We address the following eight issues common to most if not all Plans:
· Exclusivity Agreement Date
· Tradable Renewable Energy Credits (TRECs)
· Standard Terms and Conditions 5 (STC 5) and 25-year Contract Term
· Network Upgrades
· TOU Factors
· Utility-Owned Generation (UOG)
· Data for 2010 Plans
5.1. Exclusivity Agreement Date
The Commission adopted a schedule for the 2008 solicitation that was limited to major milestones, thereby permitting IOUs and staff reasonable flexibility. (D.08-02-011, at 46.) The schedule included a date for each IOU to submit its shortlist to the Commission and the Procurement Review Group (PRG). The schedule did not address if and when IOUs may request or require a bidder to execute an agreement for exclusive negotiations. As the 2008 solicitation progressed, bidders of at least one utility asked for early notification of their shortlist status because they had been shortlisted by another IOU, and that IOU was requesting that the bidder agree to exclusive negotiations.
As a result of this situation, respondents and parties were asked to address the following question for the 2009 solicitation: "Should the Commission take a position on whether or not an IOU may execute exclusivity agreements with bidders prior to formal notification to all bidders?" PG&E and SDG&E encourage Commission adoption of a consistent schedule for all three utilities so that bidders will have approximately simultaneous information regarding their shortlist status before being required to agree to exclusive negotiations with only one IOU. SCE recommends the Commission focus on policy objectives and compliance requirements, letting IOUs separately decide details related to the competitive solicitation process and dates for exclusivity agreements. Sierra and PacifiCorp assert the issue does not apply to them.
In addressing this question, we first note that in 2004, the Commission adopted the following as part of the LCBF methodology:
1. All bids should be treated as potentially multiple until bids are short-listed and negotiations begin. (D.04-07-029, Ordering Paragraph 1, Finding of Fact 13.)
2. It is reasonable to require bidders that have been shortlisted to withdraw competing bids, to avoid the situation in which the utilities are negotiating against one another for the same project, potentially resulting in inflated prices. (D.04-07-027, Ordering Paragraph 1, Finding of Fact 11.)
That is, we determined that exclusivity is a reasonable requirement upon a bidder being shortlisted, but we did not establish a uniform date to trigger exclusivity. We are persuaded by PG&E and SDG&E to now adopt a uniform date before which an IOU may not request or require that a bidder execute an agreement requiring exclusive negotiation with an IOU. Experience from the 2008 solicitation shows that to do otherwise results in the need of one or more IOUs to accelerate their evaluations and notification process in order to compete for attractive RPS offers. This unreasonably places IOUs in a situation where another IOU can reduce the available time for reasonable review of all bids received by that IOU. PG&E's IE advises that it is desirable to avert premature shortlisting. We agree.
Moreover, we are persuaded by SDG&E that a non-uniform exclusivity date allows bidders to "game the system." As SDG&E argues, compressing pre-shortlist negotiations provides an opportunity for the bidder to extract concessions from an IOU in order for the IOU to obtain exclusive rights for further negotiations, raising the likelihood of a bidding war and unnecessary cost increases for ratepayers. Therefore, we adopt SDG&E's recommendation to prohibit execution of an exclusivity agreement with bidders before formal shortlist notification to all bidders.
SCE points out municipal utilities do not have the same procurement restrictions but they are formidable competitors. SCE says the option of when to execute an exclusivity agreement must be left to the IOU because IOUs are competing against many buyers, including municipal utilities.
We are not persuaded. Competition with municipal utilities was not what caused the problem in 2008. PG&E and SDG&E face the same concern as SCE but do not seek the same remedy. We adopt the recommendation of PG&E and SDG&E for the 2009 solicitation.
IOUs and parties may bring further information to our attention for consideration in the 2010 Plans. For example, at least in theory, a fully competitive market protects buyers and sellers without the need to limit competition via exclusivity agreements. Parties may wish to bring us further information on the vitality of the competition in the RPS market and, if sufficiently competitive, on the desirability of eliminating the use of exclusivity agreements altogether. Alternatively, additional experience with a uniform date between Commission-regulated entities relative to other competitors (e.g., municipal utilities) may provide useful insights into necessary changes here.
Finally, SDG&E recommends the specification of additional dates. In support, SDG&E says that prevention of inequitable pre-shortlist negotiations requires the date on which a bidder accepts its shortlist position to be (a) as close as possible in time to the shortlist notification date and (b) the same day for all IOUs.24
We decline to set a uniform number of days for a bidder to accept or reject its shortlist position, or a single such date for all IOUs. We did not specify that level detail for the 2008 Plans, and we decline to do so for 2009. We are not convinced that this level of flexibility between IOUs materially harms competition or unreasonably increases the bargaining position of any bidder. We continue to be persuaded of the need for reasonable flexibility, as argued by SCE and others. Each IOU may set its own time limit for the bidder response, as long as it is consistent with the adopted schedule for the overall solicitation.
IOUs include discussion of the use of TRECs in their 2009 Procurement Plans, generally seeking use of TRECs but conditioned on a future Commission order authorizing that use. DRA and TURN recommend that the Commission reject inclusion of the use of TRECs in these Plans. In support, DRA and TURN cite the Commission decision on the 2008 Plans. We there declined to accept SDG&E's proposal to include TRECs in its discussion of flexible compliance. We did so noting that the treatment of Renewable Energy Credits (RECs) was being addressed in R.06-02-012, and we did not want to prejudge the REC issue in the 2008 Plans. (D.08-02-008, at 18.)
Additional events have now occurred. We have adopted the final joint staff report of the CEC and this Commission on the CEC's RPS Tracking System, in which we find that the tracking system is ready to support the use of TRECs for RPS compliance.25 (Resolution E-4178, November 21, 2008.) Also, a proposed decision on the use of TRECs has been prepared, and commented upon by parties.
Although our consideration of the use of TRECs for RPS compliance is further along than it was in early 2008, it is not yet complete. It would be premature to authorize IOUs' use of TRECs (even subject to conditions) until we have actually authorized the use of TRECs for RPS compliance. That subsequent authorization, for example, may include conditions we cannot foresee here.26
The IOUs should, therefore, remove discussion from the Amended Plans to be filed pursuant to this order regarding the use of TRECs to meet RPS Program targets. If and when we authorize the use of TRECs for RPS compliance, each IOU may amend its Plan in accordance with the authorization at that time.27
5.3. STC 5 and 25-Year Contract Term
Contract length (also called contract term) is Commission-adopted STC 5. (D.08-04-009, Appendix A, at 11.) As one of our STCs, we require that each contract specifically address this item. We provide model language, including that parties may select the term by checking one of four boxes. The boxes are for a contract term of 10 years, 15 years, 20 years, or non-standard delivery over a specifically stated period of years. STC 5 is modifiable by parties.
LSA and CalWEA propose that 2009 RPS Procurement Plans include an option for bidders to select a contract term of 25 years. As proposed, IOUs would not be obligated to enter into 25-year contracts, but would be obligated to include the option, consider bids with 25-year terms, evaluate those bids using the LCBF methodology, and justify rejection of such bids to the PRG. In its response, PG&E says it does not oppose the recommendation. SCE says the recommendation should be rejected.
We decline to adopt the LSA/CalWEA proposal. While STC 5 was previously non-modifiable, parties are now free to modify STC 5 during the solicitation/negotiation process. (D.07-11-025, at 20.) We see no need to modify an already modifiable term to include a specific reference to 25 years. Rather, as written, modifiable STC 5 allows the bidder to fill in the number of years it proposes for the sale. Thus, we are not persuaded that we should change STC 5 for all model contracts.
At the same time, we note that SCE's Request for Proposals states that:
... sellers may propose a standard delivery term length of ten (10), fifteen (15) or twenty (20) years, or a non-standard delivery term that is no less than one (1) month and no longer than twenty (20) years. (Procurement Protocol, at 5.)
SDG&E's Request for Offers says a bidder shall propose a 10-, 15- or 20-year agreement; that SDG&E will accept proposed short term agreements of up to five years; and that SDG&E may (at its discretion) consider offers of other contract duration. PG&E's Solicitation Protocol says bidders may offer delivery terms as short as one month and as long as 10, 15 or 20 years, or any term that is mutually agreeable and approved by the Commission.
We know of no convincing reason why the bid request or protocol of any IOU should foreclose or discourage a bidder from submitting a bid in excess of 20 years.28 Nor should the request or protocol suggest that an IOU may decline to consider such bids. We adopt market price referents (MPRs) in excess of 20 years. (See Resolution E-4214 dated December 4, 2008.) This provides a vehicle for consideration of such contracts. The comments of LSA/CalWEA demonstrate that some solar and wind projects may find contracts in excess of 20 years desirable. Those proposals should be allowed and considered.29
Therefore, we do not change STC 5, but we direct each IOU to exclude language in its request or protocol which would prohibit or discourage bids longer than 20 years. This requires changes in the language proposed by SCE and SDG&E, and perhaps PG&E.
We require this consistent with existing language in STC 5. That is, STC 5 permits a bidder to mark the box "non-standard delivery term" and enter a period longer than 20 years. This aligns with both a plain reading of STC 5, and the notion of STC 5 being modifiable. We expect each IOU to consider bids submitted for any duration, from one month to over 20 years. Just as with any bid, the IOU should evaluate each bid using its LCBF methodology plus any other reasonable screening tools, and discuss acceptance or rejection with its PRG, as appropriate.
5.4. Network Upgrades
LSA/CalWEA recommend the Commission encourage upfront funding by IOUs of network upgrades required for renewable generator interconnections. In support, LSA/CalWEA point out that Federal Energy Regulatory Commission's (FERC) policy is to require a renewable generator to fund the cost of network upgrades upfront if the Participating Transmission Owner does not undertake that responsibility itself, with the cost of the upgrade credited back to the generator over a subsequent five-year period.30 LSA/CalWEA assert the Commission is aware that market failures and increased customer cost may occur due to FERC's policy, and to remedy these problems the Commission has provided "backstop funding." This approach allows an IOU to provide upfront funding of network upgrades and recover those costs from retail customers if FERC does not permit recovery through wholesale transmission rates.31
According to LSA/CalWEA, the Commission expected this funding approach to result in IOUs volunteering to build and pay upfront, in the majority of cases, for all transmission network upgrades needed to interconnect both individual and multi-developer projects. LSA/CalWEA claim this expectation has not been realized, and that this could result in a stunted market. LSA/CalWEA propose three remedies. PG&E and SCE oppose the proposals. We adopt them in part.
5.4.1. Cash Flow
First, LSA/CalWEA suggest that the Commission renew its support for IOU-funded network upgrades, and its commitment to ensuring cost recovery for IOUs. In particular, LSA/CalWEA recommend the Commission allay IOU concerns about cash flow impacts by adopting policies to minimize regulatory lag related to cost recovery (e.g., allow IOU cost recovery pending FERC approval of cost recovery in wholesale rates; use Commission-authorized balancing accounts to speed rate adjustments).
We decline to make changes here. We are giving further consideration to these issues in our transmission rulemaking and investigation (R.08-03-009/ Investigation 08-03-010). We are there considering policies that would actively promote the development of transmission infrastructure to provide access to renewable energy resources for California. We encourage LSA/CalWEA and other parties to participate.
5.4.2. Component of Plan
Second, LSA/CalWEA suggest that the Commission encourage each IOU to include upfront funding as a component of its 2009 RPS Procurement Plan. We do not disagree. To the extent not already addressed but intended as a component of its 2009 RPS Procurement Plan, each IOU may include upfront funding of network upgrades in the revised Plans to be filed shortly after this decision.
5.4.3. Justify Decisions
Lastly, LSA/CalWEA suggest that the Commission require IOUs to justify decisions to forego upfront funding in connection with any failure by an IOU to reach RPS Program targets. We decline to adopt this suggestion. SCE correctly points out each IOU is already on notice of its ultimate responsibility for reasonable RPS outcomes, within application of flexible compliance criteria. 32 Moreover, we have identified related issues in our transmission rulemaking and investigation. To the extent appropriate and addressed by parties, we will explore the matter there.33
5.5. LCBF Proposals
IOUs were asked to identify modifications in how bids are to be evaluated and ranked using their LCBF methodology between their 2008 and 2009 solicitations, including evaluation and ranking of out-of-state resources and short-term contracts. IOUs describe several modifications. Parties offer comments along with related proposals regarding project evaluation. For the reasons discussed below, we accept most proposals and decline to accept others.
PG&E reports that it will continue the ranking process implemented in 2008 but, based on IE feedback, clarifies the LCBF evaluation process with respect to three items. First, locational marginal pricing multipliers based on data developed by the California Independent System Operator (CAISO) will be used to evaluate delivery points. Second, PG&E makes explicit in its LCBF protocol that PG&E will limit the total supply shortlisted from any single counterparty in order to diversify risk. Third, hybrid offers (a combined fossil and renewable proposal) must separately price the renewable power, and only the renewable power will be considered in the RPS solicitation.34
SDG&E says its LCBF method will reflect four changes. First, it will modify how it applies duration equalization adders (to equalize bids with different starting dates and terms). SDG&E says it will fill in delivery gaps using average 2009 bid prices rather than MPR (since MPR does not, according to SDG&E, include the REC component otherwise potentially contained within bid prices). Second, SDG&E says the roles and responsibilities for two separate bid assessment teams (Processing Team and Evaluation Team) will be combined into one team, aliases will no longer be created to disguise affiliate offers, and other information in an offer from an affiliate will no longer be masked. Third, SDG&E may seek outside consultants to perform LCBF quantitative calculations, depending upon internal resources, the number of offers and other related factors. Fourth, SDG&E proposes different methodologies for evaluating short-term and long-term offers.35
SCE does not identify any important, specific changes. SCE states that it has revised certain language.36 SCE reports that it used the same evaluation methodology in 2008 for short-term and long-term contracts, and will do so again in 2009. SCE also explains that its methodology for evaluating and ranking out-of-state resources for 2009 is unchanged from that used in its 2008 Plan.
No party convincingly argues against these specific changes (discussed more below), and we accept them. Each IOU should continue to work with Energy Division and parties to make its LCBF analysis clear, as described more below. IOUs remain responsible for meeting RPS goals (e.g., 20% by 2010), and are expected to continue to modify and improve LCBF methodologies, if and as necessary, consistent with meeting program goals and complying with Commission orders.
Parties also make several proposals. LSA/CalWEA recommends that the Commission establish a process for improving consistency and transparency of the criteria IOUs use in evaluations of project viability. We have addressed this above regarding Sunrise issues.
LSA/CalWEA also recommends that the Commission require IOUs to explain the application of project viability evaluation criteria to UOG. We agree. The project viability methodology and criteria addressed above are focused on merchant plant. While the exact same methodology may not apply, we expect project viability considerations to be addressed whenever a UOG project is formally proposed by an IOU.37
Reid makes several comments relative to project evaluation under the heading of transparency. We decline to adopt Reid's recommendations.
Reid is concerned with PG&E's use of qualitative assessments as part of its bid evaluation. To partially address this concern, Reid recommends the use of commercially available software to assess, and quantify, the probability of default as part of the credit attribute item in bid evaluation. PG&E points out in its response that this software typically requires the use of historical prices of the debt and equity of the firm and, for small and/or private firms that often bid into PG&E's RPS solicitation, this information is not available to PG&E. We are persuaded by PG&E that the required data is not necessarily easily available on an equal and unbiased basis. We decline to order IOUs to use such software. Nonetheless, the concept of quantifying and more objectively assessing the probability of default has merit. We encourage parties to continue to explore the subject and bring us additional proposals if and when reasonable.
Also, it is unclear how Reid's comments relative to portfolio fit and other items are to be incorporated into the LCBF methodology. We welcome further suggestions from parties. We encourage parties to clearly explain and support proposals, and then link specific recommendations to prior Commission orders or specific items in an IOU's Plan so that we may have a better opportunity to understand and implement reasonable proposals.
5.6. TOU Factors
RPS Plans include time-differentiation of prices to be paid for electricity generated by renewable resources. The time-differentiation is based on TOU factors.
CCC and Solar Alliance recommend the Commission direct IOUs to file benchmarking studies and schedule a workshop with an opportunity for written comments. We decline to do so. Parties have had time to engage in discovery, move for hearings, and bring evidence to the Commission, thereby making the record any party believes necessary. We will use the record before us.
CCC/Solar Alliance question why the summer on-peak TOU factors vary so widely between SCE, PG&E and SDG&E, with, for example, the summer on-peak TOU factor of SCE being 91% higher than that of SDG&E. 38 CCC/Solar Alliance contend this may be because the SDG&E factor is energy-only and is not "all-in" (capacity and energy).
There may be several reasons the TOU factors differ between IOUs. For example, the SCE summer on-peak period is June through September for 510 hours, while the SDG&E summer on-peak period is July through October for 696 hours, or 37% more hours for SDG&E than SCE.39 There may be other factors.
CCC/Solar Alliance do not provide adequate evidence or argument to conclude that SDG&E's approach is flawed, even if different than that of PG&E and SCE. We encourage parties to provide further information, as appropriate. In the meantime, we have found that each IOU may develop its own TOU factors, in order to best reflect each utility's market-based valuation of electricity in different time periods. (D.06-05-039, at 68.) We continue this approach, absent compelling evidence to adopt a uniform method or benchmarking system.
We also expect time of use factors to "recognize the extent of the need for additional capacity." (D.06-05-039, at 69.) SDG&E must make a showing when it next addresses TOU factors that explains the reasonableness of its TOU factors. In particular, SDG&E must explain the extent of its need for additional capacity and how that is or is not reflected in its TOU factors. SDG&E must also present both energy only and all-in factors with its next showing so we have a more complete record upon which to reach an informed decision.
Here, however, we have no evidence to order different TOU factors. We are confident that parties with a sufficient economic interest will pursue these matters when it is reasonable for them to do so. We have committed to a formal review of TOU factors in the next long term procurement plan (LTPP) proceeding. (See D.08-07-048.)
Finally, CCC/Solar Alliance ask if the review of TOU factors in the next LTPP proceeding will modify the TOU factors used for RPS bids and the MPR in 2009 or 2010. No party, including CCC/Solar Alliance, makes a proposal to answer that question, and we will not craft one here. Therefore, we expect to apply TOU factors on a going forward basis. This will include current and prospective (but not retroactive) application of TOU factors determined in the LTPP proceeding to RPS Plans under consideration at that time. It will not include adjusting TOU factors accepted here for the 2009 Plans.
5.7. Utility-Owned Generation
We have consistently said that enforcement of the 20% by 2010 requirement will take into account whether or not each IOU undertook all reasonable actions to comply, including the building, owning and operating of its own RPS resources.40 We asked that RPS Plans include a showing on IOU consideration of this option. The most recent Amended Scoping Memo asked that the Plan identify specific projects under consideration, and specific generic additions. Each IOU Plan includes its showing. (See Attachment C.)
DRA recommends that IOUs be directed to re-file their Plans in order to include cost-competitive UOG renewable projects. We decline to require the re-filing of Plans before reaching today's decision. Rather, we note that IOUs have included relatively more information in these Plans than before. For example, PG&E discusses small hydro, solar and other options. SCE includes its Solar Photovoltaic Program. SDG&E includes 20 MW to 35 MW of utility owned distributed solar project viability.
At the same time we point out, as we have before, that the showings are relatively short, generally inconclusive, and are unlikely to meet the necessary standard of demonstrating that the IOU undertook all reasonable actions to meet the 20% goal (if an IOU otherwise fails to meet that goal). (See, for example, D.08-02-008, at 32-33.) We repeat our prior statement on this matter since it remains reasonably succinct and clear:
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, at 25, cited in D.08-02-008, at 33.)
IOUs may consider including more information in the amended Plans they file pursuant to today's order. This may include cost-competitive UOG renewable projects, as suggested by DRA.
We note that PG&E includes a new ownership option in its 2009 Plan. In particular, PG&E states that it has been approached by counterparties interested in pursuing joint development and ownership of projects. PG&E reports that its prior solicitations did not explicitly provide for this type of offer. PG&E says its 2009 Protocol has been revised to expand ownership options to include joint development and ownership (in addition to three previous options of (a) power purchase agreement with buyout, (b) purchase and sale agreement, and (c) site for development). No party filed comments.
We have long supported utility ownership in appropriate situations. PG&E's proposal is consistent with our guidance last year, wherein we expressed interest in the possibility of utility ownership of electric generation at the site of one of its customers, or partial ownership in combination with that customer. (D.08-02-008, at 34, footnote 14.) We are pleased to see PG&E include a joint development and ownership option this year, just as we were pleased in 2007 with a PG&E proposal to solicit sites for development. (D.07-02-011, at 24.) We accept PG&E's proposal, and encourage (but do not order) other utilities to adopt a similar item.
Finally, we have not only changed ratemaking treatment to place UOG on a more equal footing with others, 41 but we note that several very significant events have occurred since the draft Plans were filed in August 2008. Some of these are potentially so important as to dramatically change available options. Among these, for example, are: extension of certain federal investment tax credits for renewable resources to those owned or developed by utilities (where they were previously unavailable to utilities); reduction in interest rates; significant deterioration in financial markets; a national recession; and a $789 billion federal economic stimulus package that targets certain funds for renewable resources. The revised Plans filed pursuant to this order should include discussion of UOG, and other items, that reflect these important changes in conditions, where appropriate, in a manner consistent with Commission policies and guidance on procurement. This may include, for example, opportunities for utility procurement, where reasonable, of existing, completed merchant-developed RPS projects that are facing asset liquidation.42 As we have said before, we expect utilities to reach RPS Program targets (e.g., 20% by 2010). If this is not possible through competitive solicitations, we expect utilities to reasonably develop all economic and feasible RPS plant necessary to reach Program targets. In the unique circumstances in which California finds itself today, that might also include a utility obtaining a partly completed RPS plant if a merchant generator is unable, or does not desire, to bring the project to completion.
5.8. Plan Organization and Data for 2010 Plans
As we have said in each of the last several years, we continue to note that each Plan is complex, with many attachments that are not easy to assess and use. (See, for example, D.08-02-008, at 35-38.) In particular, the form and format of the attached solicitation documents (e.g., Protocol, Request for Proposal (RFP), Request for Offer (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. We also suggest IOUs begin coordinating now on the form and format of the 2010 Plans. Increased coordination will promote the continuation of incremental improvements.
We are encouraged by progress made so far. For example, SCE proposes standard contracts for all RPS projects (discussed more below). We encourage increased standardization in form and format to the fullest extent reasonable. As we said last year:
... 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. (D.08-02-008, at 38.)
IOUs make various recommendations on data and presentations for the 2010 Plans. For example, IOUs must provide information that identifies changes between Plans, including proposed changes to STCs. SDG&E and others state that the matrix used to identify proposed changes to STCs is burdensome. SDG&E recommends that in the 2010 Plan each IOU simply provide redlines of changes to modifiable STCs, including justification for the change, along with a statement that no changes have been made to the non-modifiable STCs.
We agree with making improvements for the 2010 Plans that ease the workload on all parties while providing necessary information in an easy to understand format. We do not micromanage the details here. Utilities may work with Energy Division staff and parties on that goal for the 2010 Plans. The assigned Commissioner will issue an Amended Scoping Memo later in the year detailing the necessary items for the 2010 Plans. To the extent further refinements should be considered that are not already incorporated in the Amended Scoping Memo, utilities may also move at that time for changes to the Amended Scoping Memo.
24 SDG&E proposes four weeks between the date SDG&E notifies short-listed bidders and the date short-listed bidders must withdraw from SDG&E's solicitation or accept short-listed standing and provide a development security deposit. (SDG&E Plan, at 7 of 26.) PG&E recommends eight days between the date PG&E notifies shortlisted bidders and the date the bidder notifies PG&E whether it accepts the shortlisted position. (PG&E Protocol, at 4.) SCE proposes ten days between the date SCE notifies a bidder of its short-list status and the date the bidder either withdraws its bid or grants SCE exclusive negotiating rights. (SCE Plan, at 14.)
25 Our authority to authorize TRECs is conditioned upon this finding by the CEC and us. (§ 399.16(a)(1).)
26 See § 399.16(a)(9).
27 Each IOU may file and serve an advice letter notifying the Commission and the service list of a change in its RPS Procurement Plan. (See General Order 96-B.) The advice letter should attach the pages which are added to the Plan, and clearly identify any deletions or other changes to the Plan.
28 "In soliciting and procuring eligible renewable energy resources, each electrical corporation shall offer contracts of no less than ten years in duration, unless the commission approves of a contract of shorter duration." (§ 399.14(a)(4).)
29 Allowing and considering a proposal does not mean the proposal will be approved and become an effective contract.
30 LSA/CalWEA Comments, at 7, citing Standardization of Generation Interconnection Agreements and Procedures, Order No. 2003, 104 FERC ¶ 61,103 (2003).
31 Id., citing Pub. Util. Code § 399.25 and Commission D.06-06-034 (at 11, 38, and Conclusion of Law 3.)
32 SCE Comments on Proposed Decision, at 9.
33 The issues in the preliminary scoping memo include: (a) has the Commission's cost recovery regime been effective in supporting transmission to renewable resource areas and (b) how could that cost recovery regime be improved. (R.08-03-009/I.08-03-010, at 8.)
34 As explained by PG&E, separate pricing is not required if 100% of the generation is RPS-eligible under the CEC's eligibility guidelines. It is required only when part of the generation is not RPS-eligible. (PG&E Reply Comments on the proposed decision, at 5.)
35 See SDG&E Plan at 10, 18, and Appendix E, at 1, 2.
36 SCE notes that the revisions are identified in the redlined comparison between its 2008 and 2009 LCBF written report. (See SCE RPS Procurement Plan, Attachment 1-2, Appendix B.)
37 This would not necessarily be part of an IOU's RPS Procurement plan but would, for example, be in the IOU's formal application with the Commission for a CPCN. If an IOU (or affiliate) submits a bid in an annual RPS solicitation, it would be in the review of bids in that solicitation.
38 The SCE summer on-peak TOU factor is 3.13. The SDG&E summer on-peak TOU factor is 1.64. The ratio (3.13/1.64) is 1.91.
39 June through September is 85 days (excluding two holidays), at six hours per day during the on-peak period for SCE, for 510 hours. July through October is 87 days (excluding two holidays), at eight hours per day during the on-peak period for SDG&E, for 696 hours. The ratio of 696/510 is 1.365. (See SCE 2009 RPS Procurement Plan, Attachment 2-3, Exhibit K; SDG&E 2009 RPS Procurement Plan, Appendix B5, at 39.)
40 See, for example, D.06-05-039, at 33-34; D.07-02-011, at 23-25; D.08-02-008, at 32-35.
41 See D.07-12-052, at 221 and Ordering Paragraph 33. Also see D.08-02-008, at 34.
42 We addressed this, for example, as a situation that may result from a settlement or bankruptcy. We said in 2007 that we thought these conditions would diminish over time. (See D.07-12-052, at 212.) We now note that extraordinary and dramatic economic events since 2007 may affect the duration and nature of those situations.