We have, in fulfilling our duties and allowing electrical corporations to fulfill theirs, granted RPS-obligated electrical corporations considerable flexibility in the way they satisfy RPS program goals. For example, we have generally employed the presumption that utilities should be permitted to use their best business judgment in running their solicitations, unless their plans threaten to impair the effectiveness of the RPS program. In this context, we have provided guidance, and adopted limited and specific program requirements. We have also taken steps to broaden and enhance the quantity and quality of RPS bids and improve the contracting process. (See, for example, D.05-07-039, p. 15; D.06-05-039, p. 14.) We continue to do so here by providing additional guidance, taking limited actions to further expand opportunities, and adopting a schedule to organize the process for 2007.
We do this based on relatively limited comments from parties on the IOU's proposed 2007 Plans. Parties generally do not recommend extensive changes in proposed Plans. In fact, CalWEA states that: "the utilities' 2007 procurement plans and solicitation documents reflect incremental improvement over prior years' materials." (Comments, p. 1.) Nonetheless, three parties raise several concerns, and we note others, which we address below.
At the same time, we reaffirm that each RPS-obligated retail seller ultimately has the duty to take all reasonable actions to meet the state's RPS goals. Our responsibility includes reviewing the results of solicitations, and accepting or rejecting proposed contracts submitted for approval, based on consistency with approved Plans. (§ 399.14(d).) The Plans approved herein will be a fundamental, but not necessarily the only, part of that review, as described in prior decisions, including D.06-05-039, and also below.
Moreover, while we review each Plan, our conditional acceptance is based on the fact that we have neither written each Plan, dictated with precise detail the specific language on each page of each Plan, nor do we take over procurement. These remain IOU Plans, subject to our guidance along with limited, focused and specific direction. The procurement duties remain those of each IOU. The IOU is ultimately responsible for proposing and obtaining approval of reasonable Plans, and achieving successful procurement under the RPS Program.
In this context, we address the following ten issues common to all plans in the noted sections below:
· 4.1: credit requirements and collateral pool
· 4.2: utility-owned projects
· 4.3: financial disclosures, rate adjustments and change in law
· 4.4. waivers and disclaimers
· 4.5: scheduling coordinator
· 4.6: evaluation criteria
· 4.7: changes pursuant to SB 107
· 4.8: Commission review process
· 4.9: Other changes to model contracts
· 4.10: RPS data
4.1. Credit Requirements and Collateral Pool
At least three types of deposits or collateral may be sought by IOUs: with a bid, during project development, and during commercial operation. We addressed bid deposits in our consideration of the 2005 Plans. (D.05-07-039.) At that time, we had limited information and concluded we should not interfere with IOU's judgment, but urged parties to bring us more evidence, as needed.
In our consideration of the 2006 Plans, we summarized and addressed bid deposits and other collateral requirements (e.g., commercial operation security, performance assurance deposits). (D.06-05-039.) No party presented new information there, but we made several observations and encouraged IOUs to reconsider various amounts and conditions related to deposits and collateral. We also stated we would take the reasonableness and level of bid deposits into account should an electrical corporation later seek reduction or waiver of a non-compliance penalty, with the burden of the showing on the electrical corporation.
4.1.2. PG&E Proposal
PG&E now proposes to reduce a portion of its Project Development Security for as-available, baseload and peaking (but not dispatchable) products.7 This, for example, reduces the Project Development Security by as much as half (from $20/kW to $10/kW).
No party opposes PG&E's proposal to reduce a portion of its Project Development Security. We accept PG&E's proposal.
PG&E's proposed 2007 Delivery Term Security (from the commercial operation date through conclusion of the contract) remains the same as in the 2006 Solicitation. It is an increasing amount as a function of months of revenue for increasing contract length.
CalWEA contends that all three IOUs seek an excessive amount of credit during project operations. CalWEA believes no independent financial performance assurance is needed once a project has achieved commercial operation. If, however, IOUs "want at least some `skin in the game' from developers," then CalWEA recommends an amount equal to no more than two months' projected project revenue. (Comments, p. 2.) We decline to adopt this recommendation.
PG&E's proposed Delivery Term Security is 5% of the total revenues of the project (e.g., six months' revenue for a 10-year contract; 12 months' revenue for a 20-year contract). CalWEA proposes the commercial operation security be no more than 1.7% of total revenues over the contract life (e.g., two months for a 10-year contract). In support, CalWEA asserts that the 5% collateral requirement results in the IOUs being "over-insured" at the ratepayers' expense. Despite our request for evidence related to problems, if any, CalWEA provides no data in support. We are not persuaded to reduce the amount here, as recommended by CalWEA, particularly in light of the observations we discuss further below.
4.1.3. SCE Proposal
At SCE's option, SCE may select one of the following amounts for the collateral obligation during operation (called Performance Assurance by SCE): (a) zero dollars, (b) six months of contract payments based on maximum contract capacity or (c) 12 months of contract payments based on maximum contract capacity. (SCE 2007 Procurement Protocol, Appendix 2A, p. 24.8) Since one option is zero, in the case of SCE this appears to address CalWEA's proposal to require two months or less.
Further, however, we note that SCE proposes each seller submit three contract prices, one each for the three Performance Assurance amounts. This may permit CalWEA (or another party) to collect information on the amount of "insurance" built into the contract price for each Performance Assurance. Absent credible information, however we decline to conclude whether or not the IOU's proposed operating collateral requirements under-insure, properly insure, or over-insure ratepayers or others.
SDG&E does not propose any changes in its credit requirements during project operation. For the reasons discussed below, we are not persuaded to adopt CalWEA's comments relative to SDG&E.
Thus, generally for the 2005 and 2006 Plans we had, and for the 2007 Plans we have, an inadequate record to order further modifications. Nonetheless, as we did before, we make several observations.
First, we continue to encourage IOUs to reconsider all deposit and collateral amounts and policies. To the fullest extent reasonable, IOUs must propose amounts and policies that reach a proper balance between all competing interests, such as the desire to stimulate the RPS market; the interests of ratepayers and the state in having viable projects bid, develop and operate in a reasonable, reliable and safe manner; and a reasonable balance of risks between all parties. Moreover, these amounts and policies might not be static, but may change over time with changing conditions.
Second, we repeat that we will take deposit and collateral requirements into account should an electrical corporation later seek to avoid an RPS Program non-compliance penalty. Because we provide IOUs reasonable flexibility here, an IOU later seeking deferral or waiver of a penalty has the burden to present a showing in support of that request. The showing must include evidence that its deposit requirements were at least as reasonable as those of PG&E, and did not prevent otherwise viable projects from coming forward at least for evaluation. (See D.06-05-039, mimeo., p. 38.)
Third, we are generally persuaded by PG&E and SCE that deposits and collateral have some role in ensuring projects are proposed, developed and operated in a manner consistent with the RPS program and signed contracts. In particular, operating collateral provides a project developer with a financial incentive to continue to perform under the contract. This can be important if then current market prices for electricity several years into the term of a contract are at that time above the contract price. The developer would otherwise have an incentive at that time to default on the contract. As SCE says:
RPS contracts "are typically 10 to 20 years in length. Neither party is able to predict what is going to happen during the term of these agreements; however the buyer generally pays a fixed levelized price over the term of the contract. Thus, IOUs must have some remedy to protect customers from renewable generators attempting to terminate a PPA when market prices are to the customers' advantage (typically the latter half of the term of the agreement due to levelized pricing structure)... A credit assurance of two months' revenue is insufficient to provide that assurance." (SCE Reply Comments, p. 2.)
Risk and risk-sharing are a function of several elements of the contract. These elements include the price level and the price structure (e.g., whether nominal prices are levelized using a real or nominal carrying charge rate; whether subject to some form of periodic adjustment to market or an index). They also include contract provisions for default, performance requirements, termination payments, and other remedies. (For example, see PG&E 2007 proposed Solicitation Protocol, Attachment G, Form of Power Purchase and Sale Agreement, Article 5.) Risks and remedies may also depend upon whether the default is voluntary or involuntary.
We may address the issue of deposits and collateral again when we give further consideration to risk-sharing as one of the seven policy issues upon which parties have commented. (See August 21, 2006 Scoping Memo, Attachment A, Issue 2.) In relationship to proposed 2007 Plans, however, no party presents sufficient information regarding the most equitable and efficient package of contract elements to justify modification from the proposals of the IOUs.
Finally, we again urge parties to bring evidence of problems with deposits and collateral, if any, to our attention. Parties should also continue to present information on the equitable and efficient package of contract elements to address risk and risk-sharing concerns. Absent a persuasive showing otherwise, however, we are likely to allow IOUs reasonable flexibility here. For example, absent compelling evidence otherwise, operating collateral of 5% does not appear unreasonable. Nonetheless, the burden is on IOUs to meet RPS Program targets, including 20% by 2010. We provide IOUs reasonable latitude in determining how they wish to reach the goal but will hold IOUs to successfully reaching that target (within flexible compliance rules).
4.1.6. Collateral Pool
PG&E recommends further exploration of a promising topic: a risk (or collateral) pool. According to PG&E, such pool could be a means of reducing costs and burdens of credit requirements for all renewable counterparties. PG&E says the Commission could set an aggregate number for collateral to protect against potential credit losses experienced by the pool. PG&E explains that each pool member would post collateral (or a guarantee) to cover an allocated portion of the aggregate requirement, and collateral held in the pool would be used to mitigate losses, if any.
PG&E's general concept has merit. Beyond simply endorsing PG&E's suggestion of seeking more information, however, the concept is not sufficiently developed to adopt and implement here.
Nonetheless, as noted above, SCE's requirement for all bidders to state three prices based on the amount of Performance Assurance likely supports the assertion that bidders seek recovery of collateral in prices. At least in theory, pooling of risk might be a less costly and more efficient method to address this issue. Several questions must be considered, however, before any proposal is adopted. Is there a role for government in establishing a framework in which private industry may provide this product? Alternatively, should this be a government-sponsored pool? Should participation by RPS generators be voluntary or mandatory? Should some portion of the authorized price for RPS energy be used to fund such a pool? Should public interest funds (e.g., SEPs) be set aside for this purpose, for the benefit of the entire program? What losses would be eligible for recovery from the pool? What criteria would be used for disbursing payments from the pool? Are there equity and efficiency gains by individual contract prices "internalizing" collateral requirements rather than incurring administrative and legal complications related to establishing a pool?
We will not direct respondents to develop a proposal. Nonetheless, we encourage respondents and/or parties to consider the subject and make a concrete proposal for our consideration here or in the long-term procurement plan proceeding (Rulemaking (R.) 06-02-013) if one or more parties believe it has merit.
4.2. Utility-Owned Projects
CalWEA renews its objection to counting energy from utility-owned renewable facilities toward meeting RPS goals. In support, CalWEA says competitive activities by IOUs may chill development by independent power producers, and discredit the RPS program due to concerns with utility gaming of the market. CalWEA says IOUs should not be encouraged to pursue direct ownership until completion of a public comment process. We disagree.
4.2.1. IOUs Should Consider Building
We addressed the matter last year in our review of the 2006 RPS Plans. CalWEA's repetition of an earlier comment does not convince us to alter course. Our prior statement remains succinct and clear. We adopt it again:
"We intend to enforce the 20% by 2010 requirement. In doing so, we will take into account whether or not each electrical corporation undertook all reasonable actions to comply. One of those actions is building, then owning and operating, the resource itself. Utility construction of generation resources, of course, must be fully consistent with all Commission procurement rules (e.g., all-source solicitations; see D.04-12-048). We do not here require utilities to build resources. We only observe that the option should be considered.
The burden is on the electrical corporation to comply with the RPS program, subject to certain compliance flexibility. Compliance must be met, subject to compliance flexibility and absent valid reasons otherwise. By adopting the amended Plans herein, we point out that the absence of discussion in the 2006 Plans about a utility building, owning and operating the renewable resource does not excuse an IOU from compliance on the basis that it did not build the plant itself, absent a valid reason otherwise.
Finally, we point out that a utility may build a renewable resource and, under appropriate circumstances, earn between 0.5% and 1.0% increased rate of return on that investment. (§ 454.3.) That is, the Legislature has authorized an increased incentive for utility ownership of renewable generation. We think IOUs should consider taking advantage of this law and, where reasonable and appropriate, we will authorize the increased rate of return." (D.06-05-039, p. 34.)
We are pleased to see PG&E include an item in its proposed 2007 RPS Protocol for solicitation of "sites for development." (PG&E Draft Solicitation Protocol, p. 9.) Through this item PG&E seeks offers for new or existing sites to "be acquired by PG&E for the development, construction, and operation of an ERR [eligible renewable energy resource]." (Id., p. 9.) We accept PG&E's proposal.9 We encourage (but do not order) SCE and SDG&E to adopt a similar item.10
We share DRA's concern, however, that IOUs may not be doing enough to consider building their own renewable resources. To explore the issue, the assigned Commissioner directed each IOU to include in its proposed 2007 Plan a "showing on [its] current consideration of whether or not to build its own renewable generation to reach 20% by 2010 (D.06-05-039, pp. 33-34)." (August 21, 2006 Scoping Memo, Attachment C, p. 2.) PG&E and SDG&E report that they are considering the option, but the showings are limited and without many specifics. We expect more.
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.
4.2.2. SCE's Concern about Asymmetric Rate Treatment
SCE states that a major obstacle exists in its pursuing the possibility of building its own RPS generation. According to SCE, the Commission in D.04-12-048 established an asymmetric cost sharing mechanism for utility construction of new generating resources. In particular, the Commission determined that 100% of actual utility construction cost above a utility bid-price must be paid by utility shareholders, but 50% of any savings below the utility bid-price is shared with ratepayers. SCE reports that its request for rehearing has been granted in part, and that until the 50/50 sharing mechanism is reheard SCE "is practically prevented from pursuing utility built renewable generation." (Reply Comments, p. 16.)
To the contrary, the Commission routinely balances competing interests in making its decisions. We have balanced various interests and determined that the proper balance here is 100% shareholder funding of overages, and 50/50 sharing of savings. Unless changed on rehearing, this is the Commission's decision.
We encourage SCE not to assume it is immune from a possible non-compliance penalty simply because it disagrees with the Commission here. Rather, SCE retains the burden to show that its decision not to build, if any, is reasonable. Absent compelling reasons otherwise, we are unlikely to agree with SCE that the asymmetric treatment alone would justify SCE deciding not to build RPS resources.
We are pleased, however, that SCE also reports that it has begun development of new generation studies, as funded via its general rate case (GRC) decision, D.06-05-016. Regarding renewables, SCE states it began a study in the third quarter of 2006 and expects initial results by the second quarter of 2007. SCE concludes that, should SCE determine that there is a cost-effective renewable resource that it could propose to benefit its customers, SCE would likely "pursue the development of this resource assuming a successful resolution of the asymmetric risk issue." (Reply Comments, p. 16.) We encourage SCE to consider building RPS resources independently of how the issue is resolved. Moreover, SCE is encouraged, as are the other IOUs, to take into consideration the possibility of up to an extra 1% rate of return on such investment as additional incentive to help achieve the state's renewable resource goals.
4.3. Financial Disclosures, Rate Adjustments,
and Change in Law
Four related issues arise relative to financial disclosures.
4.3.1. Disclosures Pursuant to FIN 46(R)
Each IOU's proposed RPS Plan requires access to seller's financial statements for possible consolidation.11 SCE and SDG&E relate this to FIN 46(R).
CalWEA objects, arguing that developers consider much of the information proprietary. Further, CalWEA says it knows of no requirement that a utility consolidate its financials with that of a developer, and that SDG&E reports no consolidations to date.
SDG&E correctly responds, however, that the IOU has no choice in the matter to the extent consolidation turns out to be required pursuant to FIN 46(R). Therefore, it is reasonable to adopt a term that requires certain disclosures, when required.
If this term must be included, CalWEA says it does not object to a carefully tailored contract provision, but there should be no requirement that the developer agree to open its books to the utility as a condition of participating in the solicitation. We concur. We will not require disclosure as a condition of submitting a bid. In fact, PG&E proposes to clarify its solicitation to require disclosure as part of the contract negotiation process, not during the evaluation of bids. (PG&E Reply Comments, p. 6.) We adopt PG&E's clarification. That is, disclosure shall be required, if at all, no sooner than after the project is on an IOU's shortlist. We adopt this provision for all three IOUs.
Finally, regarding the specific language, CalWEA does not propose an alternative "carefully tailored contract provision" for our consideration.12 Each IOU's proposed Plan, however, contains a provision that appears reasonable. That is, while the wording of each IOU Plan is different, each essentially states that if the IOU determines that consolidation is required, the seller must provide access to financial information.
Thus, we require the Plans to be amended so that disclosure is not required before creation of the shortlist, but otherwise adopt the language proposed by each IOU. If a dispute regarding FIN 46(R) arises after the contract is signed, parties may employ dispute resolution protocols generally contained in model contracts.13
4.3.2. Project-Specific Information
We note that IOUs require substantial project-specific information with bids.14 We agree with CalWEA, however, that information at such level of detail would normally be considered proprietary. While IOU's commit to keeping the information confidential, it is not entirely clear that IOUs need this much information to reasonably evaluate a project. If of limited usefulness or unneeded, perhaps the level of detail can be reduced, or the requirement eliminated.
For example, we note above that SCE is right when it says "neither party is able to predict what is going to happen during the term of these agreements." (SCE Reply Comments, page 2.) Projections are just that. An IOU has no inherently better ability to predict the future than a developer, a bank, the federal government, the California Energy Commission (CEC) or the Commission.
The IOU's interest in detailed project-specific financial information may go beyond an independent assessment of project viability. It may also be relevant in potentially negotiating a lower price on behalf of ratepayers, probably to be used during the "contract negotiation process" after the project is on the short list. In this context, this level of financial disclosure seemingly makes the IOU and its ratepayers more like a "partner" than a disinterested, competitive "buyer."
Nonetheless, the vitally important public health and safety aspects of safe and reliable electricity generation at every instant, and over the decades, require a close relationship between buyer and seller. Whether or not intentional, the financial health of both buyer and seller become important. This may require a substantial degree of project-specific financial information at the beginning of the relationship, and over time.
We also note above the role of credit and collateral in sharing risk between the IOU, developer and ratepayers. Risk sharing is an important element of the hybrid electricity market. We encourage IOUs and parties to continue to consider the issue and present creative ideas. We decline to direct IOUs to modify their Plans to require less project-specific financial information with the developer's bid. Nonetheless, we encourage IOUs and parties to rethink what exactly is needed, particularly in the context of sharing risk over the term of the agreement, and make proposals as appropriate for our consideration.
4.3.3. Rate Adjustments
SDG&E's 2007 proposed Plan notes that beyond the direct costs of the purchased power there are at least two other costs with RPS contracts. These are costs resulting from debt equivalence and FIN 46(R) requirements.15 To the extent that individually executed PPAs will impact SDG&E's capital structure, SDG&E proposes that SDG&E be permitted to seek relief in its Commission advice letter filing for approval of each PPA. (SDG&E 2007 Proposed Plan, p. 20.)
SDG&E's proposal to seek relief by an advice letter is rejected. Advice letters are intended to be used primarily for compliance filings. A change in capital structure, or other cost recovery due to debt equivalence or FIN 46(R), is beyond a simple compliance filing. Nor does SDG&E propose a formula, for example, and none is litigated and resolved here, to account for these effects in a way that might be easily executed upon the filing of an advice letter.
Moreover, TURN correctly argues that SDG&E's approach is inconsistent with past Commission orders. We ordered that "IOUs shall justify the debt equivalence factors for PPAs on a case-by-case basis in their cost of capital proceedings." (D.04-12-048, Ordering Paragraph 23.) We did this because debt equivalence might require the infusion of more equity in the capital structure, for example. This is best assessed in a cost of capital proceeding. This is also true for FIN 46(R), since a consolidated financial statement might affect an IOU's credit profile (e.g., increasing its risk) and resulting cost of equity. It is not a matter than can easily be handled by advice letter (at least unless and until one or more parties propose a streamlined, simplified method to do so). SDG&E does not convincingly show otherwise.16
SDG&E argues that TURN fails to account for the harm that will occur if the matter is deferred to cost of capital proceedings. SDG&E says that the ratemaking relief related to FIN 46(R) "must be addressed immediately." (Reply Comments, p. 10.) Moreover, SDG&E asserts:
"prudent corporate planning dictates that SDG&E obtain certainty and clear direction at the time it signs contracts that may have negative impacts on creditworthiness regarding the ratemaking relief available to mitigate such impacts." (Id.)
We appreciate SDG&E presenting an issue that may need resolution, and doing so in a timely way, consistent with our expectations for IOUs to do so. (D.06-05-039, pp. 19-20.) SDG&E, however, presents insufficient support for its proposal, and its claim of urgency, to convince us at this time to adopt its proposed relief. Regarding urgency, for example, it is uncertain that any consolidation of financial statements will be required under FIN 46(R) at all. Even if required, the possible size of the effect is unknown (e.g., change in capital structure of no measurable effect, 0.1%, 1.0%, other). Nonetheless, when assessing RPS bids, SDG&E may rely on the fact that ratemaking relief, if any, is available via cost of capital or other applicable proceeding, but not at this time via advice letter.
4.3.4. Change in Law
SDG&E reports that the accounting industry is still considering the relevance of FIN 46(R) in the renewables context, and application of FIN 46(R) is being finalized. (SDG&E Reply Comments, pp. 8 and 10.) CalWEA notes that there may be ongoing changes in accounting rules. (CalWEA Comments, p. 3.)
More generally, at any time over the life of a contract there may be new or revised laws, regulations or rules which affect terms and conditions under the contract. Proposed model contracts would apparently contemplate parties handling such changes pursuant to dispute resolution procedures (including provisions for mediation and arbitration). It may be useful for IOUs to consider addressing such situations directly in model contracts.
For example, we encourage IOUs and parties to examine the change of law provisions in recently approved telecommunications interconnection agreements. One such example is included in Appendix C. The approach used in the telecommunications industry may assist parties in the electricity industry and, if so, IOUs and/or parties may make specific proposals for the next RPS proposed Plans (i.e., 2008 model contracts).
We clarify one point in this regard. Substantive changes to contracts must be brought to the Commission's attention. That is, "CPUC approval" requires that a contract contain a term subjecting the contract to continuing Commission review of the buyer's administration of the agreement. (D.04-06-014, Appendix A, page A-1.) It is extremely unlikely that the Commission would find a buyer's administration of the agreement to be reasonable if parties materially change the terms and conditions of the agreement but do not bring this to the attention of the Commission. Therefore, we make clear that the IOU must bring substantive changes in any RPS contract to the Commission's attention.
4.4. Waivers and Disclaimers
In conditionally approving the 2006 Plans, we noted that each IOU's Plan contained many disclaimers allowing it to reject offers or terminate solicitations. (D.06-05-039, p. 49.) We declined to limit these disclaimers, but reminded IOUs that they must reach the RPS goal of 20% by 2010 (with appropriate application of flexible compliance rules). We encouraged IOUs to rethink the tone and nature of their disclaimers.
In response, PG&E proposes to remove language that would require bidders to waive any state or federal constitutional right as a condition of participating in the solicitation. This is an improvement. Nonetheless, PG&E proposes retaining language that requires the bidder, with limited exception, to waive "any rights under statute, regulation or common law to assert any claim or complaint or other challenge in any regulatory, judicial or other forum..." (2007 Solicitation Protocol, Section VII, p. 42.) CalWEA asserts PG&E's waivers remain over-reaching and should be eliminated. CalWEA asserts neither SCE nor SDG&E propose such offensive requirements.
We again decline to eliminate such broad language. We remind PG&E, SCE and SDG&E that the latitude provided here may not be used as an excuse for failing to meet the RPS Program goals. We may deal with this again in a subsequent decision on various policy issues. Below, we deal more specifically with PG&E's proposed language regarding relief bidders may seek at the Commission.
4.5. Scheduling Coordinator
SCE proposes to perform SC services. (SCE Bid Solicitation Documents, Attachment 2C, 2007 Pro Forma Agreement, Section 3.11, pp. 32-33.) In response, CalWEA asserts all IOUs should serve as SCs.
We decline to order each IOU to do so. PG&E correctly states that each renewable facility operator is best suited to understand, communicate, and manage both its expected and actual operations. As such, the operator may elect to be its own SC, or may use a scheduling agent. Moreover, the CAISO has initiated the Participating Intermittent Resource Program (PIRP) to address concerns regarding SC responsibilities for intermittent resources, according to PG&E. We have no information persuading us that facilities are having undue burden performing this service themselves, finding SC services elsewhere, or participating in the PIRP. Thus, we are not convinced that each IOU should be ordered to offer SC services.
We accept SCE's proposal to perform SC duties with one modification. SCE's offer includes language that makes it mandatory: "At least thirty (30) days prior to Initial Synchronization, Seller shall take all actions ... necessary to authorize ... SCE as Seller's Scheduling Coordinator ... throughout the Term of this Agreement." (Id., Section 3.11(a)(i).) We welcome SCE's offer to provide SC services, but do not believe it should be mandatory. As PG&E contends, generators are typically in the best position to schedule their performance. If they choose to do so, this should be permitted. SCE should amend its Plan to make clear its SC services are optional, not mandatory.17
Lastly, SCE proposes that operators take the risk of incurring certain penalties related to operations outside an established bandwidth. CalWEA contends that this imposes the risk of deviations outside a narrow bandwidth back on developers. CalWEA argues that IOUs should manage deviations with respect to RPS resources, and delivery forecasts from RPS generators should be in good faith, but not binding.
We are not convinced. SCE correctly states that if the RPS generator provides accurate and timely information, no CAISO deviation charges are assessed. Only if forecasts are incorrect or untimely, or outside established bandwidths, is a charge made. This reasonably places the burden where it belongs, since the RPS operator is in the best position to forecast and manage its operations. Inaccurate forecasting and scheduling can lead to excessive burden on operators in real-time. SCE's proposal to charge for deviations outside an established bandwidth provides an appropriate incentive for the RPS facility to forecast and operate reasonably, while allowing SCE to offer a useful SC service without itself incurring all the risk for deviations.
4.6. Evaluation Criteria
We have required since the beginning of the program that each IOU Plan have a clear and concise statement of the evaluation criteria used in assessing bids. The statement must contain all criteria, including the benefits of the RPS program identified by both the Legislature and the Commission. It must encourage bidders to address such benefits, if any. This permits a bidder to know how its bid will be assessed, helps a project focus its bid on the factors to be judged, and promotes a reasonably fair, transparent and open process. (See D.03-06-071, p. 37; D.04-07-029, p. 28, Finding of Fact (FOF) 27 and 28; D.06-05-039, pp. 50-53, Conclusion of Law 3.)
We found in reviewing the 2006 Plans that each IOU could do a better job. We directed that each IOU amend its Plan to do so. The results varied.
PG&E improved its 2006 Protocol, for example, expanding on its old Section XI.D by including a new Section XI.E. The new section more fully identified non-quantifiable factors and requested bidders to address the factors, if applicable.
SCE improved the "Evaluation of Proposals" section within its 2006 Procurement Protocol by including more items in its quantifiable attributes, plus more description of those attributes. We specifically directed SCE to make a particular decision reference clear, and SCE did so. Also, however, we said: "SCE must state each...qualitative criterion and solicit bidders to address such benefits, if any, within these criteria." (D.06-05-039, p. 51, footnote 19.) SCE failed to include all the qualitative factors from the referenced decision, and failed to solicit bidders to address such benefits, if any. SDG&E similarly made some improvements.
The language in each IOU's proposed 2007 Plan is still not adequately clear, comprehensive, explanatory, inclusive, and concise. For example, PG&E proposes to eliminate Section XI.E. This leaves essentially no discussion of qualitative factors, and no solicitation of bidders to address these factors.18 SCE's proposed language continues in its failure to address all qualitative factors and solicit bidders to address such benefits. IOUs can continue to improve these sections.
Each IOU was directed to submit a preliminary Evaluation Criteria and Selection Process Report on September 29, 2006.19 A workshop on transparency of the RPS procurement process, including evaluation criteria, was held on December 15, 2006. The first reports from PG&E and SCE were filed on December 21, 2006 along with short lists.
Work continues in this area, and it continues to deserve this work. Each IOU can do a better job clearly explaining its evaluation criteria and selection process. Each must do so in its amended 2007 Plan.
Thus, as we also said last year, each IOU should amend its Plan to do a better job of clearly and specifically stating each factor used in its evaluation. These include factors found and declared important by the Legislature, and discussed in Commission decisions. Each Plan must specifically invite bidders to address such factors and related benefits, if any. We also encourage each IOU to again review the body of RPS decisions, beginning with D.03-06-071, to help it prepare a clear and concise statement of the evaluation criteria used to assess bids, including all quantitative and qualitative factors, plus our direction to encourage bidders to address particular benefits, if any.
Finally, it seems unlikely that the evaluation criteria and selection processes at the three IOUs are so uniquely different that they merit three different approaches and descriptions. We encourage the three IOUs to meet and consider drafting one section that each may use in its Plan. This does not preclude each having, in part, some uniquely different language to reflect limited differences at each company. Nonetheless, we think one largely similar form, format and description may improve the overall approach to the subject. IOUs should work with Energy Division on the continuing development of this item.
4.7. Changes Pursuant to SB 107
Parties were asked to address changes that might be required in each IOU's draft 2007 Plan due to the passage of SB 107, effective January 1, 2007. In particular, parties were asked to address four items: (a) RECs, (b) agreement information, (c) access to bid information, and (d) other. PG&E also raises a concern relative to timing, which we address below.
We adopted a limited number of standard terms and conditions for RPS contracts in 2004. One such term involved the definition and ownership of RECs. (D.04-06-014, Appendix A, pp. A-2 to A-3.)
SB 107 now adopts a specific meaning for RECs. Moreover, SB 107 requires that contracts for the purchase of electricity generated by an eligible renewable energy resource include the REC associated with all generation under the contract. IOUs propose four changes to their draft Plans relative to RECs and their treatment under SB 107.
First, each IOU proposes adding a definition of REC in the appropriate part of its model contract. The proposals vary, but each essentially refers to, or quotes, new § 399.12(g) from SB 107. There is no opposition to adding a definition of REC.
To promote consistency, we adopt PG&E's proposal for all three IOUs. PG&E's proposal is succinct, while also being robust in the face of potential change. We direct each IOU to use this definition20 in the appropriate part of its model contract:
" `Renewable Energy Credit' has the meaning set forth in Public Utilities Code Section 399.12(g), as may be amended from time to time or as further defined or supplemented by Law."
SB 107 also requires that the contract include the RECs associated with the RPS energy. Little more is needed, however, since this provision is already required via D.04-06-014. That is, it is part of the non-modifiable term used for the definition and ownership of RECs (requiring that the seller convey all Environmental Attributes to the buyer). SCE proposes some additional language to ensure conformance with SB 107. SCE's proposal is adopted for SCE.
Second, PG&E proposes inclusion of some additional items in the list of pollutants, consistent with concepts embodied in Assembly Bill (AB) 32. There is no opposition. PG&E's proposal is adopted, as cited more fully below under Green Attributes.
Third, D.04-06-014 adopted the term "Environmental Attributes" to address the definition and ownership of RECs. PG&E and SDG&E now propose that this language be amended to refer to RECs. Their proposals differ slightly. We adopt PG&E's proposal as more encompassing. We direct that all three IOUs adopt the new term cited more fully below under Green Attributes.
Finally regarding RECs, PG&E and SDG&E propose that the term "Environmental Attributes" be changed to "Green Attributes." In support, they assert that the Commission's definition of "Environmental Attributes" (capitalized in D.04-06-014 and in model contracts) includes RECs, but that SB 107, in establishing the statutory definition of RECs, provides that RECs include all "environmental attributes" (not capitalized). As a result, they point out that confusion is possible since Environmental Attributes in D.04-06-014 incorporate RECs, while environmental attributes pursuant to SB 107 are only one aspect of RECs. As a result, SDG&E and PG&E agree that the potential for confusion caused by the juxtaposition of these terms may, and should, be mitigated, and they propose modifying the Commission's term.
We agree. Our original term for the definition and ownership of RECs included the term "Green Tags." Thus, the proposal of PG&E and SDG&E to use "Green Attributes" is reasonably parallel to a term with which parties are already familiar without causing confusion. In adopting the original term, we said "we expect that the contract language will become more refined as the parties and the Commission gain further experience." (D.04-06-014, p. 6.) We think that is the case here.
Central California Power (CCP) argues against the change, saying SB 107 did not create any potential for confusion. We disagree. While the change from "Environmental Attributes" to "Green Attributes" is not strictly required, we agree with PG&E and SDG&E that the likelihood of confusion is easily avoided by adopting their proposed change. The change does not alter the original concept behind use of the term "Environmental Attributes," nor, contrary to CCP's concerns, does it create any conflict with SB 107.
Thus, we replace the non-modifiable term adopted in D.04-06-014 for "Environmental Attributes" with the non-modifiable term "Green Attributes." We similarly conform Section 3.4 of the standard term and condition for RECs (as recommended by GPI in comments on the proposed decision). (See D.04-06-014, Appendix A, pp. A-2 to A-3.)
We decline to add "any other tradable rights" as proposed by PG&E for a fifth item in the list of what is an environmental (green) attribute. The list is already characterized as "include[s] but not limited to." Nonetheless, it is unreasonable to add a term as undefined and open-ended as "any other tradable right," particularly since it may cause unintended disputes with regard to taking of property rights. We saw no need for language this broad in 2004, and similarly see no need today. Finally, we combine PG&E's proposed fourth term with the third term, as recommended by GPI.
As a result, the non-modifiable term will be as follows. To more easily identify the language changed from that adopted in D.04-06-014, the changes21 are in bold:
" `Green Attributes' means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its displacement of conventional Energy generation. Green Attributes include but are not limited to: (1) any avoided emissions of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants; (2) any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth's climate by trapping heat in the atmosphere; (3) the reporting rights to these avoided emissions such as Green Tag Reporting Rights and Renewable Energy Credits. Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser's discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of Energy. Green Attributes do not include (i) any energy, capacity, reliability or other power attributes from the Project, (ii) production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the project that are applicable to a state or federal income taxation obligation, (iii) fuel-related subsidies or "tipping fees" that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or (iv) emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits. If the Project is a biomass or landfill gas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project."
"3.4 Green Attributes. Seller hereby provides and conveys all Green Attributes from the Unit(s) to Buyer as part of the Product being delivered, as such term is described in the applicable Transaction confirmation for the period set forth in such confirmation. Seller represents and warrants that Seller holds the rights to all Green Attributes from the Unit(s), and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Unit(s)."
4.7.2. Agreement Information
The second general area dealing with possible updates due to SB 107 involves disclosure of certain project information. In particular, SB 107 requires:
"The standard terms and conditions shall include the requirement that, no later than six months after the commission's approval of an electricity purchase agreement entered into pursuant to this article, the following information about the agreement shall be disclosed by the commission: party names, resource type, project location, and project capacity." (SB 107, § 399.14(a)(2)(D).)
SCE reports that its pro forma agreement already provides for release of this information. Thus, no modification is necessary.
PG&E and SDG&E each have contract language which permits release of the information consistent with requirements of SB 107. Each, however, also includes a sentence which in substance provides: "If Option B is checked on the Cover Sheet, neither Party shall disclose party name or project location, pursuant to this section, until six (6) months after such CPUC Approval."22
PG&E points out that this last sentence is not fully consistent with the SB 107 time period. PG&E proposes deleting the sentence, as well as updating the solicitation Cover Sheets to remove reference to Option B. We agree, and direct SDG&E to do the same.
Finally, SDG&E proposes that "online date and delivery point" be included in the list of disclosable terms for consistency with D.06-06-066. No party comments or objects. We adopt SDG&E's proposal. To the extent not already included, each IOU shall modify its list to also include online date and delivery point. It should also include "expected deliveries (energy)" and "length of contract," consistent with our recent decision regarding SB 1488. (D.06-06-066, Appendix 1, pp. 16-17, Items F and G.)
4.7.3. Access to Bid Information
The third general area dealing with possible updates due to SB 107 involves access to bid information. In particular, the original RPS legislation required that the Commission adopt a process for determining market prices. It required that the Commission make specific determinations of market prices after the closing date of a competitive solicitation. It also required that an electrical corporation not transmit or share the results of a competitive solicitation until the Commission had established market prices. (§ 399.14(a)(2)(A).) Effective January 1, 2007, the restriction on an electrical corporation transmitting or sharing the results before the Commission has established market prices is lifted. (SB 107, § 399.14(a)(2).) This may cause changes in the IOUs' Plans and Commission procedures.
Parties were asked to identify any necessary changes in their proposed 2007 Plans to conform to the lifting of this restriction. Each IOU reports that its proposed Plan is consistent with this provision in SB 107 and no changes are necessary.
Consistent with the original legislation, earlier Commission orders had adopted procedures whereby Commission staff would not see the results of the RPS solicitation until after the Commission had adopted the market price referent (MPR) resolution.23 We lift this restriction effective January 1, 2007. For example, the schedule we adopt below no longer contains procedures limiting staff access to bid information before calculation of the MPR, and none shall be applied going forward. Moreover, effective January 1, 2007, we make clear that there shall be no limitation on an electrical corporation transmitting or sharing the results of any competitive solicitation for eligible renewable energy resources with the Commission.
The last area involves parties identifying and addressing other aspects of SB 107 that might require changes in the proposed 2007 Plans (with two specific exceptions which we will address elsewhere: (a) flexible compliance in 2010 and beyond and (b) contracts of less than 10 years' duration). In response, PG&E recommends that the Commission expressly allow consideration of certain changes to non-modifiable standard terms and conditions through the advice letter process.
For example, PG&E argues that a change in a non-modifiable term should be permitted by advice letter if the developer requires such change and provides a declaration explaining why the change is necessary for project financing or to otherwise proceed. PG&E also points out that current non-modifiable terms may conflict with changes in California law and court orders over time. While the issue deserves consideration, we decline to address it now for the following reason.
On February 1, 2007, PG&E and SCE jointly filed a petition for modification of D.04-06-014. (D.04-06-014 adopted standard terms and conditions for RPS contracts, with some designated as "may be modified by parties" and others as "may not be modified.") The petition, among other things, seeks clarification regarding how and when standard terms and conditions may be modified. We will address PG&E's recommendation when we consider the joint petition for modification.
PG&E recommends that SB 107-related changes, if any, also be applied to contracts from prior solicitations that may come to the Commission for approval after January 1, 2007. We agree, as explained below. Parties should use the previously described terms as and where applicable (e.g., for RECs, agreement information, access to bid information) for contracts that result from prior solicitations (e.g., 2004, 2005, 2006) that are presented for our consideration after January 1, 2007, where appropriate.
In comments on the proposed decision, many parties disagreed with this approach. For example, SCE states that a contract signed by parties after January 1, 2007 should include the relevant language, but the Commission should not require parties to amend a contract signed before January 1, 2007. Caithness Corporation argues that the requirement should apply only to contracts submitted 60 to 90 days after the effective date of this order so that parties have reasonable notice and opportunity to incorporate these terms.
We clarify here that contracts executed between an IOU and RPS project before January 1, 2007 should include the terms described above, but only to the extent reasonable and applicable. We do not make this a requirement. We do not direct that parties renegotiate an agreement that has already been executed. Rather, we leave that up to the judgment of the parties. On the other hand, an RPS contract executed between an IOU and a counterparty on or after the date this order is mailed should incorporate the terms described above.
4.8. Commission Review Process
The issue of considering changes to non-modifiable contract terms by advice letter raises the more general issue of how we process and consider RPS contracts. Our recent experience with advice letters, and the issues that have surfaced here, demonstrate a need to rethink our process.24
4.8.1. General Review of Contracts
With some exceptions, advice letters are typically used for compliance filings.25 They should tend to be ministerial and reasonably straightforward. They should typically not raise complex or serious factual, legal, policy or technical issues. On the other hand, applications or other formal pleadings are the vehicle for discretionary and all other matters.
We initially adopted an advice letter approach for consideration of IOU proposed RPS contracts. (D.03-06-071, p. 39.) This approach is in the context of the Commission having reviewed and accepted an IOU's RPS Procurement Plan. (§ 399.14.) The accepted Plan would contain standard terms and conditions adopted by the Commission, including performance requirements. (§ 399.14.) The Plan would contain one or more model contracts for use by parties in the solicitation. The proposed contracts would be submitted to the Commission for review after an IOU's competitive solicitation, least cost-best fit screening, and review by the Procurement Review Group. The Commission would review the results of a solicitation after this reasonably thorough process and "accept or reject proposed contracts...based on consistency with the approved renewable energy procurement plan." (Old § 399.14(c); new § 399.14(d), effective January 1, 2007.)
The adopted advice letter process contemplates a fundamentally compliance, relatively straightforward, reasonably ministerial filing. This process may or may not be feasible for contracts that do not fit these facts.
4.8.2. Continue with Current Process
To address this, the proposed decision would have had us adopt a procedural approach that differentiates the filing of RPS contracts into those to be considered by advice letter (i.e., for a "compliance" filing pursuant to a competitive bid solicitation using a model contract) or application (i.e., for filing of a contract reached outside a competitive bid solicitation and/or containing nonstandard terms and conditions that are substantively different that those in the model contract). There may be merit in using this structure to streamline and focus the efforts of parties and the Commission. If properly implemented it could facilitate reaching RPS program goals and targets sooner with less cost, plus greater efficiency and equity. Nonetheless, we decline to adopt this approach here.
While there may be benefits, there might also be costs. The application process, for example, may in some cases take more time (with potentially increased risk and cost for projects subject to delay). Nearly all, if not all, comments oppose adoption of the procedural approach framed in the proposed decision.
As a result, we maintain the status quo for now. RPS contracts may continue, consistent with existing Commission orders, to be submitted for Commission consideration by advice letter. We believe this will enable timely consideration of most, if not all, contracts.
Also consistent with existing Commission practice, Energy Division is the Commission's "gatekeeper" to screen and separate out contracts that require special attention. For example, under certain conditions Energy Division should reject an advice letter (with instructions that the applicant submit the item as an application if it wishes further consideration). Alternatively, Energy Division may seek Commission conversion on its own motion of an advice letter to an application.
The conditions under which this might be done include, but are not necessarily limited to, when: (a) an advice letter raises a potentially disputed, important, or significant issue of fact, policy or law (based on a filed protest or as identified by Energy Division); (b) the contract price exceeds the relevant MPR by a nontrivial amount; or (c) changes to modifiable or non-modifiable standard terms and conditions raise an important issue (based on a protest or as identified by Energy Division). An applicant might on its own elect to submit certain matters for Commission review and consideration by application rather than advice letter, but is not required to do so. Rather, applicants may continue to submit proposed contracts for Commission consideration by advice letter. Energy Division has the experience and responsibility, however, to continue to employ its administrative expertise to treat filed advice letters as advice letters when appropriate, but reject or convert others, as necessary and where reasonable.
4.8.3. Defense of Noncompliance Penalty
This discussion is generally with regard to process, not substantive review of submitted items. Thus, we do not repeat here what is said elsewhere in this order, nor what is said in prior orders, regarding contract review and possible penalties. We encourage parties to review this and prior orders.
Nonetheless, we address several factors above which deal with elements an entity should be able to show in any future defense relative to a non-compliance penalty, if any (e.g., reasonable credit and deposit policies and amounts, reasonableness of waiver and disclaimer language). We also note a few below (e.g., reasonableness of an entity's margin of safety in its procurement plan; SCE's failure to include high, base and low scenarios). In the interest of clarity, we point out that the comments here compliment and supplement, and do not replace or supersede, prior orders (e.g., D.06-05-039, Conclusion of Law 7, Ordering Paragraph 7.) We encourage each entity to review this and prior orders to ensure it is reasonably implementing the RPS program given the Commission's guidance.
4.9. Other Changes to Model Contracts
The proposed decision employed an approach wherein the accepted RPS Plan included a complete model contract, which in turn incorporated all standard terms and conditions from D.04-06-014. This would be the model contract. It would facilitate and enable expedited Commission consideration of subsequent conforming agreements. Consistent with this approach, the proposed decision would have had us direct SCE to amend its proposed Proforma Agreement to be consistent with all Commission adopted standard terms and conditions (both modifiable and non-modifiable) from D.04-06-014. It would then have recognized that SCE and the bidder could modify the terms permitted to be modified.
In its comments on the proposed decision, SCE argues that it should not be required to modify its Proforma Agreement. SCE says its couterparties have found some Commission non-modifiable terms (e.g., "assignment") to be unacceptable. SCE also says some standard terms do not work in the context of SCE's entire 2007 Proforma Agreement (e.g., definition of "as-available" is a remnant of the Edison Electric Institute agreement that no longer makes sense, according to SCE). SCE asserts that it would need to publicly state it would be unable to enter into its own Proforma Agreement if SCE is required to modify its Proforma Agreement to comply with the exact terms in D.04-06-014. SCE contends this would be a waste of time and resources.
It has now become apparent (through recent advice letters, applications, the petition for modification of D.04-06-014, and comments on the proposed decision by parties other than SCE) that not only SCE but also other IOUs have changed standard terms and conditions over time (both modifiable and non-modifiable). We believe this subject deserves additional consideration. SCE and others argue that continuity of the RPS Program (so that California has a reasonable opportunity to reach RPS goals) is too important to delay the 2007 solicitation. We essentially agree.
Therefore, we accept the RPS Plans proposed by the IOUs for the 2007 solicitation without requiring that they conform to the precise standard terms and conditions adopted in D.04-06-014. In doing so, we withhold judgment on parts of the Plans not addressed herein. We also reserve judgment on treatment of modifications to standard terms and conditions for our later consideration of the petition for modification of D.04-06-014. As stated above, Energy Division may at its discretion require contracts with changes to the standard terms and conditions otherwise adopted in D.04-06-014 to be filed by application.
Thus, IOUs are permitted to use their proposed Plans for their 2007 solicitation, subject to the modifications otherwise ordered herein, as summarized in Appendix A. At the same time as we have also said in other contexts, IOUs have the responsibility, within flexible compliance rules, to reasonably administer and implement the program and to meet RPS targets. This responsibility is not altered by our decision to permit IOUs to proceed on this basis with the 2007 solicitation.
4.10. RPS Data
The August 21, 2006 Scoping Memo directed each IOU to submit APT, IPT and other RPS data. In October 2006, we issued our Reporting Decision, D.06-10-050.
We here conditionally accept each IOU's 2007 Plan, subject to it being amended and refiled within 15 days. IOUs may update their Plans, as appropriate, to reflect reporting decisions in D.06-10-050. This should simplify each filing, and IOUs may make or decline to make those simplifications at this time.
7 PG&E's Project Development Security is composed of (a) $3/kilowatt (kW) for the first period (between the date the agreement is executed and a date within 30 days following CPUC approval of the agreement) and (b) $20/kW for the second period (between 30 days after CPUC approval and the project's commercial operation date). PG&E now bifurcates the deposit in the second period to (a) for dispatchable products it is $20/kW and (b) for intermittent, baseload or peaking products it is $20/kW multiplied by the greater of (i) capacity factor or (ii) 0.5.
8 SCE also says that it "will only execute Power Purchase and Supply Agreements wherein Seller posts a Performance Assurance amount that is greater than zero (0) months of contact payments." (Id.) At the same time, many terms are negotiable, and the bidder might propose that the final Performance Assurance be equal to two months of contract payments or less.
9 PG&E did not propose "sites for development" in its 2006 RPS Protocol. (Solicitation Protocol, December 22, 2005, pp. 2-5.) Rather, PG&E there included ownership Alternatives I (Power Purchase Agreement with PG&E Buyout Option) and II (Turnkey Agreement). PG&E's amended 2006 Plan, submitted based on guidance and direction in D.06-05-039, included Ownership Alternative III (Sites for Development). (Solicitation Protocol, June 16, 2006, p. 10.)
10 We generally direct in only limited ways the manner in which an IOU achieves RPS Program goals (e.g., some standard terms and conditions in contracts). Rather, within the legislative framework, adopted program structure and our guidance, it is fundamentally up to each IOU to determine how it wishes to achieve the goals. Each IOU must, for example, propose a reasonable Plan for acquiring RPS resources. We accept, modify or reject each Plan. (§ 399.14(c).) Each IOU will then be held to meeting the goals, within rules for flexible compliance.
11 See PG&E 2007 Solicitation Protocol, Section XII.B, page 41. See SCE 2007 Proforma Agreement, Appendix 2C, Article 3.22, p. 40. See SDG&E 2007 Plan, Appendix A (Proposed RFO), Section 8.0, p. 20.
12 In arbitrations of telecommunication interconnection agreements, parties are required to present specific alternative proposed language. (See Resolution ALJ-181, Rule 3.6.) The procedural framework here is not that of arbitration, but parties increase the likelihood of making a compelling case when they provide specific proposals.
13 PG&E Proposed PPA, Article 12. SCE Proposed Pro Forma Agreement, Article 12.
14 For example, PG&E requires the bidder to include projections of revenues, expenses (disaggregated into many categories), interest payments, principal repayments, and capitalization (both debt and equity). (2007 Solicitation Protocol, Attachment E.) This permits PG&E to estimate the project's return on equity and rate of return. Similarly, SCE requires applicant to include a printout of the results from SCE's Revenue Calculator. (2007 Plan, Appendix 2E, Article 4.11.)
15 According to SDG&E, long-term financial obligations, such as PPAs, are treated by credit rating agencies as additional debt. "As SDG&E executes more and more power purchase agreements, the cumulative debt equivalence of all these agreements may greatly affect SDG&E's credit profile and, consequently, its financial standing." (SDG&E 2007 Plan, p. 18.) Similarly, "FIN 46(R) will affect SDG&E's reported financial data and may have negative impact on SDG&E's balance sheet and/or credit profile." (Id., p. 20.)
16 It may be that this matter will eventually become routine and can be handled by a balancing account in a simple offset proceeding, or a formula applied with an advice letter. We do not, however, have data or experience to reach that conclusion here.
17 For example, Article One of SCE's Pro Forma Agreement contains items to be filled in by parties. An element might be added here to state whether or not SCE is the SC.
18 The organization of PG&E's Protocol could be improved. Many, if not all, the factors are listed in the "Required Information." (2007 Solicitation Protocol, Section VIII.C.) They are not listed or cross-referenced in the section titled "Evaluation of Offers." (2007 Solicitation Protocol, Section XI.)
19 These reports were ordered in D.06-05-039, pp. 44-45. The first report is due with each IOU's shortlist of bids.
20 SCE and SDG&E may also include PG&E's definition of "Law" as they determine necessary or appropriate.
21 We also adopt PG&E's proposal to change the statement that green tags are accumulated on a "kWh" basis to a "MWh" basis for internal consistency.
22 The Cover Sheet to each model contract includes options regarding confidentiality.
23 For example, see D.04-07-029, p. 10 ("PRG [Procurement Review Group] meetings, not including Commission staff, are held to review bid results") and Finding of Fact 7 on p. 41. Also see D.05-12-042, Appendix B, p. 1, and D.06-05-039, Appendix A, p. 1.
24 Section 4.8 in this decision (except for Section 4.8.3) is focused on process, not the evaluation criteria to be used when we consider any particular RPS contract.
25 Our use of advice letters continues to evolve. We recently adopted a three tier system for consideration of many advice letters. (D.07-01-024, adopted January 25, 2007.)