4. Issues Common to All Plans

We address the following 11 issues common to all plans:

· 4.1: Solicitation for Short-Term Contracts and Delaying or Foregoing 2008 Solicitation

4.1. Solicitation for Short-Term Contracts and Delaying or Foregoing 2008 Solicitation

The July 31, 2007 ACR asked each IOU to address whether or not pursuing one or both of the following two strategies would enhance its ability to reach the 20% by 2010 RPS goal:

In response, each IOU affirms its desire to solicit short-term contracts. PG&E and SCE express no interest in postponing or foregoing the 2008 solicitation. SDG&E proposes that it be permitted to later decide on its own whether or not to conduct a solicitation in 2008.

We largely accept the IOUs' views. In particular, each IOU may solicit contracts for less than 10 years, as well as for 10 years or more, subject to (a) filing reasonable amended Plans to incorporate this option, and (b) counting short-term energy consistent with the condition adopted in D.07-05-028. Further, we neither delay nor forego the 2008 solicitation. We address SDG&E's proposal separately below.

4.1.1. Short-Term Solicitations

On September 6, 2007, PG&E filed its proposed revised draft Protocol to incorporate a short-term solicitation. SCE did not submit a revised draft, but states that opening its 2008 solicitation to short-term contracts will not require significant revisions to existing documents. This also appears to be the case for SDG&E. Thus, in addition to any additional refinements PG&E might make, our acceptance of the request to include solicitation of short-term contracts in the 2008 solicitation means SCE and SDG&E must each revise their documents to accommodate such proposals.

As provided below, amended Plans will be filed and served pursuant to this order, and may include solicitations for short-term contracts. The Plans will be subject to Energy Division review for consistency with this order and program protocols. The actual solicitation for short-term bids may be combined with, or separate from, that for long-term bids. Short-term contracts must be evaluated using criteria that accurately assess their LCBF characteristics, and parties should work with Energy Division staff, if and as necessary, to identify those criteria.

We recently adopted a condition relative to the use of short-term contracts. (D.07-05-028.) That condition applies here as well. The condition is that in order for an IOU to count the energy deliveries from short-term contracts with existing facilities for RPS compliance in a given year, the IOU must also sign contracts of at least 10 years' duration and/or contracts with new RPS-eligible generation facilities for energy deliveries equivalent to at least 0.25% of its prior year's retail sales. (D.07-05-028, Ordering Paragraphs (OP) 1 and 2.)

We also address but decline to adopt three related proposals. First, PG&E proposes an expedited review process and reasonableness criteria for short-term contracts, referring to comments PG&E submitted in Rulemaking (R.) 06-02-012.4 We do not here adopt an expedited process or reasonableness criteria, but will address the matter in R.06-02-012 (where we are considering development of additional methods to implement the RPS Program, including details on short-term prices).

Second, SCE asks that the in-state delivery requirement for RPS projects be removed. (August 10, 2007 Amended Plan, p. 7.) We are not persuaded that any change is necessary, as discussed separately below.

Third, DRA suggests that each IOU's short-term procurement be above and beyond its annual target, including its procurement margin of safety. We decline to adopt this recommendation. Short-term contracts, as SDG&E points out, can fill temporary shortfalls and act as a bridge to the commercial online date of an RPS facility, particularly when the initial operation is delayed. Precluding use of short-term contracts until all other procurement goals have been satisfied, including a margin of safety, would deprive IOUs of a potentially useful and important compliance tool. We find no compelling reason to do so. Moreover, DRA's proposal is inconsistent with our recently adopted condition relative to use of short-term contracts. (D.07-05-028.) We considered relevant factors when adopting that condition, and are not persuaded by DRA to add to that condition now.

4.1.2. No Delay in 2008 Solicitation

No respondent asks for a Commission order to delay or forego the 2008 solicitation, and no party recommends a delay or suspension. We agree. Now is not the time to delay or forego the 2008 solicitation.

4.2. Flexible Compliance

SDG&E, SCE and PG&E each request modification of Commission flexible compliance rules. We agree. Flexible compliance provisions, as modified, are discussed below, and summarized in Appendix D.

4.2.1. 2010 and After

Our existing flexible compliance provisions apply through 2009, but do not apply in 2010 and thereafter. (D.06-10-050, OP 2.) SCE and others point out that recent legislation (SB 107) modified the statute such that flexible compliance must apply not only up to 2009, but to all years. They are correct.5 The law now specifically requires that flexible compliance rules apply in all years, and we make that modification. (See Appendix D.)

We recently noted that current flexible compliance rules are in the context of reaching the 20% goal, and that existing rules:

"are likely to lose considerable relevance once the 20% goal is reached... That is, flexible compliance may or may not have some separate usefulness after a `steady-state' of 20% is reached...In a steady-state context, for example, it may be a better balance of competing interests to more strictly apply the `no more than the following three years' statutory language. (§ 399.14(a)(2)(C).) This may result in restricting flexible compliance to a period of less than the full three years." (D.06-10-050, pp. 28-29.)

Nonetheless, SCE and others argue here that the most logical extension of flexible compliance rules is to simply apply current rules to 2010 and beyond. The record contains few proposals regarding different rules for 2010 and beyond, and no party convincingly argues that flexibility should be for a period less than three years. Absent a viable alternative, we adopt SCE's proposal to extend current rules, subject only to the minimal modifications noted below.

We expect continuing consideration of the issue, however, and encourage parties to make proposals. For example, current rules are complex. We welcome parties making reasonable proposals that will simplify the rules while both maintaining incentives to achieve targets and recognizing the realities of "lumpy" investments (i.e., wherein capacity additions are not necessarily made smoothly from year to year but may be made in large or discontinuous increments). We discuss this further below in the context of 33% by 2020.

Current rules allow a load serving entity (LSE) to carry forward a deficit in relation to 25% of its IPT (e.g., up to 25% of its IPT for up to three years without explanation, and over 25% of IPT for up to three years with certain allowed explanations). (For example, see D.06-10-050, Attachment A, p. 9.) SCE recommends the substitution of "0.25% of prior year retail sales" for "25% of IPT." We agree. IPT does not apply to 2010 and beyond. SCE's proposed change does not alter the fundamental calculation in the original rule but is necessary, and we make this change.

4.2.2. Transmission

In 2006, we said:

"We will not be sympathetic to granting waivers or reducing penalties due to lack of transmission, for example, without the electrical corporation demonstrating that it took all reasonable action to bring the problem to our attention timely, presented realistic solutions, filed applications timely for necessary projects, and took any and all other actions that could reasonably have been expected to address, if not solve, the problem." (D.06-05-039, p. 20.)

IOUs point out the law now specifically requires that provisions for flexible compliance address situations where a deficit occurs as a result of insufficient transmission. They are correct.6

Parties do not propose the precise and exact language they seek to have adopted in a specific rule regarding flexible compliance due to insufficient transmission. They do not propose specific language (e.g., insertions and deletions) to modify our adopted "Renewables Portfolio Standard (RPS) Rules for Reporting and Determining Compliance with RPS Procurement Targets." (D.06-10-050, Attachment A.) No specific proposals are made regarding how parties would ensure that these rules do not conflict with the electrical corporation's overall procurement plan (as submitted pursuant to § 454.5). DRA says a shortfall created by lack of transmission raises many questions, and makes it impossible to formulate a flexible compliance mechanism. (Opening Comments, p. 5.) We agree questions arise, but disagree that it is impossible to implement § 399.14(a)(2)(C)(ii).

We implement this provision by requiring a retail seller to make a showing when seeking to invoke insufficient transmission as a permissible reason for failing to satisfy its RPS Program targets. The burden of proof rests with the entity requesting the relief. The showing must demonstrate that the retail seller has undertaken all reasonable efforts to do at least all of the following:

(1) Utilize flexible delivery points.

(2) Ensure the availability of any needed transmission capacity.

(3) If the retail seller is an electric corporation, to construct needed transmission facilities.

(4) Done nothing to conflict with its overall procurement plan (§ 454.5).

Broad, general statements would be insufficient to meet a retail seller's burden of proof. To be compelling, the showing must include specific facts and details.

If authorized, the deferral may be for up to three years. That is, the Commission is obligated to adopt flexible rules for compliance "including rules permitting retail sellers to apply...inadequate procurement in one year to no more than the following three years." (§ 399.14(a)(2)(C)(i).) Thus, consistent with the flexible compliance framework in the statute, the allowed deficit due to insufficient transmission may be applied "to no more than the following three years."

Center and Sierra contend SDG&E's 2008 Procurement Plan should not be accepted to the extent it seeks to link RPS compliance to the approval of certain transmission projects. Center and Sierra argue that this shifts accountability from SDG&E to the Commission and others, and that inadequacy of transmission should not be permitted as an excuse for failing to meet RPS Program targets.

While we agree with Center and Sierra that compliance with RPS Program targets is the responsibility of retail sellers (not the Commission or others), Center and Sierra fail to acknowledge current provisions in law regarding transmission and flexible rules for compliance. The law requires that Plans include provisions for employing available compliance flexibility, and that flexible rules for compliance address situations where insufficient transmission causes a retail seller to incur an RPS deficit. (§§ 399.14(a)(3)(B) and (a)(2)(C)(ii).) We do that here, and are not persuaded by Center and Sierra otherwise.

At the same time, we expect each retail seller to reasonably diversify its RPS procurement portfolio, taking generation and transmission project development risk into account. We will not shield a retail seller from possible RPS non-compliance penalties who fails to reach RPS program targets due to unreasonable failure to diversify.

Center and Sierra also express concern regarding timely action by a retail seller to address transmission line issues. Center and Sierra state that misconduct relative to timely action should not be rewarded by allowing a retail seller to evade penalties if it also fails to meet RPS targets. In particular, Center and Sierra make various contentions alleging misconduct by SDG&E relative to projects and untimely actions regarding the Sunrise transmission line and a new substation connecting to the Soutwest Powerlink. Center and Sierra conclude that SDG&E should not be excused from penalties.

It is premature here to reach any conclusion regarding penalties or penalty avoidance for SDG&E. Center and Sierra may raise their concerns and specific allegations in the future if and when SDG&E actually applies flexible compliance provisions to avoid or defer a penalty. Concerns regarding specific projects or transmission line issues are likely to be best addressed in specific proceedings (e.g., Application (A.) 06-08-010 for the Sunrise Powerline Transmission Project), and we decline to address those specific issues here.

4.2.3. Banked Surplus and Pooling

SCE requests two determinations regarding the use of flexible compliance. We authorize both requests.

First, SCE requests a Commission statement that:

"If an LSE earmarks future deliveries toward its APT requirement and the project does not deliver enough actual deliveries to fill the APT requirement prior to the end of the third year after the compliance year towards which the output of the project has been earmarked, the LSE may then use its bank excess procurement to fill the deficit." (Plan, p. 5.)

In support, SCE says this is consistent with the Commission's previous findings that the use of banked excess procurement is "unlimited." SCE is correct. We have said this before. We reaffirm it now. (D.03-06-071, p. 44; D.06-10-050, p. 24.)

Second, SCE requests a Commission statement that:

"If the future energy deliveries earmarked by an LSE do not materialize within three years, the LSE may use actual energy deliveries from any other contract eligible for earmarking to satisfy the deficit." (Plan, p. 5.)

SCE contends that the current RPS reporting format requires an LSE to choose the specific contract it elects to earmark along with the quantity of earmarked future energy deliveries from each contract. SCE asserts that an LSE should not be found deficient for failing to predict precisely which contracts eligible for earmarking produce the actual procurement several years later. We agree.

An LSE needs to execute contracts that result in actual deliveries within three years, but should be allowed to satisfy a deficit by using actual energy deliveries from any contract that is otherwise eligible for earmarking.7 That responsibility should not include the burden of forecasting the exact contract and future deliveries. We encourage Energy Division to work with LSEs to revise reporting forms, if and as needed, to treat earmarked contracts as a pool for purposes of flexible compliance (with pooled contracts accurately tied to the deficit year).

4.2.4. Other Mechanisms

SDG&E recommends consideration of two other flexible compliance mechanisms:

1. unbundled renewable energy credits (RECs), and

2. unlimited carry-forward of any shortfall due to either:

a. failure of a developer to perform up to contract commitments, or

b. delay caused by lack of transmission.

SDG&E also recommends (a) setting workshops as soon as possible to allow participants to offer other flexible compliance mechanisms, and (b) convening a future proceeding as expeditiously as possible. (Plan, pp. 4 and 11.) We decline to adopt these recommendations for the following reasons.

The treatment of RECs is being addressed in R.06-02-012. We will not prejudge the REC issues here.

SDG&E recommends unlimited carry-forward of procurement deficits in certain cases. Center and Sierra object. We agree with Center and Sierra.

Existing legislation permits carry-forward of "inadequate procurement in one year to no more than the following three years." (§ 399.14(a)(2)(C)(i).) We are not persuaded by SDG&E that the law provides unlimited deficit carry-forward.

Even if it did, unlimited deficit carry-forward would make the 20% target essentially, if not completely, meaningless. It would eliminate any need for reasonable planning and procurement margins of safety to offset delays or failures in generation projects or transmission lines. It would shift substantial burden for achieving RPS Program goals from electric corporations to developers of generation and transmission projects. This is unreasonable.

The better balance is to allow deferrals up to a defined period of time, but continue to require periodic market solicitations by electric corporations to tap new opportunities. This permits an electrical corporation to take all reasonable actions, including portfolio diversification, to overcome barriers to RPS compliance. We continue to require that RPS procurement goals and targets, along with compliance determinations, are ultimately measured in actual deliveries. (See, for example, D.05-07-039, Findings of Fact 12 and 13.)

SDG&E contends that the Commission has already endorsed its proposals, particularly with regard to carry-forward of shortfalls due to seller non-performance. (Reply Comments, p. 4, citing D.03-06-071 in support.) SDG&E is incorrect. Our authorized carry-forward of procurement deficits is in the context of three years. For example, in 2003, we rejected what we characterized as the "extreme" proposals of PG&E and SCE, but pointed out that even those proposals were for only up to three years. (D.03-06-071, p. 46.) We adopted The Utility Reform Network/SDG&E approach, permitting carry-forward for up to three years, and required the electric corporation to "satisfy this deficit with that three-year period." (D.03-06-071, p. 49.)

Finally, we decline to order workshops or a further proceeding on this issue at this time. Other reasonable opportunities are currently available to pursue this issue. As noted above, for example, we welcome further proposals on flexible compliance rules, particularly those which might simplify the flexible compliance framework while maintaining incentives and recognizing other important realities. At the same time, however, parties are fully engaged on multiple issues in this and other proceedings. We will not increase their burdens by establishing workshops or another proceeding.

4.2.5. 33% by 2020

We slightly modify existing flexible compliance rules above (e.g., transmission, pooling) but essentially continue existing rules in 2010 and beyond. We do this in large part because we expect RPS procurement to grow beyond 20% by 2010 toward 33% by 2020. The goal of 33% by 2020 is a proposed goal of the Governor, and has been conditionally adopted by the California Energy Commission (CEC) and Commission.8 This is approximately an additional 1% per year from 2010 to 2020. Existing rules are in the context of the legislatively required growth of no less than 1% per year to 20% by 2010. Continuation of existing rules is not necessarily unreasonable when the growth factors underlying those rules are expected to continue.

GPI, among others, supports the 33% by 2020 target, observing that to rest at 20% by 2010 would result in a quick burst of activity followed by an abrupt and precipitous halt. Also, as recently stated, we agree "with Aglet that pursuing a 33% target is a policy goal of the Commission and one that should be pursued by the IOUs at this time." (D.07-12-052, p. 255.)

We do not at this time, however, subject any retail seller to the possibility of penalties for failure to procure more than 20%. That is, the trajectory of RPS resource procurement past 2010 is not composed of annual or final targets with penalties attached for failure to achieve targets. The only specific goals to which penalties apply are the annual 1% growth targets to achieve 20% by 2010, and the final 20% target (subject to flexible compliance rules). At the same time, however, we reaffirm our recent direction that parties work with Energy Division staff to refine a methodology for resource planning and analysis to address the issue of a 33% renewables target by 2020. (D.07-12-052, p. 256.) Development of this methodology may include assessment of whether or not to apply penalties for failure to achieve certain targets beyond 20%.

4.2.6. General Application

In comments on the proposed decision, Mountain Utilities (MU) says this decision, particularly regarding flexible compliance, should apply only to SCE, PG&E and SDG&E. Alternatively, MU says the Commission should (a) allow electric micro-utilities to easily obtain deficit forgiveness and (b) adopt flexible compliance rules concerning transmission constraints that allow electric micro-utilities to obtain deficit forgiveness for up to three years with further forgiveness upon a Tier 1 advice letter showing. No other party supports MU's specific comments, including no comments in support from other small and multi-jurisdictional utilities (SMJUs).

We decline to adopt MU's recommendations. Rather, we have said before and restate here that all RPS rules, unless we say otherwise, apply equally to all LSEs, including electric service providers, community choice aggregators and SMJUs. (See, for example, D.05-11-025, D.06-10-019, D.06-10-050, D.07-07-025, D.07-05-028.)

We specifically clarify here that the flexible compliance rules adopted today apply to all LSEs. Any adjustments that may or may not be necessary for SMJUs will be addressed in R.06-02-012. In the meantime, however, LSEs may rely on the additional flexible compliance provisions adopted herein (e.g., flexible compliance beyond 2009, certain deficits permitted upon a showing relative to insufficient transmission, pooling). This advances the program consistent with recent changes in law without causing any party undue hardship or prejudging outcomes. It permits further refinements, if and as necessary. It allows these important changes to be used for upcoming reports due soon (e.g., March 1, 2008).

4.3. Transmission Ranking Cost Report

Parties were asked to consider experience with the current Transmission Ranking Cost Report (TRCR) process and recommend improvements, if any. SDG&E recommends that the TRCR be completed based on actual bids offered in each solicitation. We decline to adopt SDG&E's recommendation for the reasons explained below. We first briefly explain the current process.

Transmission costs may be considered within the LCBF analysis. To do this, each IOU first seeks expressions of interest from potential project developers regarding the IOU's upcoming RPS solicitation. The IOU also seeks certain data to calculate applicable costs. The costs are calculated using a Commission-adopted methodology and reported in the TRCR, including relevant transmission information and resulting "transmission cost adders." The TRCR is filed and served for comment by parties. The assigned Commissioner considers comments and issues an ACR regarding the TRCR results to be used for a particular solicitation. The ACR is filed before the solicitation begins, thereby permitting the IOU to include TRCR information and "adders" in its solicitation documents. This information may then be used by prospective bidders as they consider projects and develop bids. This also ensures that the "adders" are available in a transparent form for use by each IOU in its LCBF ranking of projects. (See D.04-06-013, D.05-07-039, D.05-07-040, D.06-05-039 and D.07-02-011.)

In support of its proposal, SDG&E says the current process creates a TRCR for projects that do not necessarily match the projects bid into the solicitation. SDG&E says its 2007 bid results, for example, included only two out of thirty-four projects that participated in the TRCR process. In such case, the IOU, according to SDG&E, has a difficult time assessing the appropriate transmission cost for projects bid into the solicitation. On the other hand, SDG&E says if the TRCR is based on actual bids, then all projects are included in the analysis and only projects actually under consideration are studied. SDG&E asserts this is also an important workload consideration. (Plan, p. 18.) No other respondent or party supports SDG&E's proposal.

Accuracy and workload are important considerations, but we must balance many factors. For example, SDG&E presents no data in support of its proposal regarding the magnitude of potential accuracy gains, or how its LCBF ranking might be different. One reason for the current TRCR schedule is to permit potential projects to take transmission costs into account when submitting bids. SDG&E's proposal does not suggest a viable alternative so that bidders may have relevant transmission information during the bid preparation stage.

We are concerned that the efficiency gains (or cost savings) from waiting to do the TRCR may be offset by delays in each IOU developing its project short-list. This could delay the entire solicitation process. SDG&E presents no information on this tradeoff.

We also note that considerable work is now underway as a result of the California Renewable Energy Transmission Initiative (RETI). RETI is a statewide initiative to help identify the transmission projects needed to accommodate California's clean energy goals, support future energy policy, facilitate transmission corridor designation, and mitigate difficulties in transmission and generation siting and permitting. It begins with a thorough assessment of renewable energy potential in California and neighboring regions. We think focusing efforts of IOUs and parties on RETI is likely to be a better use of limited time and resources than modifying the TRCR process. We repeat our encouragement that IOUs and all other parties participate fully in RETI. (D.07-12-052, pp. 75-76.)

4.4. Standard Terms and Conditions

PG&E states that, as an important change from its 2007 Plan, the model contract in its final 2008 Plan will be modified to conform to the Commission's recent decision on standard terms and conditions (STCs) for model contracts. While PG&E's Plan was filed before adoption of our STC order, PG&E correctly notes the relevance of the recent order. The model contracts in the Plans of SCE and SDG&E must similarly conform.

That is, we recently addressed STCs, and found four STCs to be non-modifiable. (D.07-11-025.) The model contracts in the IOUs' 2008 Plans submitted pursuant to this order must include the four non-modifiable STCs in conformance with our order.

On the other hand, we found 10 STCs to be modifiable. We require that the initial language for these 10 STCs incorporate the principles behind each STC, as adopted in prior Commission orders.9 We generally seek consistent and uniform model contract language for these 10 STCs, but permit each IOU to propose its own initial language, subject to being vetted in the process leading to Commission acceptance, rejection or modification of each Plan. Consistent with our adopted approach, IOUs proposed language for the 10 modifiable STCs. No parties comment. We accept the 10 modifiable STCs as proposed by each IOU, unless specifically noted otherwise herein.

SCE asks for clarification regarding STC 3 (Supplemental Energy Payments-SEPs). In particular, SCE says that, in the event SCE exercises its option to replace denied SEP funding from the CEC, the "right of first refusal option" in STC 3 requires SCE to make higher cost replacement payments before SCE obtains Commission approval. SCE says it assumes it would be permitted to recover such costs in rates, but seeks clarification. Absent clarification, SCE says it would be required to modify its model contract.

We have determined that STC 3 is modifiable, and need not be included in contracts that do not involve SEPs. (D.07-11-025.) Moreover, the SEP process is substantially changed by passage of SB 1036, and the relevance of STC 3 will continue to decline as SB 1036 is implemented over the course of the next few months. Nonetheless, to the extent it is meaningful during the transition, we affirm SCE's understanding of STC 3.

4.5. Reporting on Transmission

DRA recommends that future RPS Plans state (a) the estimated online dates for anticipated transmission lines and (b) how much of each IOU's RPS effort relies on any particular transmission line. In support, DRA asserts that transmission issues are important in meeting RPS goals. DRA also states that this information is needed because not all transmission line concerns are the same, IOU's Plans fail to differentiate between lines likely to be in operation by 2010 versus those after 2010, some Plans confuse the impact of transmission limitations with other efforts to meet RPS goals, and some Plans provide little support for assertions regarding the need for transmission to meet RPS goals.

We decline to adopt DRA's recommendations. PG&E correctly points out that the IOUs already provide information and status updates on transmission lines in quarterly Assembly Bill (AB) 970 reports to the Commission. Adequate planning and status information is available elsewhere without requiring that it also be included in the RPS Procurement Plan. Moreover, considerable effort is underway in other venues on transmission issues, including RETI. We decline to require further work and detail here.

Nonetheless, we agree with DRA's general concern. While we do not expect the RPS Procurement Plan to become a report on transmission issues and transmission lines, we remind IOUs that the RPS Procurement Plan must reasonably address all important issues that concern the RPS Program and the IOU's planned procurement. To the extent transmission is a reasonably important issue the Plan must address the issue to the extent necessary. This may be by reference to other filed documents, as appropriate. IOUs generally did so with the 2008 Plans, and should continue to do so.

4.6. Margin of Safety

Each IOU's Plan includes a margin of safety, thereby building in a buffer to recognize potential project delays or failures while still permitting reasonable opportunity to achieve Program targets. For example, PG&E states it will procure between 1% and 2% of its annual incremental requirement (not just the minimum 1% annual growth). SCE states that it is procuring to a High Need Case Scenario (assuming only 70% delivery from certain contracts, not 100%). SDG&E says it will seek to procure between 24% and 26% of retail sales for its 2010 goal (rather than 20%).

Parties continue to raise concerns about the risk of not achieving 20% by 2010. In particular, Center and Sierra argue that SDG&E's procurement goals and margin of safety are inadequate. Center and Sierra recommend the Commission highlight in this decision that IOUs, and in particular SDG&E, proceed at their own risk.

We have addressed the need for each IOU Plan to include a reasonable margin of safety, and that each IOU remains responsible for achieving program goals, within reasonable application of flexible compliance rules. (See, for example, D.06-05-039, pp. 21-24; D.07-12-052, pp. 74-75.) We agree with Center and Sierra that each IOU Plan must include a reasonable margin of safety, each IOU must undertake all reasonable actions to achieve RPS Program goals, and results are not measured by contracts but actual energy deliveries. Nothing offered by Center and Sierra persuades us to modify our prior discussion, direction and orders in this regard, nor do we need to highlight our orders for one entity.

GPI believes IOUs are being seduced by attractive bids that will never be fulfilled while overlooking realistic bids which, even if more expensive, are more likely to deliver energy. GPI asserts that utilities are not selecting enough high-quality, likely-to-succeed projects. GPI concludes that IOUs need to assign realistic probabilities of success to various bids so that they select quality projects.

IOUs correctly point out in response that these factors are already taken into account as part of the LCBF process. For example, LCBF assessment includes not only total price but seller's capability to perform, economic viability, technological viability and project viability (e.g., stage of project development, developer experience, availability of financing).

Moreover, GPI acknowledges that selecting quality renewable projects may include some subjective judgment that takes into account many factors (e.g., experience, backing, developer's technical expertise, technology). (GPI comments, p. 4.) We appreciate GPI's candor. Neither GPI nor any other party proposes a scientific method that guarantees selection today of only the highest quality projects certain to succeed tomorrow. Rather, the highest quality, most likely-to-succeed projects are winnowed-out using a process. The process includes requiring each electric corporation to have an RPS Procurement Plan. Procurement is by tariffs/standard contracts for some projects (e.g., up to maximum megawatt limits for small water, wastewater and other customer generation). It is by bilateral negotiations for some projects, and by competitive bids for other projects. Selection, as appropriate, includes an LCBF analysis, certain deposits, credit assessment, PRG review, independent evaluator (IE) review, public comment and Commission review. The process involves some measurable elements, and some judgment.

An important component of each IOU's Plan is inclusion of a reasonable margin of safety, with IOUs ultimately being responsible for reaching Program targets, subject to flexible compliance provisions. We welcome specific proposals for additional improvements, but accept that some subjective judgment will always be a necessary part of the selection process as decisions are made about various projects based on informed views of future events and the likelihood of a range of outcomes. While we reiterate our support for including a margin of safety, it is up to each IOU to determine the optimal level (subject to review, as necessary, such as in a possible assessment of a penalty for failure to meet certain RPS targets).

4.7. Tariffs for Small RPS Projects

We recently approved tariffs and standard contracts for IOU purchases of electricity from small RPS generators (less than 1.5 MW) owned by water and wastewater agencies. We also approved a limited expansion of these tariffs and standard contracts to other small generators in the PG&E and SCE service areas. For the three IOUs, the total authorized procurement pursuant to these tariffs/standard contracts is 476.9 MW. (D.07-07-027.)

We directed that each IOU notify its water, wastewater and certain other customers on the availability of this new opportunity. (D.07-07-027, OP 4.) We also directed that the IOUs provide reasonable information to the Commission. (D.07-07-027, OP 3.)

We clarify here that we do not want the IOUs to take a passive approach to this opportunity. Rather, we expect IOUs to not only notify their water, wastewater and certain other customers (including Commission-regulated water and wastewater utilities) of this new option, but to work with these customers, as necessary and appropriate, to facilitate reasonable development of renewable projects. This may mean, for example, offering a workshop for these customers to explain the tariffs/standard contract option; holding workshops, or individual meetings, to help customers identify generation potential; and helping customers consider financing opportunities (e.g., whether energy efficiency funds may be available in some circumstances for certain projects which increase energy efficiency while generating output).

In this regard, we are interested in learning more about the opportunities for, and impediments to, the success of this program. If requested by staff (e.g., either the Director of the Water or Energy Divisions), each of the three IOUs should prepare a report on the IOU's work with its water and wastewater agency customers (and other customers to the extent requested); the generation opportunities identified; the impediments that may exist; recommended solutions, if any, to each impediment; and anything else relevant to advancing the success of tariffs and standard contracts for smaller RPS projects. This goal might also be advanced by individual meetings or a workshop. We encourage staff to schedule meetings or a workshop, if useful.

4.8. Increase Minimum Size of Project to Participate

Each utility's Plan requires that projects be at least 1.0 MW in order to participate in a solicitation.10 This is in part because, in order to meet the hundreds of MW embedded in the 20% by 2010 objective, utilities primarily need (and generally want) to devote limited time and resources to bid processing and LCBF analysis for larger rather than smaller projects.11

A minimum size to participate in a bid solicitation may also make sense for many developers. That is, from the developer's perspective, smaller projects tend to have a difficult time participating in solicitations and such participation may be unreasonably costly (e.g., sorting through what may be complex documents, attending bidders conferences and/or workshops, preparing documents, engaging in post-bid negotiations). To address these and other concerns, utilities and developers now have the option of using tariffs/standard contracts for smaller projects up to 1.5 MW. (D.07-07-027.)

Based on the availability of the tariff/standard contract option for smaller projects, it is reasonable to slightly increase the minimum size of projects participating in RPS solicitations. We therefore accept the IOUs' Plans on the condition that they are amended to increase the minimum size for projects to bid into a solicitation from 1.0 MW to 1.5 MW. This will help focus projects on efficient use of tariffs/standard contracts, and permit utilities to generally devote attention to larger projects. This does not, however, foreclose the use of another approach (e.g., bilateral negotiation, individual contract) if a particular project requires unique treatment.

We also note that the focus of RPS solicitations is largely intended to be on commercially viable projects evaluated using an LCBF methodology. Slightly increasing the MW limit for projects to submit bids is consistent with that focus, while at the same time using a streamlined approach for commercially viable, but smaller, projects.

We also expect utilities to consider projects which employ emerging technologies. We are separately considering a request by PG&E and SDG&E to implement an Emerging Renewable Resource Program (ERRP). (See A.07-07-015.) If approved, emerging projects may perhaps be better evaluated via the ERRP rather than periodic RPS project solicitations. For improved clarity, it may be appropriate to have a solicitation for emerging, pilot and demonstration projects that is separate from the solicitation intended for commercially viable projects. IOUs should work with Energy Division on this, if appropriate.

Nonetheless, we expect utilities to evaluate all projects (including emerging, pilot, demonstration) no matter the method in which they are brought to the attention of the utilities, and despite the regulatory review process at the Commission. If evaluated via RPS bid solicitations, utilities may need to develop slightly different evaluation criteria for emerging, pilot and demonstration projects. Utilities should work with Energy Division on identifying those criteria, if any and as necessary. Utilities should present those projects (emerging, pilot, demonstration) in separate and clearly identified filings for Commission consideration.

4.9. Utility Ownership of RPS Facilities

We do not require IOUs to build RPS resources in order to meet RPS Program goals but we note, as we have before, that we expect IOUs to consider the option. For example, in enforcing the 20% by 2010 requirement, we will take into account whether or not each IOU undertook all reasonable actions to comply, including building and owning RPS resources. (See, for example, D.07-02-011, p. 23, citing D.06-05-039, p. 24.)

In this regard, the June 15, 2007 amended Scoping Memo directed that each IOU's Plan include information on its current consideration of whether or not to build its own renewable resources to reach 20% by 2010. Each IOU responded, indicating that it is considering the option, particularly when ownership would be cost-effective. Each also notes certain impediments, however, such as tax considerations, and the lack of a development group within the utility.12

We appreciate the responses, but note that the showings are relatively short, generally inconclusive, and unlikely to meet the standard we stated in 2007. Our prior statement on this matter regarding prior plans remains succinct and clear. We adopt it again here:

"In particular, we note (as we similarly did last year) that minimal discussion in an RPS Plan about a utility building a renewable energy resource does not itself excuse an IOU from compliance with RPS goals. Our conditional acceptance of these Plans does not constitute a finding that each IOU has undertaken all reasonable actions to comply with RPS Program goals. We do not here require utilities to build resources. Nonetheless, we encourage IOUs to actively assess the feasibility of utility ownership, and pursue such ownership when and where it makes sense. We are unlikely to look favorably on a showing prepared in 2010, for example, regarding whether the IOU should have built plant earlier in the decade. Rather, we think the most convincing showing, if any, would likely include information created contemporaneously with each annual RPS Plan." (D.07-02-011, p. 25.)

We also note three items from our recent decision on the IOUs' long-term procurement plans. First, there may be a unique and important role for utility-owned RPS generation. Utility-owned generation from renewable energy resources, for example, can put downward pressure on what are otherwise increasing renewable energy prices. This satisfies an important policy objective that justifies strong consideration of utility ownership. (D.07-12-052, p. 77.)

Second, we have identified five unique circumstances warranting utility ownership when a competitive bidding process is otherwise infeasible. One such circumstance is in the procurement of preferred resources, including renewables.13 While we continue to rely on markets where feasible, we note:

"there is no reason to limit our options and [we] intend to continue to deploy all resources available to us, including utility development and ownership, to meet California's vital environmental policy objectives." (D.07-12-052, p. 211.)14

Third, we have recently agreed with parties that a "one-size-fits-all" ratemaking regime for utility-owned generation is undesirable, and have specifically eliminated our prior 50/50 cost cap-sharing mechanism.15 We will now consider all ratemaking proposals when and as made on a case-by-case basis. (D.07-12-052, p. 221.) We expect this new approach to facilitate consideration of utility-owned RPS generation.16

4.10. Coordination of Plans

IOUs are to submit Plans in the form and format in which they seek their acceptance by the Commission. At the request of the assigned Commissioner, IOUs coordinated on further improvements in form and format for the 2008 Plans, and reported on those efforts. In particular, each IOU adopted the same outline for the summary document addressing its 2008 Plan (employing a list of items identified in the Amended Scoping Memo). We appreciate the uniform structure of that document.

As we did last year, however, we continue to note that each Plan is complex, with many attachments that are not easy to assess and use.17 In particular, the form and format of the attached solicitation documents (e.g., Protocol, RFP, RFO) differ between IOUs, as do the various related forms and model contracts. We are not convinced that such complexity is necessary, and we encourage IOUs to continue to seek incremental improvements. As we said last year:

"Each Plan is a complex document that is not easy to assess and use. Each Plan is quite different in structure than the other Plans. We note that improvements have been made in the Plans over the previous cycles, but each remains relatively complex. We are not certain they need to be.

We encourage each IOU to continue to seek ways to improve its RPS Plan. We encourage IOUs as a group to use a common form and format. There does not appear to be anything so particularly unique about the plan to buy, or the contract to buy, electricity from a third-party RPS generator that each IOU must have its own form and format (even if some of the details in a Plan, or some particular contract clauses, might be different).

Consistent with the direction above, each 2008 [and 2009] proposed Plan must be in a form and format which the LSE seeks to be adopted by the Commission. It must be complete and current. Moreover, we encourage IOUs to seek ways to organize, format and present each Plan in a manner that facilitates its use by all involved, including bidders and the Commission.

Finally, we encourage IOUs and parties to give serious consideration to further development of improved model contracts, including standard terms and conditions. Better and more uniform model contracts will likely to be useable by more bidders without requiring substantial further negotiation and modification. This will permit a more streamlined process for bidding, negotiation and Commission review. The additional time spent "up front" could potentially be small compared to the time savings for the entire remainder of the process. Further, by reducing transaction time plus transaction and other costs, it might make the overall RPS structure more transparent, efficient and competitive. This could offer an opportunity to assist LSEs and California achieve the overall RPS goals sooner at lower cost." (D.07-02-011, pp. 62-63.)

SCE reports that the IOUs faced significant challenges in making the 2008 solicitation forms and model contracts substantially similar. For example, SCE says the IOU's bid solicitation materials diverged several years ago, and it would be difficult to agree to identical or similar documents now. Each IOU has incorporated lessons learned that are specific to that IOU, according to SCE, and a requirement to use a single set of documents could potentially omit those lessons learned. Finally, SCE contends that it would not make sense for IOUs to negotiate over a standard form and format since the "enormous amount of time and effort it would take" to develop common documents would not produce any more contracts, nor streamline contracting time, because developers always demand changes. (SCE Plan, p. 30.) SCE strongly recommends the Commission not attempt to create additional similarities between bid solicitation materials other than the Procurement Plan.

We disagree. Materials diverged initially because exigencies largely required using a pragmatic approach. IOUs made proposals within a general framework, but we did not require uniformity. We do not now require uniformity, but think incremental improvements may be made each year toward that goal. Further, not all lessons learned by one IOU are unique to that IOU. Many such lessons should be employed more generally for the benefit of the entire State. Lastly, we are not seeking an "enormous" amount of time, but incremental improvements in form and format.

As we noted above, the additional time spent "up front" should be small compared to the time savings for the entire remainder of the process, including the Commission's time in reviewing endlessly different contracts. Additional uniformity will make the overall RPS structure more transparent, efficient and competitive. It may also promote desirable simplicity in a relatively complex Program. Nonetheless, we do not order a uniform form and format, but encourage IOUs and parties to build on past improvements (including those made for the 2008 Plan) and continue to make incremental progress.

4.11. In-State Delivery

SCE notes that the RPS Program is limited to renewable resources that meet the definition of "in-state renewable electricity generation facility." (§ 399.12(b) and Pub. Res. Code § 25741(b).) SCE asserts that this limits the pool of resources that can compete in solicitations, thereby reducing competition and increasing prices. SCE notes that legislation may be required, but recommends that the Commission consider relaxing or removing the in-state delivery requirement. (August 10, 2007 Amended Plan, p. 7.)

No party supports SCE's recommendation, and GPI objects, contending that some RPS Program benefits are dependent upon location (e.g., reduced pollutants, rural development opportunities). SDG&E and PG&E assert they will solicit bids both anywhere in California as well as outside California, to the extent consistent with law.

We are not persuaded that any change is necessary. An eligible renewable energy resource for the purpose of the RPS program means a facility, subject to certain limitations, that meets the definition of an in-state renewable electricity generation facility in § 25741 of the Public Resources Code.18 (§ 399.12(b).) While this generally requires delivery to an "in-state" location, facilities may be located in-state, out-of-state, or even outside the United States.19

There are complexities in tracking RPS electricity and its attributes (e.g., RECs). Relaxing or removing current in-state delivery requirements could introduce additional complexity. It may require new legislation. This must be balanced with a judgment regarding whether or not the current market is reasonably competitive. SCE provides no data on the potential benefits, if any, compared to the additional burdens, and no other party provides data to support SCE's recommendation.

We are confident that a reasonable pool of resources may be tapped in all regions (in-state, out-of-state, out-of-country) within current protocols, thereby permitting reasonable competition. We think this properly balances all competing needs and interests, and permits effective competition. If bid prices are elevated due to a lack of effective competition, however, the law provides that SCE or another party may bring this to the attention of the Commission, and we may direct renegotiation of contracts or a new solicitation, as appropriate. (§ 399.14(d).) SCE has also raised the issue in R.06-02-012, and we will address it further there to the extent necessary.

4 PG&E recommends that full rate recovery for short-term contracts of less than three years' duration be permitted without advance Commission approval. PG&E proposes that the price be treated as per se reasonable if the contract was executed after consultation with the Procurement Review Group (PRG), and reported in the IOU's Quarterly Report. PG&E asserts that the per se reasonable price should be up to the greater of market price referent (MPR) plus $20/megawatthour (mWh) or market plus 10%.

5 "The commission shall adopt... flexible rules for compliance, including rules permitting retail sellers to apply excess procurement in one year to subsequent years or inadequate procurement in one year to no more than the following three years. The flexible rules for compliance shall apply to all years, including years before and after a retail seller procurers at least 20 percent of total retail sales of electricity from eligible renewable energy resources." (§ 399.14(a)(2)(C)(i).)

6 Effective January 1, 2007, § 399.14(a)(2)(C)(ii) provides that: "The flexible rules for compliance shall address situations where, as a result of insufficient transmission, a retail seller is unable to procure eligible renewal energy resources sufficient to satisfy the requirements of this article. Any rules addressing insufficient transmission shall require a finding by the commission that the retail seller has undertaken all reasonable efforts to do all of the following:

7 Otherwise eligible for earmarking means (as PG&E and SCE say in reply comments on the proposed decision) that the applicable energy meets all other requirements for earmarking. Contrary to GPI's concern, this does not negate the safeguards that are in current earmarking rules, create unlimited earmarking, or change any existing rules. This is the case because pooling does not alter whether a contract is eligible for earmarking, the time limits associated with earmarking, or the amounts of energy permitted to be earmarked from year to year. (SCE Reply Comments on Proposed Decision, p. 2; also see, D.05-07-039, p. 13 and D.06-10-050, Attachment A, p. 10.)

8 Energy Action Plan II (October 2005, Section II.3.5, p. 8). Also see CEC 2007 Integrated Energy Policy Report (November 2007, CEC-100-2007008-CTF, p. 129, adopted December 5, 2007).

9 For example, STC 15 on contract modification essentially requires that no amendments or modifications are enforceable unless entered into in writing by both parties. Initial language proposed by an IOU must be consistent with this principle. (D.07-11-025, p. 23.)

10 PG&E, 2008 Solicitation Protocol, August 1, 2008, Chapter III.D.1.a (p. 6). SCE, 2008 RFP, Article 2.06 (p. 5). SDG&E 2008 RFO, Chapter 7 (p. 17).

11 The minimum size is even larger for some projects. For example, PG&E requires offers for dispatchable products to be at least 25 MW. (2008 Solicitation Protocol, Chapter III.D.1.a, p. 6.) SDG&E requires offers to be at least 5 MW if the facility is outside the SDG&E service area. (SDG&E 2008 RFO, Chapter 7, p. 17.)

12 For example, utility-owned RPS facilities are ineligible for certain investment tax credits and property tax exemptions. Regarding project development, SDG&E points out that it recently left the development business and re-entering the field is a significant undertaking not currently contemplated in its general rate case (GRC). (Plan, p. 26.) SCE, on the other hand, points out that its test year 2006 GRC decision (D.06-05-016) permits recovery of costs that support studying new generation, including renewables. (Plan, pp. 28-29.)

13 Preferred resources in order of preference are: energy efficiency, demand response, renewables, distributed generation and clean fossil-fuel. (D.07-12-052, p. 211, footnote 240.)

14 This may include electric utility ownership of electric generation sited at a water or wastewater company (including Commission-regulated Class A and B water utilities), with ownership by the electric utility or partial ownership in combination with the water or wastewater utility.

15 We previously required IOUs to bid utility-built projects into competitive solicitations and, for successful bids: (a) would not allow recovery from ratepayers of initial capital costs in excess of the final bid price ("cost cap") and (b) required 50/50 sharing of the savings between ratepayers and utilities when final capital costs were under the cost cap. (D.07-12-052, p. 213, citing D.04-12-048, pp. 128-129.)

16 For example, SCE stated that: "should SCE identify a cost-effective renewable energy generation opportunity, it would pursue the development of the associated generating facility under the assumption that it would receive a successful resolution of cost sharing issues." (August 1, 2008 Plan, p. 29.) We had only six months earlier advised SCE that, absent compelling reason otherwise, we were unlikely to agree with SCE that the asymmetric treatment alone would justify SCE deciding not to build RPS resources. (D.07-02-011, p. 25.) Nonetheless, we have now addressed SCE's concern.

17 Each Plan, for example, includes an overall summary and multiple additional documents. In addition to the summary, PG&E's Plan includes a Solicitation Protocol with 12 attachments (e.g., solicitation protocol agreement, form of letter of credit, offer form, FERC Order 2004 Waiver, model contract for as-available product, model contract for firm product, term sheet, confidentiality agreement). SCE's Plan includes a Request for Proposals (RFP) with six appendices (e.g., notice of intent to submit proposal, pro forma agreement, form of seller's proposal, TRCR, revenue calculator). SCE's form of seller's proposal itself contains six exhibits (e.g., proposal checklist, transmittal letter). SDG&E's Plan includes an RFO and six documents in its Appendix B (e.g., offer response forms, credit applications, consent form, offer summary sheet and check list, contract documents).

18 The CEC is responsible for implementing this definition. (See, for example, "RPS Eligibility Guidebook," CEC-300-2007-006-CMF, adopted March 14, 2007.)

19 See, for example, Resolution E-4128 adopted on November 16, 2007, approving PG&E's acquisition of electricity from PPM Klondike III in Sherman County, Oregon.

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