4. Issues Common to All Plans
We address the following issues common to most, if not all Plans:
· Buyer-Directed Economic Curtailment
· Integration Cost Adders
· Tradable Renewable Energy Credits (TRECs)
· Sunrise/Imperial Valley Remedial Measures
· California Independent System Operator (CAISO) Standard Capacity Product (SCP)
· Pilot Programs for Preapproval of Short-Term Contracts
· Plan Organization and Standardization
· Other Updates
· MJU Supplemental Filing Date
· Non-Disclosure Agreements
4.1. Buyer-Directed Economic Curtailment
The CAISO recently implemented its Market Redesign and Technology Upgrade (MRTU). MRTU uses markets and market-determined prices to schedule and dispatch generation resources. In particular, it uses Locational Marginal Prices (LMPs) as price signals reflecting electricity supply and demand in multiple locations. Over time, LMPs could also give price signals that influence project location.
To address MRTU issues, SCE and PG&E propose modifying pro forma (model) contract terms and solicitation protocols. SCE and PG&E propose terms that would allow the utility, as buyer and scheduling coordinator, to decline procurement from a renewable generator if the day-ahead price makes the delivery uneconomic. We refer to this as buyer-directed economic curtailment, or economic curtailment.15 We address three economic curtailment issues presented by parties:
1. Pre-2011 contract interpretation;
2. 2011 pro forma contracts; and
3. Requirement that project be fully deliverable.
In its draft 2011 Plan, SCE asserts that its prior pro forma contracts allow SCE to direct curtailment of an RPS project at the request of either the CAISO or SCE.16 SCE also says it has the right to withhold payment to the seller for energy that the facility could have delivered but for the curtailment ordered by SCE.
CalWEA/LSA disagree, asserting that prior pro forma contracts do not allow unlimited curtailment by SCE for economic or other reasons. They claim that SCE's interpretation jeopardizes the ability of developers to find project financing.17 TURN, IEP, and CEERT agree. In addition, TURN and IEP say that SCE's interpretation could result in significant contract price increases to cover the risk of substantial curtailment.18 CEERT states that SCE's interpretation is inconsistent with prior power purchase agreements (PPAs), prior Plans, and Commission decisions.19
We decline to interpret terms of executed contracts. Rather, disputes over terms in executed contracts are subject to the dispute resolution provisions of the contract. Parties should use those provisions.
Some pre-2011 pro forma contracts may not yet be executed, but might be the subject of ongoing negotiations. If so, buyer and seller may negotiate a mutually acceptable solution regarding this issue in light of SCE's statements. We need not disturb the negotiation process.
We note, however, that our approval of prior Plans and pro forma contracts has been, and is, in the context of "flexibility with accountability." (D.09-06-018 at 9.) Each utility is "ultimately responsible for proposing and executing reasonable Plans that achieve RPS targets." (Id. at 53.) This responsibility includes contract execution and ongoing contract administration. SCE's interpretation and enforcement of prior pro forma and executed contracts is a factor in that administration. If SCE fails to execute contracts or a contract fails due to unreasonable administration by SCE, with SCE thereby failing to reach its program targets (e.g., 20% by 2010), SCE is subject to being held accountable. This includes the potential of SCE paying penalties for failing to reach targets.20
PG&E and SCE propose 2011 pro forma contracts allowing economic curtailment. SDG&E makes no such proposal. For the reasons explained below, we direct that all three IOUs include economic curtailment provisions in their Final 2011 Plans, and reveal limited specific congestion cost information to the extent used in LCBF evaluations. We first briefly describe the proposals.
PG&E proposes economic curtailment up to five percent of the project's expected annual generation per year, with PG&E paying the seller the full contract price for curtailed energy. The reduced generation, however, may result in the seller losing certain tax advantages (i.e., production tax credits or PTC). PG&E does not propose reimbursement for the lost PTCs.
SCE first proposed unbounded economic curtailment. SCE modified its proposal based on parties' comments. As modified, SCE proposes economic curtailment without compensation (and without reimbursement for lost PTCs) up to a pre-determined, negotiated number of hours capped at between 50 and 200 per year. Economic curtailment in excess of the cap is to be compensated by SCE at the contract price plus the value of any lost PTCs. At the end of the contract SCE would have the option to buy generation equal to twice the total amount that was curtailed over the life of the contract in excess of the cap at 50 percent of the contract price. This option could be exercised for up to two years past the conclusion of the original contract term.
SDG&E proposes no change from its 2009 pro forma contract. As a result, SDG&E could not exercise economic curtailment in response to MRTU price-based scheduling and dispatch.
Parties take a range of positions largely in opposition to economic curtailment. For example, CalWEA, LSA, and IEP oppose SCE's proposal, saying it is too complex and would result in higher contract prices than the proposals of either PG&E or SDG&E. TURN joins the opposition saying SCE's proposal would be more costly to ratepayers than SCE simply accepting actual curtailment risk.
CalWEA, LSA, and IEP seek a simple approach. For example, IEP suggests allowing economic curtailment without compensation up to 20 hours per year. Alternatively, IEP suggests supporting the proposal of SDG&E or PG&E because either one is simpler, while being financeable at less cost, than SCE's proposal. CalWEA and LSA recommend the Commission reject SCE's proposal, with a requirement that SCE adopt a modified version of PG&E's proposal.
We determine it is reasonable for the pro forma contract of each IOU to include provisions for economic curtailment. We reach this conclusion because MRTU has the potential of significantly changing the way generation resources are scheduled, dispatched and located. RPS contracts must reasonably reflect the CAISO's new economic approach. Failure to do so could undermine the ability of MRTU to optimally use price signals for those economic purposes.
It is clear that the impact on stakeholders differs under the proposals of PG&E and SCE, but we are unable to determine an optimal approach. Parties fail to present estimates of the likely locations or amounts of curtailment over the contract duration, the likely impact on contract prices resulting from various proposals, or any other facts or compelling argument to differentiate the impact of alternative economic curtailment approaches on different stakeholders. Without facts or more compelling argument, we decline to simply pick one.
All parties agree, however, that the proposals of both PG&E and SCE (as modified) are financeable because, by establishing specific limits, each bounds the developer's economic curtailment risk. Moreover, each proposal shares congestion cost risk between developers and ratepayers; provides economic information to developers, sellers and IOU buyers; and is negotiable between buyer and seller before final contract execution.21
As a result, we do not pick one approach but require an economic curtailment provision in the Final 2011 Plans filed by each IOU, including SDG&E. Consistent with our approach of flexibility with accountability, SCE may use its preferred approach, PG&E may use its preferred approach (with one modification required below), and SDG&E may develop one.22
We also address congestion costs as part of the treatment of economic curtailment. We do this within the framework of MRTU's use of price signals (LMPs) to schedule, dispatch and potentially locate generation resources based on supply and demand, along with other potential costs related to supply and demand imbalances. SDG&E reports that it assesses congestion within its LCBF evaluation, and PG&E commits to doing so similar to its past practice.23 This is reasonable, and we will require SCE to similarly incorporate assessment of congestion costs in its 2011 LCBF evaluations.
SCE should, as a result, include modifications to its LCBF methodology as part of its Final 2011 Plan filed pursuant to this order. The modifications should clearly incorporate and explain its economic curtailment provisions and use of congestion costs. SDG&E and PG&E should modify their LCBF descriptions as necessary to make their economic curtailment provisions and use of congestion costs clear. Further, to the extent an IOU uses specific congestion cost values in its LCBF protocol, the IOU should make those values available to bidders as part of making the LCBF methodology transparent.
Finally, as recommended by CalWEA/LSA, we require PG&E to modify its payment provisions. As modified, PG&E will pay a seller for curtailment even when that economic curtailment is initiated by an entity other than PG&E (such as the CAISO). We do this because CalWEA/LSA correctly point out that the curtailment instruction may be the result of PG&E actions or omissions. We agree with CalWEA/LSA that PG&E's approach to economic curtailments would thereby effectively not be limited to five percent of expected annual output. Therefore, we apply the five percent limit to all economic curtailment whether or not initiated by PG&E.24
We do not, however, require PG&E to compensate the seller for lost PTCs, as recommended by CalWEA/LSA. We agree with PG&E that it is reasonable for sellers to bear some of the curtailment risk. Further, PG&E correctly points out that determining the amount of the lost PTC is complex and time-consuming. While SCE agrees to do so, we will not require this of PG&E.
In its amended Plan, SCE explains that the Large Generator Interconnection Agreement gives sellers two deliverability options from which to choose: energy-only or fully deliverable. SCE proposes that sellers be required to be fully deliverable. We decline to adopt this recommendation. We first briefly explain the two deliverability options.
Energy-only projects are only required to pay the costs necessary for the project to interconnect to the network. Fully deliverable projects must also pay costs to ensure deliverability.25 The benefits of being fully deliverable include that the project can count toward an IOU's resource adequacy (RA) requirements, along with being obligated to pay its portion of any deliverability upgrade costs. CAISO decisions about which projects to curtail, however, are not affected by the project's deliverability interconnection type.
SCE proposes a fully deliverable requirement so that the project counts towards SCE's RA requirements. In support, SCE argues that energy-only interconnections expose the grid to greater risks of congestion and over-generation since these projects do not pay for necessary deliverability upgrades to avoid congestion. Further, SCE contends that full deliverability requires the project pay its share of deliverability upgrade costs. SCE suggests the Commission require that all IOUs adopt this provision so that projects selling to other buyers also share deliverability upgrade costs. IEP/CalWEA and CEERT oppose SCE's proposal.
We decline to adopt SCE's proposal. SCE expresses a legitimate concern that allowing energy-only projects to participate in RPS solicitations may increase the risk of congestion (and negative LMP prices) because those projects do not help fund deliverability upgrades. However, it is not clear that the cost to build additional facilities (e.g., transmission for deliverability) will be lower than costs related to curtailment. In addition, we address congestion cost concerns and mitigate ratepayer risk in other ways in this decision (e.g., contract terms in 2011 Plans for economic curtailment, LCBF treatment of congestion costs). This will allow IOUs to assess congestion costs as part of a bid's value and encourage developers to seek project sites with fewer potential congestion costs, without foregoing a viable interconnection option currently permitted by the CAISO.
Moreover, IOUs incorporate RA adequacy into their LCBF methodologies. Thus, IOUs are able to assess the RA value differential, if any, of a project interconnecting at energy-only versus full deliverability. The RA treatment in each IOU's LCBF methodology should be clearly explained, however. Thus, each IOU should modify its LCBF description, as necessary, to make its treatment of RA, and use of RA adders, clear to bidders as part of making the LCBF methodology transparent.
4.2. Integration Cost Adders
Integration costs are costs associated with ancillary services needed for real time balancing of the CAISO transmission system from instability caused by unexpected fluctuations in generation or load. SCE and SDG&E propose the use of non-zero integration cost adders in draft 2010 Plans as part of their LCBF evaluation of bids. In particular, SCE proposes use of integration cost adders that will be developed based on multiple integration cost studies.26 SDG&E proposes to use cost adders that will be determined at a later point in consultation with its independent evaluator (IE).27 CalWEA, LSA, DRA, and TURN oppose these proposals.
We decline to adopt non-zero integration cost adders in this decision. We have previously rejected proposals for non-zero integration cost adders.28 Nothing presented here changes our view. IOUs must exclude language in Final 2011 Plans that would incorporate use of non-zero integration cost adders, including their use in LCBF evaluation of bids.
Moreover, we said before that such costs, if any, need to be developed with public review and comment.29 CalWEA, LSA and TURN argue that an adder should only be used if it is developed in a public forum and, in addition, with Commission supervision.30 We agree. We are currently assessing renewable integration needs and costs in another proceeding (Rulemaking (R.) 10-05-006). If an adder is developed in that proceeding, then each IOU may file an advice letter seeking to amend its 2011 Plan for the purpose of using that adder in its LCBF evaluations.
4.3. TRECs
IOUs include discussion of the use of TRECs in their draft Plans, generally seeking use of TRECs but conditioned on a future Commission order authorizing that use. DRA recommends that the Commission reject inclusion of TRECs in these Plans. In support, DRA says the Commission has not reached a final decision on the use of TRECs. DRA also notes that we ordered the removal of TREC discussion in the 2009 Plans. (D.09-06-018 at 37-39.) Reid similarly supports removal of references to TRECs in amended Plans and solicitation protocols.
Subsequent to parties' comments here, we lifted the stay of D.10-03-021. We now permit the use of TRECs for RPS compliance. (D.11-01-025.) Therefore, it is appropriate for 2011 Plans to include IOUs' intended use of TRECs. Final Plans filed pursuant to this decision should include each IOU's planned use in a manner that complies with the authorization prescribed in D.11-01-025. MJUs previously reported no change in their IRPs or Supplements based on our March 2010 TREC order. MJUs should file an Amended Supplement, however, if their planned use of TRECs is now changed as a result of our January 2011 order.
4.4. Sunrise/Imperial Valley Remedial Measures
We required IOUs to hold a special Imperial Valley bidders conference, and perform specific proposal and project monitoring, as part of the 2009 RPS solicitation. (See D.09-06-018.) We did this in order to provide all reasonable opportunities for optimal use of the Sunrise transmission project. We declined to adopt automatic additional measures relative to Sunrise for the 2010 solicitation, but stated that:
" ... we will consider remedial measures if future evidence shows the LCBF methodology fails to properly value Imperial Valley resources and their unique access to transmission, or that there are other infirmities. Those measures might include automatic shortlisting, a special bid evaluation metric, special solicitation, or other remedies a party may propose. The expense and environmental consequences of Sunrise, just as with any significant infrastructure project, demand nothing less. We will not hesitate to use all regulatory tools at our disposal so that reasonable, cost-effective renewable resources enabled by Sunrise are developed. (See D.08-12-058 at 263.)" (D.09-06-018 at 18.)
The Amended Scoping Memo specifically directed IOUs to address this issue.
All three IOUs report robust Imperial Valley results from the 2009 solicitation. PG&E says it received a significant volume of offers from projects that would interconnect to the grid in Imperial Valley, and the number of bids for development in the Imperial Valley relative to resource development potential for the area was roughly the same proportion observed for renewable bids throughout the rest of PG&E's territory. SDG&E states that the number of offers it received from Imperial Valley was many times more MW than can flow over the Sunrise Powerlink. According to IOUs, the Commission's desire that renewable resources take full advantage of the Sunrise project is being met, and remedial measures are not needed in the 2011 Plans. No party comments to the contrary.
We agree. We are encouraged by the robust response, and confident that IOUs will select all reasonable bids within the LCBF process. We decline to order any remedial measures, but continue specific monitoring of Imperial Valley proposals and projects.31
SDG&E states that it plans to host another bidder's conference in the Imperial Valley regardless of whether it is ordered to do so, believing that further utility (buyer) outreach will help increase industry knowledge and, ultimately, the quality of offers. We have commended utilities for innovative work in the past, and we do so here regarding SDG&E's planned outreach and initiative.32 We encourage all three IOUs to do outreach, and take all reasonable and necessary action to secure optimal RPS development and reach RPS targets. This should include special Imperial Valley bidder's conferences, when useful, to continue to ensure robust response in this important region.
4.5. CAISO Standard Capacity Product
The SCP is a product to reduce transaction costs associated with buying, selling and trading capacity to meet RA requirements. It reduces transaction costs by standardizing the obligations of RA providers. In particular, scheduling coordinators are subject, under CAISO Tariff § 40.9, to charges for non-availability or incentive payments for availability.
SCE, PG&E, and SDG&E propose allocating the benefits and risks of the CAISO's SCP to sellers. CalWEA and LSA recommend that the Commission reject the proposed allocation of risks, asserting it is premature to do so pending final CAISO decisions and, once final, involves complicated implementation details. IOUs respond in opposition to the recommendation of CalWEA and LSA. We adopt IOUs' proposals.
IOUs convincingly show that the proposals allocate not just the burdens but also the benefits to sellers. This is a balanced approach. Moreover, implementation details are distinct from the allocation of benefits and burdens. It is generators rather than IOUs that control facility operation and have the ability to mitigate potential penalties. Allocating potential penalties to the party who is best positioned to mitigate penalties gives that party the incentive to operate optimally.
If the IOUs' proposal is adopted, CalWEA and LSA recommend modification of IOU model PPAs so that the seller's obligation to supply capacity for RA purposes would be optional. This modification is unnecessary. Contract terms (except for limited non-modifiable standard terms and conditions) are subject to negotiation. Bidders may submit bids with a proposal to modify contract terms related to RA (including these changes on a bidder's proposed term sheet summarizing all major proposed changes).33
Finally, CalWEA and LSA argue that allocation of risks relative to the SCP duplicates existing incentives. This occurs because compensation for capacity is included in the all-in energy payment. The generator is provided an incentive to provide capacity when the all-in rate includes a capacity component, and fails to receive this capacity payment when the generator does not operate during those periods (for either a planned or unplanned outage). An SCP penalty for failure to provide resource adequacy value penalizes the generator a second time according to CalWEA and LSA.
We agree, but are not convinced that this merits elimination of the capacity portion of the all-in energy payment. It is reasonable that IOUs reflect the full balance of CAISO provisions in the contract, but generators may pursue relief from duplicative incentives, if any, created by the CAISO (or the Federal Energy Regulatory Commission (FERC) upon review of CAISO action). Finally, if CAISO and FERC do not agree these incentives are duplicative, the bidder may seek to negotiate a different result with the IOU (relying on competition between IOUs to secure an optimal and just outcome).
Thus, IOUs may include allocation of both the benefits and risks of the CAISO SCP to sellers.
4.6. Pilot Program for Preapproval of Short-Term Contracts
Last year, as part of their 2009 draft Plans, SCE and PG&E requested authorization for programs permitting preapproval for certain quantities of RPS contracts. We denied those requests in favor of an RPS contract mechanism for simplified, streamlined, fast-track review of short-term contracts. We did so because the adopted mechanism addressed the fundamental goals sought by SCE and PG&E.34
As part of their 2010 draft Plans, all three IOUs propose pilot programs for transactions involving short-term deliveries. PG&E and SCE propose similar programs, wherein 1 percent of current year retail load is preapproved for procurement at certain market valuations during the next five years for contracts with durations up to five years.35 SDG&E proposes a similar program capped at 1500 gigawatt-hours (gWh). According to the IOUs, the proposals are modeled after the IOUs' procurement authority for conventional power.36 Under these pilot programs, any contract meeting specified criteria (e.g., price cap, total cost cap, energy amount, duration) would be deemed per se reasonable and preapproved for cost recovery from ratepayers.
DRA and TURN oppose the pilot programs. We decline to adopt IOUs' proposals for the following reasons.
We have inadequate evidence that the system we adopted in June 2009 does not work, cannot work, or cannot be reasonably modified, if necessary. That system was adopted after careful deliberation and the balancing of many competing interests and needs. We encourage IOUs to be more creative and vigorous in seeking authorization for short-term opportunities under our adopted system for fast-track approvals, if short-term transactions are in fact appropriate, desirable, and reasonable.
SCE proposes that we retain our existing fast-track preapproval process but also authorize SCE's pilot program, arguing that there is nothing that prevents the Commission from permitting more than one option for fast-track approval of short-term contracts. We decline to increase the complexity of an already complex program by layering on multiple options to accomplish the same objective.
Most troubling with IOU-proposed pilot programs is the lack of limit and specificity on price and cost. For example, PG&E proposes that it establish both price and revenue requirement caps, but fails to provide adequate information to establish reasonable numbers or process.
SCE proposes a confidential preapproved total cost limit set annually and calculated by SCE using a formula, but fails to convincingly show its formula is reasonable. SCE also proposes a "maximum valuation metric" for each contract. SCE says the "IOU would set a renewable premium-based, maximum valuation metric ... [and] will share this maximum valuation metric and methodology for setting the maximum valuation metric with its PRG [Procurement Review Group] and the Energy Division."37 That is, SCE's proposal delegates reasonableness determination to SCE (who will share the information with the PRG and Energy Division) for potentially hundreds of millions of dollars. While we might later be convinced this proposal is reasonable, SCE does not now present sufficient evidence to demonstrate the reasonableness of this approach.38
SDG&E says the price for its preapproved contracts will not exceed a price cap, and "SDG&E will work with its IE to determine this pricing cap on an annual basis and brief the Energy Division and its PRG on the pricing cap."39 SDG&E's proposal would delegate reasonableness determination to SDG&E and its IE (with a briefing to the PRG and Energy Division) for potentially hundreds of millions of dollars. Again, while we might later be convinced this approach is reasonable, SDG&E does not now present sufficient evidence to demonstrate the reasonableness of this approach.
In support of the pilot program proposals, the IOUs note that these contracts are subject to review in Energy Resource Recovery Account (ERRA) proceedings. Contracts engaged in accordance with pilot program guidelines, however, would, under the proposal, be per se reasonable, and contract terms (including payments made by the IOU) would be deemed approved by the Commission and recoverable in rates. Commission review is limited to an IOU's administration of the transaction. The pilot programs, as proposed, would establish a Commission review and administration process that does not adequately fulfill the Commission's duty to determine whether the results are just and reasonable.
The IOUs contend that they need more flexibility to capture short-term, fleeting market opportunities to meet near-term RPS goals in the face of competition from other LSEs, including ESPs and municipal utilities. IOUs also note that renewable energy is a preferred resource and the rules allowing preapproval of short-term transactions for renewable energy should be simpler-not more complex and restrictive-than the rules applicable to procurement of resources lower in the loading order. We agree that IOUs must have flexibility in the face of competition, and the rules for procurement of resources higher in the loading order should generally not be more complex and restrictive than those for resources lower in the loading order.
We are not opposed to a modified or simpler system than the one adopted in June 2009. We specifically noted that PG&E was free to make a proposal in its 2010 Plan, but only after experience with our adopted simplified, fast-track procedure. (D.09-06-050 at 27, 31.) For the reasons explained above, we are simply not convinced that the pilot programs proposed by IOUs are reasonable.
Nonetheless, we are committed to ensuring that IOUs have a reasonable chance to capture short-term, fleeting opportunities while being able to optimally compete against each other and other LSEs. We encourage IOUs to continue to consider and propose refinements, based on experience with our adopted fast-track procedures and the market.
4.7. Plan Organization and Standardization
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.40 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 remain unconvinced that such complexity is necessary, and we continue to encourage IOUs to seek incremental improvements in standardization and uniformity.
We noted progress made in the 2009 Plans. (D.09-06-018 at 52.) The Amended Scoping Memo encouraged the IOUs to make further progress, particularly in making their three 2010 draft Plans reasonably uniform. IOUs report that the relatively brief time between the issuance of the Amended Scoping Memo and the deadline to file draft 2010 Plans required that they limit and focus their efforts.
We appreciate the IOUs' coordination and focused efforts during that brief time.41 Our request for additional standardization, streamlining, uniformity, and coordination, however, is not limited to their work only after release of the next Scoping Memo. Rather, we encourage increased standardization in form and format to the fullest extent reasonable beginning now. As we said in 2008:
... 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 should begin coordinating now on the form and format of the 2012 Plans, including solicitation protocols, contracts, attachments, and other documents. In particular, we encourage the three IOUs to consider proposing one standard contract that can be preapproved by the Commission. One standard, preapproved contract that can be executed by buyers and sellers will help facilitate speedy and certain Commission review and approval. Negotiated contracts always remain an option, but individualized and unique contracts will continue to take a greater amount of staff time for review, and will typically reduce the certainty and slow the process of obtaining approval.
4.8. Other Updates
Several events have occurred that may not be fully reflected in IOU Plans. For example, in December 2010 we adopted the Renewable Auction Mechanism (RAM). RAM is a tool for IOUs to procure up to 1,000 MW RPS resources from projects up to 20 MW in size. (D.10-12-048.)
In December 2010, we also adopted implementation details for PG&E's solar PV program. (Resolution E-4368; D.10-04-052.) In September 2010 we authorized SDG&E to undertake a solar PV program. (D.10-09-016.) SCE has now conducted its first solar PV procurement. (D.09-06-049; Resolution E-4299.)
In December 2010, we also adopted a qualifying facility (QF) settlement agreement that addresses small power producers-including RPS facilities-up to 20 MW. (D.10-12-035.)
IOU RPS Procurement Plans are the vehicle for an IOU, in one document, to explain to all stakeholders how the IOU plans to achieve state-mandated RPS targets and goals. To achieve this objective, each Plan must be complete and comprehensive. We require that each Plan address and include all procurement options and tools that an IOU will use to reach RPS targets and goals, including utility-owned generation.
Therefore, IOUs should include these and any other similar items in Final 2011 Plans filed pursuant to this decision to ensure that the filed Plans are complete, comprehensive and up-to-date. Among other things, the resulting contracts can then be judged based on consistency with the accepted RPS Plan, and the energy can be included toward RPS targets and goals (e.g., 20% by 2010, 33% by 2020). We noted this same thing with respect to SCE's RPS Standard Contract Program, and do so again here. (D.08-02-008 at 44; D.09-06-018 at 61-62.)
4.9. MJU Supplemental Filing Date
MJUs propose a change in the current annual supplemental filing date. We make the change.42
The current schedule requires that MJUs file an IRP with us when one is also filed with other jurisdictions, along with supplement to address California-specific issues within 30 days thereafter. In years in which an IRP is not filed, MJUs must file a Comprehensive IRP Supplement at the same time as IOUs file their RPS Plans.
MJUs say the lack of a fixed filing date for Comprehensive Supplements in non-IRP years creates a logistical challenge, while a set filing schedule would allow the MJU to more efficiently plan and execute its non-IRP year supplement. MJUs ask for a date of July 15, which Sierra says will dovetail well with filing dates applicable to submissions made at the Public Utilities Commission of Nevada. We agree. This does not relieve an MJU from also responding to requests for information at any time by the Commission, including the assigned Commissioner, ALJ, and staff.
4.10. Non-Disclosure Agreement
CalWEA/LSA recommend that non-disclosure agreements (NDA), or confidentiality provisions, in each Plan be modified to permit discussion by bidders and sellers of the bidding and PPA negotiating process with the Commission and certain other entities.43 In support, CalWEA/LSA assert that the NDAs and confidentiality provisions allow each IOU to disclose confidential information to multiple agencies or entities (e.g., PRG, IE, Commission, CEC, CAISO) but foreclose bidders/sellers from doing the same. CalWEA/LSA recommend modification of these materials in order to provide the opportunity for bidders/sellers to discuss RPS process with the Commission, its staff, PRGs and IEs.
TURN strongly supports CalWEA/LSA. SDG&E does not oppose allowing disclosure of information by bidders/sellers to the Commission, but says disclosure limitations imposed by SDG&E on itself must apply equally to bidders/sellers. PG&E and SCE oppose disclosure.44
We order IOUs to modify their NDAs, or confidentiality provisions, to permit disclosures to the extent described herein. We do so because good decision-making requires consideration of complete information from different informed perspectives. The current NDAs and confidentiality provisions allow full access and data disclosure to the Commission by some RPS participants but deny the same to others, thereby denying the Commission an opportunity for a complete presentation of information from a range of informed perspectives.
Moreover, allowing access to only one side denies the opportunity for a reasonable check and balance. TURN wisely recommends: "The Commission should operate with a `trust but verify' approach to ensure that factual representations are accurate and complete."45 We need to hear all informed perspectives on a topic, subject to a reasonable check and balance.
Therefore, we require IOUs to modify their NDAs or confidentiality provisions to permit bidders/sellers to disclose information on the bidding and PPA negotiating process to the Commission, including Commission staff. We will not, however, be drawn into negotiations and the taking of sides. We expect disclosures to focus on process (i.e., bidding and negotiating process), not individual bids. We instruct staff to strenuously avoid being drawn into negotiations or the taking of sides in the bargaining between an IOU buyer and an RPS bidder/seller.
TURN recommends that the modification include bidders/sellers presenting information to the PRG.46 PG&E opposes this recommendation. We are convinced by TURN for the following reasons to require modification of NDAs and confidentiality provisions to allow disclosure to PRGs.
TURN says that as a PRG member it is forced to rely on IOU representations without the opportunity to determine whether the information is correct and complete.47 TURN reports that misleading or incomplete representations made by an IOU to the PRG could materially affect the positions taken by TURN and other PRG members.
We share this concern. PRG members must be able to `trust but verify' and have access to a full range of informed perspectives subject to a reasonable check and balance (albeit informal and infrequent). This provides the best opportunity for their reaching informed opinions and recommendations. Because we rely on informed comments and recommendations by PRGs, we must ensure that they have reasonable access to information. This is equally true for the IE. Thus, we require that NDAs and confidentiality provisions permit disclosure of information on the bid and negotiation process to the Commission, Commission staff, PRG and IE.
15 No party disputes contract terms and conditions that allow the buyer to direct reduced project deliveries when instructed by the CAISO for system reliability, safety, stability, or similar non-economic reasons. As a result, this section does not address non-economic CAISO-directed curtailment.
16 December 18, 2009 Plan at 50.
17 January 19, 2010 Comments at 2.
18 TURN January 26, 2010 Reply Comments at 1.
19 CEERT January 26, 2010 Reply Comments at 1.
20 D.03-12-065 Attachment A, adopting a modification of D.03-06-071 at 51.
21 Non-modifiable standard terms and conditions are limited to four, and do not include economic curtailment terms and conditions. (See D.08-04-009.)
22 SDG&E's economic curtailment provision must be consistent with the factors discussed herein, including that it be financeable (e.g., reasonably bound the developer risk, such as by a maximum number of curtailment hours or other device); and it must reasonably share the cost and risk of curtailment between stakeholders (e.g., so developers have an incentive to minimize congestion costs when making decisions on project site, interconnection and operation, while potential ratepayer cost is not unlimited).
23 SDG&E already includes congestion cost adders in its LCBF methodology. (April 9, 2010 Further Amended Draft 2010 Renewable Procurement Plan, Appendix C at 3.) PG&E used LMP multipliers in prior RPS RFO evaluations, and says it will do so for the 2011 solicitation. (March 3, 2011 Comments on Proposed Decision (PD) at 6.)
24 The limit does not apply to non-economic curtailment (e.g., for system reliability, safety, stability).
25 The CAISO tariff differentiates delivery status as energy-only versus full capacity. (CAISO Fifth Replacement Tariff, December 20, 2010, Appendix A, Master Definition Supplement at 810, 817.) Projects with energy-only deliverability status must pay costs for (a) direct interconnection facilities (non-network upgrades to the nearest point on the network) and (b) network reliability upgrades. Projects with full capacity deliverability status must pay those costs plus facility costs to satisfy deliverability criteria. A project with full capacity deliverability status can deliver the facility's full output to the CAISO during a variety of stressed system conditions.
26 June 17, 2010 Second Amended 2010 RPS Procurement Plan at 47.
27 April 9, 2010 Further Amended Draft 2010 Renewable Procurement Plan, Appendix C (LCBF Process) at 3.
28 D.07-02-011 at 56; D.08-02-008 at 44.
29 D.08-02-008 at 45.
30 January 19, 2010 CalWEA/LSA Comments at 16; January 26, 2010 TURN Reply Comments at 5.
31 Regarding specific monitoring, see D.09-06-018 at 14; and Appendix A at A-1, Item 1.b.
32 For example, we commended PG&E for its proposal to include joint development and ownership in its 2009 Plan, and SCE for its RPS Standard Contract Program. (See D.09-06-018 at 3, 48-52, 59-62.)
33 See discussion of term sheet as part of PG&E proposed changes summarized in Appendix D.
34 D.09-06-018 at 54-55, 57-59; D.09-06-050 at 26-28. We said that PG&E was free to make a new proposal with its 2010 Plan if, after experience with the fast-track procedures, PG&E was still interested in proposing something else. (D.09-06-050 at 27 (footnote 34), 31.)
35 The volume would be cumulative over the five years, resulting in preapproval of 5% of bundled sales over the five years of the program.
36 AB 57 Procurement Plans (§ 454.5). See, for example, D.04-12-048 (permitting an IOU to enter into contracts under five years in length without Commission preapproval); D.07-12-052 (permitting an IOU to execute a contract under five years in length without Commission preapproval provided that the procurement complies with a procurement limit methodology). On June 2, 2010, the Commission's Energy Division filed a Procurement Policy Manual. The Introduction (at 1-1) states that the Manual presents "all of the requirements and guidance provided by the Commission to its jurisdictional entities under PU Codes 380, 454.5, and 399.11-399.20. This Manual constitutes the upfront and achievable standards and criteria envisioned by the California State Legislature in Assembly Bill (AB) 57."
37 June 17, 2010 Second Amended 2010 Written Plan at 35.
38 SCE does not present an example of its "maximum valuation metric" or show how it compares with recent experience. SCE says that "under no circumstance would the maximum valuation metric exceed the reasonable premium of the last marginal proposal received from the most recent RPS solicitation short list." (Id.) We are not convinced this is reasonable. For example, we are not comfortable allowing SCE to determine what is or is not the "last marginal proposal." Nor are we sure that any particular solicitation, or all solicitations, will result in reasonable results, or that the "last marginal proposal" will, in any or all cases, be reasonable. SCE provides no data from past solicitations of its "last marginal proposal" to demonstrate the selection process or the value.
39 April 9, 2010 Further Amended Draft 2010 Renewable Procurement Plan at 13.
40 See, for example, D.08-02-008 at 35-38; D.09-06-018 at 52-53.
41 For example, IOUs report that they focused on a uniform proposed schedule, a Commission process for approval of RPS contract amendments, and advance authority to procure short-term contracts.
42 MJUs note that the proposal is in relationship to the schedule set in D.08-05-029.
43 January 19, 2010 Comments of CalWEA/LSA at 14-16. For SCE's NDA see June 2010 Second Amended Plan, Attachment 2-10, Form of Seller's Proposal, Exhibits D-1 and D-2. For PG&E's Confidentiality Agreement see June 2, 2010 Solicitation Protocol, Attachment G. For SDG&E's Confidentiality provisions see April 9, 2010 Further Amended Plan, Attachment 1, Appendix A § 11.0.
44 PG&E initially did not oppose disclosure of confidential information by bidders/sellers to the Commission and its staff, but opposed disclosure to the PRG. (January 26, 2010 Reply Comments at 8.) PG&E subsequently opposed any disclosure. (March 8, 2011 Reply Comments on the PD at 4 - 5.)
45 January 26, 2010 Reply Comments at 3.
46 TURN's proposal is not a formal process for bidders/sellers to share information, but TURN says the process is expected to be informal and infrequent.
47 TURN says this includes, for example, information on bids, bidder behavior, project details, contract discussions, summaries of issues under negotiation, and characterizations of requests made by bidders or other counterparties.
