates to participate in its 2005 RPS solicitation. However, SCE does not intend to allow buyout or turnkey proposals that would lead to SCE's ownership of the project.

3. SDG&E

SDG&E proposes both the most detailed and the most narrow solicitation of the three utilities. SDG&E is dividing its 2005 solicitation into two RFOs. One will solicit bids from developers to install distributed renewable technologies, specified to be either solar photovoltaics (solar PV) or small stand-alone wind generation units. The second RFO will solicit bids from renewable projects located in the western portion of SDG&E's service territory for all other renewable resources. SDG&E intends to issue both RFOs at the same time and evaluate them concurrently.

SDG&E seeks offers from developers for solar PV installations on selected SDG&E facilities that would sell the output from the solar PV to SDG&E in a conventional PPA, with an option for a buyout at the end of the term of the PPA. SDG&E would also allow bids for small wind turbines to be installed as stand-alone units at designated SDG&E facilities, either as turnkey projects or with the same PPA/buyout structure as the solar PV proposals.³

Since this solicitation specifies SDG&E facilities as the location for the solar PV or wind installations, the developers would be operating the projects on SDG&E facilities and would require access for installation and maintenance purposes. SDG&E anticipates that a lease or similar property interest would be part of any contract. It therefore also seeks a limited exemption from the requirements of Pub. Util. Code § 851⁴ to allow for the installation and operation of these systems on the specified SDG&E facilities without the need to file an application for approval to enter into the lease or other arrangement.

The more general RFO solicits deliveries starting in 2006, 2007 or 2008. SDG&E does not express a preference for a particular product or technology type in the second RFO. SDG&E does, however, limit the RFO to projects that can be sited within SDG&E's service area, and in particular west of the area of the Crestwood, Boulevard and Cameron substations.

SDG&E requires that PPA and PPA/buyout contracts have a term of at least ten years, though SDG&E will consider offers with other contract durations.

B. Fundamental issues

Three issues that have been addressed by a number of parties cut across the categories of long-term and short-term planning. Because the resolution of these issues will improve the 2005 solicitation process, we address them here.

1. Resource "Stacks"

PG&E and SDG&E provide resource "stacks," ranking potential renewable resources according to the utilities' present estimates of their needs and preferences. In D.04-12-048, we noted that many parties found the resource stack presented by SDG&E in its 2004 long term procurement plan to be helpful in understanding the utility's planning perspectives. Some parties now express concern, however, that there is some tension between the clarity of the stack in conveying the utility's current planning preferences and the requirement that each bid be evaluated on its merits, using least-cost best-fit criteria we prescribed in D.04-07-029.⁵

Resource stacks, or any other planning projection, cannot be used to pre-screen bids or to discourage bids from improbable (but potentially valuable) sources. Rather, they must be understood as illustrating the utility's present thoughts about potential resource allocation and availability (elements of "fit"), not as predicting its future actions on specific bids. In order to ensure that the preferences identified in the resource stacks will not act as hidden weighting factors in the evaluation of bids, the utilities should make their evaluation process transparent to their Procurement Review Groups and the Commission. PG&E has also taken the useful step, which we commend but do not require, of including its weighting of evaluation criteria in its solicitation materials.

2. Transmission Constraints, Delivery Points, and Curtailability

A central theme in the utilities' plans and the parties' comments is the importance of transmission, or transmission constraints, in RPS planning and procurement. SDG&E flatly states that, without a new 500 kV transmission line coming into its territory from the east, it will be unable to attain its 20% renewables commitment by 2010. For 2005, SDG&E proposes that it will not accept proposals from areas even within its service territory that are transmission constrained. PG&E prioritizes all resources in its service territory higher than almost any outside it, and proposes changes to the RPS rules for in-state delivery as a way to avoid transmission constraints. SCE notes that it is working on transmission issues, having filed applications for a Certificate of Public Convenience and Necessity for new transmission from the Tehachapi area
(A.04-12-007 and A.04-12-008) and having sought a declaratory ruling from the Federal Energy Regulatory Commission on financing of transmission for areas with large renewable resource potential. (FERC Docket EL 05-80-000.)

Because of the complexities of transmission development, we cannot solve all problems related to transmission in this proceeding. We can, however, take steps to ameliorate some of the impacts of transmission constraints on RPS procurement by providing for some flexibility in the utilities' requirements. By separate order in Investigation (I.) 00-11-001, we address the application of the Methodology for Development and Consideration of Transmission Costs in Initial Renewable Portfolio Standard Procurement (Transmission Cost Methodology), developed in D.04-06-013 for the 2004 RPS, to the 2005 RPS solicitation. In this decision, we address two other proactive steps that will help reduce the impact of transmission issues on RPS procurement: flexibility of delivery points and curtailability of delivery.

TURN and UCS, supported by ORA, urge that the utilities be required to allow bids with delivery points anywhere in California. The procuring utility would get credit for the full amount of the electricity delivered for RPS compliance purposes.⁶ If the energy contracted for could not be delivered to its load center, the procuring utility could swap, trade, or remarket the electricity.

PG&E agrees that this delivery flexibility would be a useful tool.⁷ SCE and SDG&E object to the TURN/UCS proposal, citing the costs and uncertainty of procuring energy that would require either transporting the acquired power to the utility's load center or remarketing it.

The risks noted by SCE and SDG&E can be obviated, as TURN points out, by adjusting bids that specify delivery at points outside the utility's service territory to account for any increased costs associated with remarketing, swaps, potential congestion, and other factors arising from the out-of-area delivery. If this adjustment is made expressly and transparently for review by the utility's Procurement Review Group and the Commission, it should provide an adequate basis for comparison with bids proposing in-area delivery, including bids that propose in-area delivery after initial interconnection outside the utility's service territory.⁸

In order to attain the 20% goal by 2010 and maintain or increase it thereafter, the utilities must engage in creative and aggressive procurement.⁹ Merely waiting for projects to be developed that will deliver directly and only to the utilities' preferred delivery points, using transmission facilities that do not yet exist, is not likely to accomplish the goals of the RPS program, as SDG&E's frank assessment of its situation highlights. Widening the scope of delivery options is one step that can be taken without any additional investment in physical infrastructure and without statutory or regulatory changes. We will require the utilities to change their RFOs to allow bids from out-of-territory generators that have delivery at points outside their service territories, but in the California Independent System Operator (CAISO) control area. We also grant SCE's request that it may require in-territory generators to deliver to in-territory points.¹⁰

Another approach to reducing the impact of transmission issues on RPS procurement is the development of projects that face some transmission constraints, but that can nevertheless bid in RPS solicitations by proposing curtailability as part of their bids. As TURN notes, some transmission bottlenecks are only congested during a relatively small number of hours per year. In response to this issue, in D.04-06-013 we instructed the utilities to "assess RPS bids that propose curtailability as an attribute of their projects on a case-by-case basis." Mimeo., p. 22. We reiterate that bids proposing curtailability are acceptable in the RPS process, and must be evaluated with all other bids. The utilities must evaluate bids for projects with curtailability as an attribute through the use of System Impact Studies and Facilities Studies for those projects for which such studies have been performed, and use their best judgment in evaluating projects having only conceptual studies. Id. at 22-23.

By casting a wider net for projects that may not have their ideal delivery points or deliverability attributes, the utilities may be able to bolster their RPS procurement starting this year, rather than waiting for transmission improvements that may not come to fruition for years. To this end, we modify paragraph 6 of the section, "Consideration of Network Transmission Costs in Ranking Bids" of the Transmission Cost Methodology¹¹ to expand the allowable attributes of bids (additions underlined):

6. In their bids, renewable bidders may describe expected network benefits, the extent to which the project would be able to produce Volt Amperes Reactive, and other transmission-related factors, and may propose delivery of product output to any point in the CAISO control area; they may also propose less-than-full deliverability of product output. Each subject utility shall evaluate proposed network benefits and also curtailability proposals that have been examined through System Impact Studies or Feasibility Studies. Each subject utility shall evaluate proposals for delivery outside its service area after making appropriate adjustments for the costs associated with such delivery. It shall utilize consistent, logical approaches to assessing these potential benefits and costs, and its evaluation process should be transparent to the utility's Procurement Review Group and to the Commission.

We emphasize that our directions here are not intended to interfere with or change the utilities' obligation to perform a least-cost best-fit analysis for all bids, but rather to provide a way to increase the number of bids that would be subject to that analysis.¹²

3. Compliance

In D.03-06-071, we set out the requirements for RPS compliance, including flexible rules for compliance, as required by § 399.14(a)(2)(C). PG&E asks us to revisit the compliance standards. PG&E requests that we declare that:

1. When, in response to a shortfall greater than 25% of APT for a particular year, a utility demonstrates that contracts already executed will provide future deliveries sufficient to satisfy the current year's deficits, the future deliveries should be "earmarked" to apply first to the year of the deficit, rather than to the year of the delivery.

2. Signed contracts count toward the utility's demonstration of compliance with its APT for the year in which the solicitation resulting in the contract was begun.

3. The goal that 20% of the utility's retail sales of energy in 2010 be from renewable sources does not require that 20% of energy actually delivered to utilities in 2010 must be from eligible renewable resources.

We agree with CEERT and ORA that the utilities' focus should now be on seeking and signing the best possible contracts for renewable energy, rather than on seeking adjustment to compliance standards. However, since PG&E raised these issues, we will address them to the extent necessary at this time.

As many commenters¹³ point out, the RPS program is intended to provide energy, not contracts. In D.03-06-071, we made clear that "procuring" energy for the RPS program means "actual generation output being available, rather than just the execution of a contract." (Mimeo., n36, p. 67.) We see no reason to change our conclusion, which is grounded in the language of § 399.14(g), that compliance with RPS goals is measured in delivered energy. We evaluate PG&E's proposal in that light.

The RPS flexible compliance rules include a provision that allows the utilities to use contracts as part of their demonstration for RPS compliance when faced with under procurement. Under the compliance regime we adopted in D.03-06-071, a utility acquiring at least 75% but less than 100% of its annual procurement target (APT) may carry over the deficit without further explanation. If the utility procures less than 75% of its APT, it may provide a demonstration that "[c]ontracts already executed will provide future deliveries sufficient to satisfy current year deficits..." (Mimeo., p. 76.)

PG&E proposes that, when the utility invokes the reason that contracts already executed will provide future deliveries sufficient to satisfy current year deficits, the deliveries in later years from contracts so identified should be "earmarked," and applied first to the shortfall in the year of the contract. This is in contrast to the application of the 25% shortfall without explanation, where we require that later deliveries be applied first to the year of delivery, and only after the current year's APT is attained may deliveries be applied to make up earlier shortfalls. As we explained in D.03-06-071, this requirement prevents continual roll-over of the 25% shortfall, and thus prevents the utility from falling so far behind in its RPS procurement that it may jeopardize attainment of the program's goals. (Id., p. 49.)

PG&E's proposal is a reasonable elaboration of the flexible compliance rules. The existence of the already executed contract provides reasonable assurance that the anticipated future deliveries will occur and will be available to make up the prior years' shortfall. As UCS notes, § 399.14(a)(2)(C) allows "inadequate procurement in one year" to be applied "to no more than the following three years." This limit applies to shortfalls below 75%, with the enumerated reasons, as well as to the 25% shortfalls that do not require explanation. We reiterate that aggressive procurement efforts can alleviate some of the utilities' concerns about application of the flexible compliance rules.

PG&E also notes that, since the 2005 RPS solicitation is not scheduled to begin until late in 2005, it is unlikely that contracts will be signed during 2005. This observation should not be used to justify a general rule that contracts should be counted for the year of the solicitation rather than the year in which they are signed, since such a rule would create an incentive to draw out contract negotiations. Rather, it only provides the basis, as TURN and UCS urge, to allow contracts signed by June 30, 2006 to be counted as "contracts already executed" for 2005. This adjustment recognizes the realities of the timing of the RPS procurement process for 2005. We are initiating a schedule for 2006 procurement that should allow procurement on a calendar year basis, and render such adjustments unnecessary in the future.

PG&E's request that we revisit the 2010 goal is premature. When the Commission, by adopting the Energy Action Plan (May 8, 2003), accelerated the 20% goal to 2010, it envisioned that 20% of energy actually delivered in 2010 would be from eligible renewable resources. In D.04-04-026, we began implementing the 2010 goal by adjusting the utilities' 2004 APTs to that timeframe.¹⁴ The RPS program is in its early stages. This year is the first year in which all utilities are undertaking RPS solicitations. It is simply too early to decide whether we need to make special adjustments or allowances in relation to the 2010 targets. We consider 2010 the date by which 20% of energy sold to retail end-users is to be delivered from eligible renewable resources; the utilities should, too.¹⁵

C. Common Issues in 2005 Plans and RFOs

Parties have raised several issues that are common to more than one utility plan and RFO. In considering the most significant of these issues, we seek to broaden and enhance the quality of RPS bids and improve the contracting process. We start from the presumption that utilities are able to use their business judgment in running their solicitations unless their plans threaten to impair the effectiveness of the RPS program.

1. Proposals that Include Utility Ownership

PG&E has proposed that it will accept turnkey or buyout proposals as well as PPAs. SDG&E's solicitation requires bidders to provide both turnkey or buyout options with PPAs. SCE does not intend to solicit any projects with utility ownership features, but will consider PPA proposals from affiliates.

IEP and CalWEA object to the PG&E and SDG&E proposals, fearing that, without more guidance on criteria to use in least-cost best-fit ranking of such projects, utilities will favor bids that result in their eventual ownership of the renewable resource. Because the RPS statute allows utilities to own generation that can be used to satisfy RPS requirements,¹⁶ bids with some form of utility ownership must be considered, if relevant, in the bid evaluation process.

The potential problems identified by IEP and CalWEA are inherent in the hybrid market we endorsed in D.04-12-048. For that reason, we adopted a variety of safeguards and procedures in that decision; these apply to RPS procurement as well. In D.04-12-048, as PG&E and SCE note, we required that utilities use independent evaluators if affiliated entities bid in a procurement solicitation or if the utility seeks turnkey proposals.¹⁷ PG&E also proposes to extend the use of an independent evaluator to evaluate buyout project bids for its RPS solicitation. We believe this is an appropriate safeguard and adopt it.

In D.04-12-048 we also set out "All-Source and RPS Solicitation Bidding Guidelines," which apply to turnkey and buyout projects. (Mimeo., pp. 140-41). These guidelines apply by their terms to RPS solicitations. All bids, regardless of ownership form, must be reviewed using the least-cost best-fit criteria, and one short-list must emerge from ranking all bids against one another. Because 2005 solicitations will be the first application of these guidelines in an RPS solicitation, the utilities and their Procurement Review Groups may need to make special efforts to ensure that bids proposing turnkey or buyout projects are properly evaluated. In order to minimize problems that may delay the evaluation process, we will require the utilities to submit their methodology for evaluating turnkey or buyout bids to their Procurement Review Groups and Energy Division staff for review and approval prior to developing their short-lists.

2. Bid Deposits

Both PG&E and SCE propose that bidders be required to post deposits. PG&E's deposit requirement is $3.00/kW for all short-listed bids. SCE adopts a deposit system similar to the one PG&E used in 2004: $25,000 or $5.00/kW for all bidders. CalWEA and Solargenix argue that these deposit requirements will both deter bidders from bidding at all and skew negotiations with suppliers who do bid. SCE counters that bid deposits should deter bidders who are not serious or cannot put forward a viable proposal. PG&E notes that its deposit requirements are not coercive, since it refunded cash deposits of all losing bidders, with interest, in its 2004 solicitation.¹⁸

There is a wide range among the three utilities on bid deposits, from SDG&E's absence of any requirement to SCE's requirement of a significant deposit for all bidders. Although a bid deposit requirement could deter qualified bidders or harm negotiations between utilities and short-listed bidders, as CalWEA and Solargenix argue, it could also improve the quality of bids submitted, as SCE argues. At this time, we do not have a way to choose between these hypotheses. We therefore will not interfere with the utilities' judgment about the need, or lack of need, for bid deposits for 2005. If evidence of problems with bid deposits emerges from the 2005 solicitations, we urge parties to bring it to our attention so that we may reevaluate this issue for 2006 solicitations.

3. CAISO Market Redesign Contingencies

PG&E reports that, as a result of difficulties in its 2004 negotiations, it has modified its provisions on delivery contingencies related to CAISO market redesign. For 2005, PG&E will allow delivery at the generator's busbar if CAISO changes the current zonal market to a nodal market. SCE intends to keep its requirement of delivery to its service territory, even if a market redesign occurs. CalWEA supports PG&E's flexibility and urges that we require it of all utilities. Although we approve of PG&E's response to its experience in 2004, and think that SCE and SDG&E should consider it carefully, we will not require the other utilities to follow PG&E's lead this year. We do require SCE to allow out-of-territory generators to deliver to any point in the CAISO control area, consistent with our requirement for basic delivery terms.

4. Miscellaneous Contracting Issues

CalWEA is critical of the use of a PPA based on the Edison Electric Institute (EEI) model. The standard terms and conditions for RPS contracts that we adopted in D.04-06-014 were developed with reference to the EEI model, including the adoption or modification of many specific sections of the EEI model. These standard terms and conditions were the result of extensive work by many parties to this proceeding. We will not prohibit the use of the EEI model itself as a base document for PPAs when it has been used for the development of our required standard terms and conditions. Any specific problems that can be attributed to use of the EEI model should be brought to the attention of the parties and Energy Division staff for consideration in any subsequent relevant workshops.

Solargenix also objects to the imposition of credit requirements for developers, especially without a reciprocal obligation for the utility to provide collateral. SCE asserts that protecting ratepayers against the risk of nonperformance leads to the need for credit requirements. PG&E notes that now PG&E has no need to post collateral, but it gives a preference to bidders posting collateral. We consider this dispute largely hypothetical at this time and will not require the utilities to make any changes.

Solargenix suggests that we require the utilities to offer a contract length of 30 years. Nothing in the RFOs prevents a bidder from proposing such a term, and nothing prevents the utility from agreeing to it. As PG&E points out, any non-standard contract length (whether longer or shorter) can be agreed to, subject to Commission approval. We therefore see no need to require the utilities to offer something that bidders themselves may initiate.

CalWEA notes that none of the utilities provides a firm deadline by which it will notify losing bidders that they are out of consideration. CalWEA asserts that this unnecessarily ties up potential projects that have submitted binding bids in a particular solicitation. SCE agrees with the suggestion that it establish a firm bid-rejection date and proposes seven days after the notification of short-listed bidders. PG&E, on the other hand, responds that, based on its experience with its 2004 solicitation, some highly-ranked projects can drop out of the solicitation, allowing other projects to be considered. If forced to reject bids by a firm deadline, PG&E suggests, it might prematurely close off bids capable of being improved and short-listed. CalWEA has identified a potential area of unfairness to bidders, but its proposed remedy is too drastic. We will leave notification of rejected bidders to the business practices of the utilities, and expect those practices to be consistent with the general requirements of transparency in RPS procurement.

D. Individual utility plans

1. PG&E

PG&E's proposed solicitation for 2005 is fairly straightforward. PG&E will accept a wide range of bids for resources and products, with a range of ownership options. The focus of parties' criticism of PG&E's plan is its overly passive approach to seeking contracts with repowered wind facilities. As PG&E itself points out, it already has contracts with wind facilities in the Altamont Pass Wind Resources Area. Repowering wind facilities at Altamont Pass is feasible, will increase the energy that can be delivered to PG&E from that area, and is likely to be cost-effective. But, as CEERT notes, PG&E has not presented any plan for pursuing repowering options in 2005.¹⁹ Indeed, repowered wind at Altamont Pass is only number three in PG&E's resource stack. While each bid must be evaluated according to least-cost best-fit criteria, we would expect PG&E to devote a reasonable amount of effort to acquiring repowered wind resources.²⁰

It is possible that the use of an independent evaluator for turnkey and buyout bids will delay the completion of the solicitation. We encourage PG&E to prepare early for the use of the independent evaluator and to provide timely information to its Procurement Review Group about issues related to the independent evaluator. We authorize PG&E to book the cost of the independent evaluator in its Long Term Procurement Memorandum Account. We also encourage PG&E to document any issues or problems that may arise from the use of the independent evaluator, so that we may benefit from this experience in reviewing future solicitations.

2. SCE

SCE's proposed solicitation for 2005 is open to a range of resources and products. It is the only solicitation that will be open to affiliates. It is possible that the use of an independent evaluator for affiliate bids may delay the completion of the solicitation. We encourage SCE to prepare early for the use of the independent evaluator and to provide timely information to its Procurement Review Group about issues related to the independent evaluator. We also encourage SCE to document any issues or problems that may arise from the use of the independent evaluator, so that we may benefit from this experience in reviewing future solicitations.

TURN asserts that SCE's short-term planning is based in part on an improper banking of credit for energy acquired from Calpine's Geysers geothermal facility. TURN urges that SCE be required to recalculate its forward banking after the Energy Commission has determined the amount of incremental renewable procurement associated with SCE's Geyers contract. SCE responds that this dispute has already been resolved in its favor in Resolution E-3809 (January 30, 2003). In that resolution, we allowed the contracts TURN identifies to be counted as transitional procurement from a renewable resource that SCE could count toward "any obligation it may have pursuant to D.02-08-071 and D.02-10-062, or other applicable law, to procure an additional 1% of its annual electricity sales from renewable resources." (Mimeo., p. 24.)

SCE misinterprets prior Commission actions when it asserts that they create an exemption from statutory requirements for the RPS program. Resolution E-3809, on which SCE relies, approved the Geysers contracts and, as SCE notes, allowed the energy procured to be applied to satisfy SCE's obligations under "other applicable law." We agree with SCE that this category includes the RPS program, since SB 1078, creating the RPS program, was effective January 1, 2003.

SCE errs, however, in reading the statement in Resolution E-3809 to absolve it of its responsibilities for complying with the requirements of the "other applicable law." Those requirements, with respect to geothermal output for RPS purposes, are set out in § 399.12(a)(2).²¹ SCE may have been able to comply with the mandates of D.02-08-071 without receiving certification from the Energy Commission that the geothermal production was incremental under § 399.12(a)(2) (see D.03-06-076, mimeo., p. 36), but it cannot comply with the mandates of the RPS statute without such certification.²²

Neither Commission resolutions nor actions or inactions by Commission staff can serve to alter this statutory mandate. We recently reaffirmed this principle in our disapproval of certain residential rate increases instituted by SDG&E that were inconsistent with statutory provisions, although SDG&E's advice letters had been approved. See D.04-02-057, mimeo., p. 95; D.04-04-020, mimeo., p. 15.

In upholding the statutory allocation of certain responsibilities to the Energy Commission, we are in no way prejudging the outcome of the Energy Commission's certification process. We are simply stating that until SCE has presented appropriate certification from the Energy Commission of incremental output for the Geysers contracts, it may not allocate this energy to its Incremental Procurement Target (IPT).

3. SDG&E

SDG&E's proposed bifurcated solicitation has drawn opposition from TURN and UCS. TURN argues that the solar PV/small wind solicitation is too small to have any real impact on SDG&E's RPS procurement obligations and is too expensive to be justifiable; in effect, TURN says, it is a demonstration project rather than a procurement plan.²³ TURN urges that we reject the plan, or at least ensure that it will not be too expensive by refusing to allow the use of supplemental energy payments (SEPs)²⁴ for the solar PV/small wind project. TURN also objects to the narrow geographic range of the other proposed general solicitation, believing that it is likely to yield too few bids to be economically sensible, and urges that this project, if not rejected, be denied SEPs.

SDG&E explains that the two solicitations will be evaluated consistently with one another. Only those projects meeting least-cost best-fit criteria will be short-listed. SDG&E argues that it is not worthwhile to solicit bids from the eastern part of its service territory, since those bids will almost certainly fail because of lack of adequate transmission.

The structure of both SDG&E solicitations should be revised to create an environment in which a reasonable number of competitive bids can be expected. The solar PV solicitation should be changed to allow not only the ten-year buyout proposal described, but bids for PPA-only and turnkey proposals as well. The all-resource solicitation should be broadened to remove the geographical restriction. It must also encompass our requirement that utilities allow delivery to any point in the CAISO control area and allow bids with curtailability as an attribute.

Further, SDG&E must avoid treating the solar PV solicitation in isolation from the all-resource solicitation. A narrowly drawn solicitation may yield a project that, ranked against others equally narrow, was preferred, yet does not comport with least-cost best-fit criteria in a wider context. SDG&E has stated that the two solicitations are separate only because of their very different technical characteristics and that they will be evaluated consistently. To ensure that SDG&E's intentions in this regard are carried through, we will require SDG&E to evaluate the bids from the two RFOs together and to develop one short-list for 2005 bids. When SDG&E's solicitations are revised as we have required, TURN's and UCS's concern about the possible overuse of SEPs should be allayed.

SDG&E also seeks advance waiver of the requirements of § 851 with respect to the solar PV/small wind project.²⁵ SDG&E explains that it intends to lease space on the roofs of its facilities for a rent of zero for the placement of the generating resources.

We have authority under § 853(b) to make exceptions to the requirements of § 851 when the application of § 851 is not necessary in the public interest.²⁶ We agree with SDG&E that filing an application under § 851 after any contract has been negotiated and signed could delay implementation of a solar PV/small wind project. The involvement of SDG&E property is relatively small and it will be used to generate electricity for the utility's customers. We do not, however, want to sign a blank check for any arrangement SDG&E might negotiate. We will therefore grant a waiver pursuant to § 853(b), conditioned on the circumstances of the contract being as SDG&E currently represents them and as we have additionally required:

1. The contract is the result of a solicitation for all forms of ownership of the generation and PPAs;

2. The contract is the result of a single least-cost best-fit ranking of all projects in both 2005 solicitations;

3. The winning bidder is not an affiliate of SDG&E;

4. The bidder has access to SDG&E property only for the life of the contract and only for the purposes of the contract.

If any of these conditions are not met by the winning bid, SDG&E must file an application under § 851.

E. Reporting

In order to allow orderly evaluation of utilities' compliance with RPS program requirements, a uniform reporting regime is necessary. Three aspects of reporting have been the subject of comment from the parties: the format of reports, the timing of reports, and the treatment of line losses in reporting. With the scoping memo, we attached Green Power's proposed RPS Annual Procurement Target (APT) reporting template. While parties generally agreed with the proposed template, PG&E identified several key elements that were not included in the template. The template does not take into account banking or shortfalls in renewable procurement, application of flexible compliance guidelines, or computational transparency for the APT.

We therefore adopt Green Power's proposed reporting template as an interim approach for the APT compliance reports. (Attached as Appendix A.) Energy Division will hold a workshop to address further refinements to the adopted reporting format, including the issues noted above and coordination with utility reporting to the Energy Commission on delivery of RPS generation.

Green Power proposed that reports be filed in February and July each year. Initially, PG&E suggested that the reports be moved to March and August, to allow the utilities to obtain more complete information from the prior calendar year. This proposal was generally supported by other parties. PG&E's subsequent suggestion that the reports be moved to May and November, to allow full use of the utilities' FERC Form 1 filings, was objected to by the parties who were willing to agree on the March/August system. UCS's suggestion that reports be filed in March and August, with the opportunity to supplement or amend the earlier filing by May 1^st, is a good one, and we adopt it.

In its 2005 plan, PG&E suggests that the utilities' reporting dates should be set in accordance with their solicitation cycles. Green Power and UCS oppose this idea, pointing out that it could yield three different, unpredictable, reporting cycles. We agree. RPS obligations are keyed to calendar years; reporting on those obligations should follow the same calendar.

Green Power, supported by ORA, also suggested that the quantity of renewable energy reported should be adjusted for line losses, so that the utilities are reporting electricity delivered to the end-user customer. Since the percentage of retail sales to end-user customers are the measure of RPS obligations, Green Power argues, the electricity delivered to retail customers should be the measure of RPS compliance. Green Power and ORA acknowledge that there is currently no method that would yield a precise quantification of the line losses for such reporting; ORA suggests workshops on this issue.

No other parties support this proposal. PG&E and SCE argue that they already take into account line losses between the generator and the point of delivery to the utility. They urge that their procurement obligation should be measured from the point at which they procure (take control of) the energy. This, they say, is the contractual delivery point, and it should define their RPS as well as their legal obligations. ORA argues that the ratepayers receive the electricity delivered to the end-user customer, not the electricity delivered to the utility, so this legal analysis does not resolve the issue.

We agree with the utilities that the point of delivery to the utility is the point at which the amount of electricity procured from eligible renewable resources should be counted, and that is the amount that should be reported. As SCE points out, the RPS statute obligates the utilities to "procure" electricity from eligible renewable resources, and specifies that "'procure' means that a utility may acquire the renewable output of electric generation facilities. . ." (§ 399.14(g).) We will not impose any additional burden to compensate for distribution losses beyond compliance with the procurement obligation set by statute.

F. Next Steps for 2005

Once the utilities have made and submitted the changes to their draft RFOs required by this decision, they may begin their 2005 solicitations. The other element necessary for completing solicitations, the 2005 MPR, has been the subject of workshops. After party comment on the workshops, we will issue a decision adopting the methodology for the MPR for 2005. After the utilities inform staff that they have developed short lists of bids, the assigned commissioner will release the 2005 MPR calculation for comment.²⁷ After consideration of the comments, we will by resolution adopt the final MPR for 2005.

We also intend to address the participation of community choice aggregators and energy service providers, in accordance with §§ 399.12(c)(2) and 399.12(c)(3)(C), during 2005.

G. Procurement planning in 2006

In order to move toward a calendar-year solicitation cycle, we anticipate that the utilities will file and serve their 2006 draft plans and draft RFOs in December 2005 in this proceeding or a successor proceeding, on a schedule to be set by the assigned Commissioner.

We will address the long-term plans filed in this proceeding in a subsequent decision. After that decision, we intend to return long-term RPS planning to the long term procurement planning component of R.04-04-003 or its successor, as contemplated by § 399.14(a).

²⁵ Sec. 851 provides:

No public utility other than a common carrier by railroad subject to Part I of the Interstate Commerce Act (Title 49, U.S.C.) shall sell, lease, assign, mortgage, or otherwise dispose of or encumber the whole or any part of its railroad, street railroad, line, plant, system, or other property necessary or useful in the performance of its duties to the public, or any franchise or permit or any right thereunder, nor by any means whatsoever, directly or indirectly, merge or consolidate its railroad, street railroad, line, plant, system, or other property, or franchises or permits or any part thereof, with any other public utility, without first having secured from the commission an order authorizing it so to do. Every such sale, lease, assignment, mortgage, disposition, encumbrance, merger, or consolidation made other than in accordance with the order of the commission authorizing it is void. The permission and approval of the commission to the exercise of a franchise or permit under Article 1 (commencing with § 1001) of Chapter 5 of this part, or the sale, lease, assignment, mortgage, or other disposition or encumbrance of a franchise or permit under this article shall not revive or validate any lapsed or invalid franchise or permit, or enlarge or add to the powers or privileges contained in the grant of any franchise or permit, or waive any forfeiture. Nothing in this section shall prevent the sale, lease, encumbrance or other disposition by any public utility of property which is not necessary or useful in the performance of its duties to the public, and any disposition of property by a public utility shall be conclusively presumed to be of property which is not useful or necessary in the performance of its duties to the public, as to any purchaser, lessee or encumbrancer dealing with such property in good faith for value; provided, however, that nothing in this section shall apply to the interchange of equipment in the regular course of transportation between connecting common carriers.

The commission may from time to time by order or rule, and subject to those terms and conditions as may be prescribed therein, exempt any public utility or class of public utility from this article if it finds that the application thereof with respect to the public utility or class of public utility is not necessarily in the public interest. The commission may establish rules or impose requirements deemed necessary to protect the interest of the customers or subscribers of the public utility or class of public utility exempted under this subdivision. These rules or requirements may include, but are not limited to, notification of a proposed sale or transfer of assets or stock and provision for refunds or credits to customers or subscribers.