IV. Issues Common to All Plans
We have, in fulfilling our duties and allowing electrical corporations to fulfill theirs, granted electrical corporations considerable flexibility in the way they satisfy RPS program goals. In this context, we have provided guidance, and adopted limited and specific program requirements. We have also taken steps to broaden and enhance the quality of RPS bids and improve the contracting process. Further, we have employed the presumption that utilities are able to use their business judgment in running their solicitations, unless their plans threaten to impair the effectiveness of the RPS program. (D.05-07-039, page 15.)
We continue to do so here. We also provide additional guidance, take limited actions to further expand opportunities, and adopt a schedule to organize the process for 2006. We encourage IOUs to make modifications regarding, and we set boundaries on, certain interactions to neutralize the transaction (i.e., level the field) between parties in order to avoid impairing the effectiveness of the program.
We do this based on comments from IOUs and parties that raise several concerns. These concerns include whether or not additional compliance flexibility should be permitted now, because IOUs foresee potential difficulties about reaching 20% of deliveries by 2010. Concerns have also surfaced about whether or not there is room for discrimination in selection of bidders for the short list, and, as a result, whether there should be increased disclosure of evaluation and selection methods. In fact, as SDG&E says:
"It is plain, however, that despite the measurable progress made to date by the parties involved in the implementation of the RPS program, significant obstacles to the success of the program continue to exist." (Reply Comments, page 2.)
We address below the important obstacles and issues raised by parties. We do so in the context of reaffirming that each electrical corporation 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(c).) The Plans approved herein will be a fundamental, but not necessarily the only, part of that review, as described further 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. Further, 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.
A. Transmission
PG&E's Plan includes a proposal to accept bids from all eligible resources, as defined by the CEC, with delivery points anywhere in California. This would be in addition to the CAISO delivery points authorized by D.05-07-039. Aglet agrees, saying:
"IOUs should be able to contract with renewable suppliers that propose delivery points anywhere in California. Public Utilities Code § 399.11(a) clearly states that the goal of the RPS is to attain 20 percent renewable energy for California, and not just for the CAISO control area. PG&E's proposal is consistent with that goal and deserves serious consideration by the Commission." (Aglet Comments, page 8.)
We approve PG&E's proposal for the reasons stated by Aglet. We were previously concerned about accurately tracking deliveries for RPS compliance. (D.05-07-039, page 33.) We understand that tracking issues are now resolved. This allows us to adopt PG&E's proposal for all three IOUs, to the extent any IOU does not now do so,7 and will help California reach program goals by allowing IOUs to cast "a wider net for projects..." (D.05-07-039, page 10.)
PG&E also proposes to use "typical commercial arrangements" (i.e., remarketing, swaps, transmission adjustment bids) to permit PG&E to accept electricity at a CAISO delivery point and avoid the cost of congestion. (Plan, page 12.) GPI supports this proposal during transmission-constrained episodes. (GPI Comments, page 4.)
We encourage utilities to be creative and innovative in all reasonable ways in order to meet the RPS program goals, both during transmission-constrained and unconstrained times. It is ultimately up to the California Energy Commission (CEC), however, to design and implement an accounting system to verify compliance with the RPS by retail sellers. (§ 399.13(b).) In that context, we remind parties that only those deliveries verified by the CEC in its procurement verification report may be counted toward a utility's RPS requirements. If parties and the CEC develop a verification method that does not apply to a specific contract signed by a utility, or the CEC is unable to verify claimed generation from a particular contract, we will not allow that generation to be counted toward the IOU's RPS obligations. Our authorization for IOUs to seek contracts throughout California is not a substitute for actual verification of procurement by the CEC.
Transmission issues are recognized as presenting potential impediments to achieving RPS goals. We have been examining these issues here and in other proceedings (e.g., Investigation (I.) 00-11-001), and have recently opened a new proceeding to continue that work (I.05-09-005). GPI makes a recommendation in its comments on the 2006 RPS Plans here, however, that we think deserves consideration, since it may increase flexibility and facilitate achieving RPS goals.
GPI asserts that the considerable discussion about transmission (e.g., need, location, cost, cost recovery) has not yet considered an important issue in the larger discussion. That issue is gross versus net cost for RPS-related transmission.
According to GPI, renewable energy will either displace energy from existing plants or new plants. Displacing energy from those plants affects the transmission system. Future transmission needs are different for RPS scenarios versus non-RPS scenarios, but the choice is not between RPS and doing nothing. Rather,
"The choice is between making the transmission improvements needed for 20% renewables, and making the transmission improvements needed for any non-RPS alternative scenario with the same demographics. Looking at the net, rather than the gross, transmission requirements for renewables may alter perspectives on cost allocation issues." (GPI comments, page 3.)
No reply comments oppose GPI's suggestion, and DRA states its support:
"DRA maintains that this transmission-system issue calls for reevaluating the IOUs practice of making the costs of all transmission upgrades necessary for the interconnection of renewable resources part of the costs of those renewable resources. A more comprehensive cost allocation, including the cost of transmission for conventional resources, should be used to put the costs of transmission upgrades for renewable resources in proper perspective." (DRA Reply Comments, pages 2-3.)
We agree that these costs must be viewed in the proper perspective. Determining the cost to attribute to a project depends upon what one considers to be the alternative. If demand for electricity grows, for example, and we assume that demand is met with something other than blackouts, then some alternative makes that electricity available. Whatever the alternative, it has implications with respect to the physical transmission system. It also has implications for cost allocation related to cost recovery, and cost allocation as it may relate to project ranking.
The LCBF methodology requires that projects be ranked on a total cost basis, and that total costs include "indirect costs associated with needed transmission investments..." (§ 399.14(2)(B).) In doing this, however, we have already recognized that it may be reasonable to adjust transmission costs for their net cost:
"Adjustments may also be appropriate if, for example, renewable generation is expected to replace planned non-renewable energy flows in a manner that reduces the need for transmission upgrades. [Footnote deleted.] We will revisit the continued reasonableness of the adopted Transmission Ranking Cost Report and bid evaluation methodologies in future years. We will continue to make improvements as appropriate..." (D.05-07-040, pages 7-8.)
One potential improvement is for IOUs to subtract transmission costs related to a non-RPS scenario from those related to an RPS scenario on a system-wide basis to determine the net costs that should be used for the LCBF analysis. This might be done in large increments of RPS versus non-RPS facilities. The result might be that IOUs and their ratepayers are responsible for the cost of the "backbone" transmission system, with RPS generators responsible in the LCBF ranking analysis only for their reasonable costs of interconnection to the grid (e.g., generation tie lines). This may or may not be consistent with the way an IOU would present cost assessment for a new utility powerplant. That is, "indirect" costs related to a new utility plant would not necessarily include the cost of all secondary and downstream changes to the transmission system, only those to interconnect the new plant to the transmission "backbone." As a result, going forward, the LCBF analysis might reflect the "indirect costs associated with needed transmission investments transmission costs" on a net, not gross, basis.
Parties should continue to present concerns and solutions. Further recommendations on this issue, if any, should be supported with example calculations and information on how such methods would work. Neither GPI nor DRA, however, present a sufficiently developed recommendation here for our adoption.8
We are required to direct electrical corporations to prepare RPS Plans. We must review and accept, modify or reject those Plans. We must review the results of an RPS solicitation submitted for approval and accept or reject proposed contracts based on consistency with the approved Plan. Finally, we are directed to exercise our authority to require compliance with our RPS Plan orders. (§ 399.14(a), (b), (c) and (d).)
In this context, we note parties express considerable concern regarding whether or not transmission will be available to permit compliance with the requirement that 20% of retail sales be obtained from renewable resources by 2010. We are considering this matter in several places, as noted above.
We also point out here, however, that electrical corporations must bring us their concerns and problems along with reasonable proposed solutions in time for us to respond and allow this program to succeed. In a future determination of an electrical corporation's compliance with an RPS Plan and program requirements, we will consider the extent to which the electrical corporation brought a problem to us on a timely basis, and proposed a reasonable and realistic solution. We will not be sympathetic to granting waivers or reducing penalties due to lack of transmission, for example, without the electrical corporation demonstrating that it took all reasonable action to bring the problem to our attention timely, presented realistic solutions, filed applications timely for necessary projects, and took any and all other actions that could reasonably have been expected to address, if not solve, the problem.
B. Compliance
Parties were asked to discuss whether or not the Commission should adopt an IPT greater than the 1% increment required by statute. An IPT of 1.2%, for example, would create a margin of safety toward meeting the 2010 RPS goal of 20%, thereby planning against various risks, including project or contract failure. IOUs oppose this requirement, while it is supported by DRA.
We decline to adopt an IPT of 1.2%, or other specific margin of safety. The IOUs are already engaged in contingency planning. Their contingency planning may or may not ultimately be adequate, but it appears sufficient at this time.
For example, PG&E reports that it seeks to acquire incremental procurement in 2006 of between 1% and 2% of its retail sales volume (between 700 gWh and 1,400 gWh per year). (PG&E Solicitation Protocol, December 22, 2005, page 2.) PG&E says that it intends to include a margin of safety in its procurement. (Reply Comments, page 2.) SCE shows that it is planning to achieve 20% renewables generation as a percentage of bundled sales under the high procurement requirement scenario by 2010. This means that SCE will have in excess of 20% if the base or low procurement scenarios materialize. (SCE Plan, December 22, 2005, page 10.) SDG&E declares that it has adopted a strategy of achieving 24% of its bundled customer retail load served by renewable generation by 2010. (Supplement to Long-Term Procurement Plan, December 6, 2005, page 17.)
There are enough other program issues and details that we do not wish to potentially further complicate the program by adopting either an increased IPT or other margin of safety requirement (along with the possibility of other penalty measures and methods for compliance flexibility). Rather, as SDG&E says "the resources of the Commission and the other parties ...are better put to use in removing the existing roadblocks to the program's success..." (Reply Comments, page 4, emphasis in original.) We agree, given that each IOU already includes a margin of safety in its Plan. IOUs must now meet APT and IPT requirements, or face penalties. IOUs and parties should focus their resources on making the program successful each year at those levels, and by 2010, without Commission-adopted increased incremental goals.
Importantly, IOUs understand that they are ultimately responsible for program success each year and by 2010. For example, SCE says: "SCE is ultimately required to meet its RPS obligations or possibly suffer penalties..." (Reply Comments, page 5.) SCE also says: "SCE is responsible for achieving its RPS procurement obligations..." (Reply Comments, page 9.) SDG&E says: "The utilities are already required to meet incremental procurement targets ("IPTs"), annual procurement targets ("APTs") and the overall 20% target." (Reply Comments, page 4.) PG&E notes that "the Commission has sufficient incentives in place to encourage PG&E to meet its RPS targets, including the consequences for non-compliance discussed in D.03-06-071." (Reply Comments, page 3.)
The RPS Procurement Plans we have adopted before, and adopt here, provide sufficient opportunity for each IOU to succeed. We decline to adopt a larger IPT or other margin of safety. But, we remind IOUs that we are required to enforce our orders if an electrical corporation fails to comply. (§ 399.14(d).) We have every intention of doing so, and encourage all electrical corporations to undertake all reasonable actions to make the RPS program a success.
For example, seller non-performance may be an excuse for an IOU's failure to meet an IPT or APT.9 If an IOU uses seller non-performance as an excuse, however, that IOU must also show that it took all reasonable actions to vigorously pursue necessary IPT and APT goals. This may include an IOU setting and reasonably pursuing its own margins of safety. While we do not adopt an IPT of 1.2%, in exchange we expect an IOU, in any non-compliance defense, to show its plan included a reasonable margin of safety, or it took other reasonable actions, to satisfy its RPS targets.
We will also require a modest amount of additional reporting in exchange for not adopting increased margin of safety targets. Specifically, we direct each IOU to provide us with information on whether each approved RPS project (for which a PPA has been executed between the generator and the IOU, and approved by the Commission) is on target with the project's milestones and projected initial operation date. This information shall be provided with each compliance report (currently due March 1 and August 1 of each year; see D.05-07-039, Ordering Paragraph 17). Energy Division may work with the IOUs to determine an acceptable reporting format.10 Each utility should also make the report available to the fullest extent possible to those on the service list, and any other person or party expressing interest, subject to confidential treatment of protected information.
PG&E and SCE believe the flexible compliance rules need to be modified to allow for full earmarking now, and flexible compliance in 2010. We decline to do so. We encourage IOUs to redouble their efforts to make this program a success no later than 2010, rather than focus limited time and energy of parties and the Commission on modifying the program so IOUs do not later face the potential for penalties. We may or may not give the full earmarking proposal further consideration in the upcoming decision on reporting but, for the reasons explained below, we decline to adopt it here. As we said last year, and repeat here, we consider 2010 the year by which 20% of energy sold to retail end-users is to be delivered from eligible renewable resources. The utilities should too.
The RPS legislation required that we adopt:
"Flexible rules for compliance including, but not limited to, permitting electrical corporations to apply excess procurement in one year to subsequent years or inadequate procurement in one year to no more than the following three years." (§ 399.14(a)(2)(C).)
We adopted initial flexible compliance rules in 2003. (D.03-06-071, pages 40-55.) In doing so, we rejected a California Wind Energy Association (CalWEA) proposal that we characterized as "too rigid" (which included only a three-month extension to make up a deficit). We also rejected a PG&E and SCE proposal that we characterized as the "other extreme" (which included permitting deferral of the entire procurement obligation up to three years with no review or penalties). We adopted a middle ground recommended by The Utility Reform Network (TURN) and SDG&E, the primary elements of which are:
· An IOU must meet 75% of its procurement target each year (with limited exceptions)
· An IOU may carry forward a deficit of up to 25% without explanation for up to three years, but must satisfy the deficit within the three-year period
· A present year procurement target must be met before applying procurement to previous years' deficits
· Annual shortfalls in excess of 25% are permitted upon a demonstration of one of four conditions:
o Insufficient response to an RFO
o Contracts already executed will provide future deliveries sufficient to satisfy current year deficits
o Inadequate public goods funds to cover above-market renewable contract costs
o Seller non-performance (including contract defaults and conditions beyond the control of the utility).
· An IOU is subject to a non-compliance penalty of $0.05 per kilowatt-hour (kWh), with an overall cap at $25 million
As we explained in 2003, these rules permit an IOU reasonable flexibility in meeting its procurement targets, but do not allow it to get so far behind as to jeopardize its ability to make up deficits, jeopardize its ability to meet the overall RPS goals, or compromise any future RFOs. They allow an IOU to engage in good faith efforts to maximize ratepayer benefits and promote orderly renewable resource development, without unnecessarily frustrating RPS program objectives. The penalties provide incentives and clear consequences, establish concrete and transparent rules, and remove uncertainty. Recognizing the program was new, we granted each utility an exemption for the first year. We also found that compliance requirements are not triggered until an IOU is creditworthy.
In 2005, we adopted a PG&E recommendation to modify the flexible compliance rules. This modification permits a utility, in response to a shortfall greater than 25% for a particular year, to demonstrate in its annual compliance filing that contracts already executed will provide incremental future deliveries sufficient to satisfy the current year's deficit. If able to make that demonstration, the utility is permitted to "earmark" the future deliveries to apply first to the portion of the deficit that exceeds 25% in the year of the deficit, rather than to the year of contract delivery, so long as no deficit is carried forward more than three years. (D.05-07-039, Ordering Paragraph 14.)
PG&E and SCE now propose "full earmarking," wherein deliveries from earmarked contracts may satisfy any portion of a prior year's deficit, not just the portion that exceeds 25%.11 PG&E and SCE also propose that flexible compliance rules apply in 2010.
We agree with GPI and DRA that the full earmarking proposal is an effort to roll back the 2010 RPS date, if not all the way back to 2017, then back to somewhere between 2010 and 2017. In combination with flexible compliance for 2010, it pushes the compliance date back to at least 2013.
We rejected such proposals in 2003, and again in 2005, because we wanted to prevent continuous roll-over of the 25% shortfall. Continuous roll-over may permit a utility to fall so far behind in its RPS procurement that it jeopardizes attainment of the program's goals. (D.05-07-039, page 13, citing D.03-06-071, page 49.)
Lack of Evidence: IOUs contend that their procurement decisions now may be affected by our decision regarding earmarking, and may affect the cost of the program. We are not persuaded. No evidence supports this assertion. For example, there is no evidence that the market price referent (MPR) next year will be more than it is this year. There is no evidence that procuring more now compared to later will increase the overall cost of the program at all, or if so, how much. Nor is there evidence that this cost, if any, is greater than the benefits of the renewables program, or greater than the incremental benefits of obtaining program goals sooner.
For example, assume more is procured in 2006 due to our decision to deny full earmarking and flexibility in 2010 compared to the amount procured in 2006 if we allow full earmarking and increased flexibility. Also assume that increased procurement now results in IOUs not being able to negotiate as low a price from an RPS generator as would be the case otherwise. There is no evidence, even given these assumptions, that this sum, if any, is substantial. Moreover, there is no evidence how this sum, if any, compares to the benefits already found by the state of attaining 20% renewables or attaining the benefits earlier. Rather, it is California state policy to attain 20% renewables "for the purposes of increasing diversity, reliability, public health and environmental benefits." (§ 399.11(a).) The decision to attain 20% renewables has already balanced various direct and indirect costs, and determined the benefits justify the target. This policy decision is already constrained by the Market Price Referent (MPR) and the state's willingness to use Supplemental Energy Payments (SEPs), if any. Even if there is a cost to rejecting the recommendation of PG&E and SCE, which we are not convinced there is, we are not persuaded that it is material, that it is greater than the benefits of the program, or that it is greater than the incremental benefits of obtaining program goals sooner.
We also note that, while reporting and compliance are important, we do no want stakeholders to become diverted from the larger picture: 20% no later than 2010. The success of this program will largely be determined by the fundamental economics (e.g., level of RPS generator costs compared to MPRs and the availability of SEPs, if necessary). It will also fundamentally be driven by the vigor and commitment of each electrical corporation to the program's success. We agree with SDG&E when it "asks that all parties remain focused on identifying reasonable and practical implementation strategies that will ensure the best outcome for California." (Reply Comments, page 2.) Parties need to focus on strategies for success.
Future Defenses: Electrical corporations, including IOUs, will have a full opportunity later, if needed, to defend themselves against penalties. That may be a complete defense, and may or may not include showing (a) insufficient response to RFOs, (b) inadequate SEPs to fund above-market costs, (c) seller non-performance independent of IOU's actions, or (d) other reasons.
As we have said before, it is our clear desire never to visit these penalties. IOUs may procure more renewables than the minimum required amounts. The best way to prove parties wrong who believe IOUs are unreasonably resisting this program is for the IOUs voluntarily to procure more than the bare legal requirements, within the MPR and SEPs. (D.03-06-071, pages 52 and 55.) And we repeat: "the utilities' focus should now be on seeking and signing the best possible contracts for renewable energy, rather than on seeking adjustments to compliance standards." (D.05-07-039, page 12.)
Policy of the State: Even if we wanted to adopt full earmarking and flexible compliance now-which we do not-the 20% by 2010 action item is the policy of the state, not just the Commission. That is, this action item was adopted jointly in Energy Action Plan II (EAP II) by the CEC and the Commission, not just the Commission. It was developed with the active participation of California's agencies having energy-related responsibilities, including, but not limited to, the Business, Transportation, and Housing Agency; the Resources Agency; the State and Consumer Services Agency; the CAISO; and the California Environmental Protection Agency (EPA). It was a coordinated implementation of energy policy articulated by the Governor through Executive Orders and instructions to agencies. It implements legislative direction. We decline to unilaterally act in conflict with EAP II, absent further consultation with those involved in EAP II development and adoption. Rather, we are bound by the commitments we agreed to therein, and will not modify them on our own at this time.
Further Evidence: On May 15, 2006, PG&E moved to file a supplement to its reporting and compliance comments. PG&E states that its supplemental comments (including a confidential appendix) provide evidence from its 2005 solicitation to support its full earmarking recommendation. We have given careful consideration to PG&E's further evidence and argument. We are not persuaded by any data, information or assertion therein.
PG&E asserts that "full earmarking will result in customer savings...and avoid sending inappropriate signals to the renewables market." (May 15, 2006 Supplemental Comments, page 1.) According to PG&E, the savings will be "hundreds of millions in costs." (Id.)
To the contrary, program prices payable by PG&E and its customers are already basically constrained to levels no higher than the MPR. Prices above the MPR are typically subject to recovery via SEPs, at no direct cost to PG&E ratepayers. The use of the public's money (e.g., via SEPs) should be left to those public officials authorized to make such decisions. By seeking full earmarking now, PG&E effectively seeks to prevent the Commission from making LCBF decisions, and the CEC from making decisions about the use of SEPs.
That is, RPS contracts are dependent upon Commission approval, with CEC approval of SEPs, if required. If PG&E decides to seek approval (via an advice letter submitted to the Commission) of a contract at a price above MPR, it is reasonable to let the process work itself out. The Commission may or may not approve the contract based on a full range of LCBF or other criteria. If approved by the Commission at a price above MPR but subject to recovery of SEPs, it is reasonable to let the CEC consider the use of SEPs. California citizens may desire the project now, for example, with earlier reduction in greenhouse gases (GHG) compared to another project later with delayed reduction in GHG. That is a weighing and balancing for the CEC to make on behalf of California's citizens based on the availability of SEP funds, and all the evidence and argument that will be presented to the CEC.
Every party, including PG&E, is legitimately concerned about LCBF and total RPS program cost. We are also concerned with meeting all other RPS program purposes and objectives (e.g., resource diversity, reliability, public health, environmental benefits, stable prices, economic development, new employment, reduction in reliance on imported fuels; see § 399.11(a) and (b)). Nonetheless, PG&E's cost concern, as it is reflected in its full earmarking recommendation, is misplaced. It seeks to have decisions made now that need not yet be made until all facts are known, and all competing purposes and objectives are weighed. It also takes decision-making away from the Commission and the CEC, including the balancing of competing public purposes and objectives that will properly be undertaken by each agency.
PG&E is also concerned that rejecting full earmarking now unreasonably gives a preference to projects with shorter lead times over those which might which take longer to develop. PG&E asserts that projects with longer lead times "should not be disadvantaged prematurely." (May 15, 2006 Supplemental Comments, page 3.) To the contrary, this is again a decision to be made by the Commission in its assessment of LCBF and other factors, and the CEC in its application of SEP funds.
Another potential concern with disallowing full earmarking now could be that it will artificially increase demand in the near term. This in turn might cause higher prices from bidders, sending "inappropriate signals" to the market, and result in the signing of more contracts now at higher prices than would otherwise occur (thereby incurring extra "hundreds of millions in costs"). To the contrary, there is a mechanism for relief from higher prices due to a lack of effective competition. (§ 399.14(c).) That is, if the entire supply curve shifts due to lack of effective competition, the Commission may order that contracts be renegotiated, or a new solicitation be conducted. In contrast, moving up or down the supply curve does not itself cause inappropriate price signals or excess costs. Rather, movement along the supply curve may be the normal result of policy decisions that California's public officials should make after weighing all competing interests, with the benefit of all the facts, once presented. Moreover, PG&E and its customers are largely, if not completely, protected as described above by approved contracts being at or below MPR, with costs above MPR generally recoverable via SEPs.
Finally, PG&E's cost concern might actually be a concern about penalty exposure absent full earmarking, since the absence of full earmarking may make it difficult to otherwise reach various procurement targets, according to PG&E. To the contrary, PG&E may, if penalties become an issue, state all necessary defenses at the appropriate time. Those defenses may include, for example, that reasonably priced bids were of insufficient quantity to meet targets, or that bidders were unable to offer sufficient supply within the required year to meet targets. These or other defenses may or may not be sufficient, but will be fully considered at the appropriate time. It is premature to grant full earmarking now based on a concern that may or may not materialize. Rather, existing rules already reasonably balance many competing goals, needs and objectives (e.g., reasonable flexibility while not allowing a utility to get so far behind so as to jeopardize its ability to meet overall goals or compromise future RFOs). As a result, no changes are warranted at this time.
Request for Extension of 2005 Earmarking Deadline: In its May 15, 2006 pleading, PG&E also asks that the earmarking deadline for the 2005 solicitation be deferred from June 30, 2006 to September 30, 2006.12 PG&E gives examples of issues that it asserts need to be resolved, and will make the June 30, 2006 deadline problematic. No party argues to the contrary. No other IOU asks for similar relief. PG&E's request is granted, but only for PG&E.
C. Utility Construction and Ownership
PG&E and SDG&E include utility ownership alternatives in their RFOs. In particular, each shows that a bidder may offer a turnkey agreement or a buyout option after a number of years. SCE does not mention turnkey or buyout options, but allows affiliates of SCE to bid.
We note, however, that neither PG&E, SCE nor SDG&E as a utility company includes any discussion in its Plan of the utility itself building, and then owning and operating, the renewable generation resource. We point out that procure "means that a utility may acquire the renewable output of electric generation facilities that it owns..." (§ 399.14(g).) Also, "[n]othing in this article [Article 16, the RPS statute] is intended to imply that the purchase of electricity from third parties in a wholesale transaction is the preferred method of fulfilling a retail seller's obligation to comply with this article." (Id.)
The law is clear. The utility may procure the renewable generation from itself. There is no preference for compliance through purchases from a third party, including affiliates or others.
The IOUs are apparently not contemplating the building of renewable generation at this time. 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. Deposits and Collateral
For the reasons explained below, we encourage IOUs to reconsider various bid and deposit requirements. We will take the level of deposits into account should an electrical corporation later seek to avoid a non-compliance penalty.
IOUs have different approaches to deposits and collateral. For example, PG&E requires a bid deposit of $3 per kilowatt (kW) upon notice that the bidder qualifies for PG&E's short list. The bid deposit is refundable under most conditions. The bid deposit converts to Project Development Security upon execution of a PPA, and the amount increases to $20/kW. PG&E also requires Commercial Operation Security during the time of commercial operation, with the amount either fixed (e.g., 12 months of revenue for a 20-year contract) or fluctuating (e.g., replacement cost collateral).
SCE requires a Proposal Deposit of $25,000 upon the submission of a proposal. Seller must replace the Proposal Deposit with a Short List Deposit upon notice the bidder qualifies for the short list, but the Proposal Deposit is not returned until later (e.g., upon SCE's rejection of seller's proposal, or upon execution of a PPA; see SCE 2005 Procurement Protocol, page 11, Item 3.05(d)). The Short List Deposit is the greater of zero or net capacity times $3/kW less $25,000.13 The Proposal Deposit and Short List Deposit are refundable under most conditions. Upon execution of a PPA, SCE requires seller to post Performance Assurance in the amount of $20/kW, which is held by SCE as a Development Fee (to ensure seller maintains adequate progress in development of the project by the firm operation date). SCE also requires collateral during the operation of the project to cover a portion of SCE's exposure in the event that the market price for energy supplied to SCE by seller exceeds the energy price during the term of the PPA.
SDG&E's Plan states that SDG&E reserves the unilateral right to evaluate and determine the credit-worthiness of each bidder. Each bidder is required to complete an RFO credit application as part of the offer.14 SDG&E requires that the credit support arrangements (e.g., letter of credit) be negotiated prior to an offer being accepted as a winning offer. SDG&E does not appear to have a specific Proposal Deposit, Bid Deposit, Short List Deposit, Project Development Security, Commercial Operation Security, or similar amounts, but SDG&E reserves the right to negotiate deposits and collateral as it believes necessary.
We addressed bid deposits in D.05-07-039. We noted there that, according to California Wind Energy Association (CalWEA) and Solargenix, a bid deposit could deter qualified bidders or harm negotiations. We also noted that, according to SCE, bid deposits could improve the quality of submitted bids. We determined we had insufficient information to choose between these hypotheses, would not interfere with the IOUs' judgment about the need (or lack thereof) for deposits for 2005, and urged parties to bring evidence of problems with bid deposits for 2005, if any, to our attention.
No party brings any new information to our attention. Aglet restates the position of CalWEA and Solargenix, and says it agrees. Aglet recommends a maximum bid deposit of $3/kW for SCE and SDG&E as used by PG&E.
Given the absence of specific new evidence, we decline to adopt Aglet's recommendation. Nonetheless, we make the following observation. PG&E does not require a bid deposit until a bidder is selected for the short list. In contrast, SCE requires a bidder to deposit $25,000 simply to submit a bid. While the deposit is refundable, that is a deposit of $25/kW for a 1 MW project. That seems to be an excessive amount, and an unreasonable requirement for a project simply to submit a bid.
SCE believes its approach improves the quality of bids, and may alleviate later financial losses should a project otherwise fail. DRA correctly points out, however, that this is a balance of risk between "margin of safety" (with avoidance of project failures) and facilitating the development of desirable projects. (DRA Comments, page 4.) To mitigate barriers to program success, we think the better balance is to have more projects, not less, submit bids for evaluation. In fact, SCE observes that:
"the developers' views of what RPS-eligible renewable resources are likely to be available is at least as important, if not more important, than the utilities' views, because the developers are uniquely situated to know whether or not particular resources are worth developing and bidding into a utility solicitation." (Plan, December 22, 2005, page 18.)
We do not direct SCE to change its deposit amount or practice, but encourage SCE to reconsider and adopt a scheme more in line with that of PG&E: no Proposal Deposit, a Bid Deposit of $3/kW once the project is on the short list, and full refund of the deposit including interest under most conditions. We similarly decline to direct SDG&E to adopt any particular deposit amounts or practice, but also recommend that SDG&E employ equally reasonable criteria.
We will take the level of deposits into account should an electrical corporation later seek to avoid a non-compliance penalty. That is, if an electrical corporation later faces a non-compliance penalty but seeks reduction or waiver of that penalty, that corporation must make a showing that its deposit requirements were reasonable compared to those of PG&E, and that its deposit scheme did not prevent otherwise viable projects from coming forward at least for evaluation. We again urge parties to bring evidence of problems with bid deposits, if any, to our attention.
We similarly make no orders regarding other collateral requirements of the IOUs (e.g., Project Development Security, Commercial Operation Security, Performance Assurance Deposits, Development Fees, other collateral). Nonetheless, just as with bid deposits, we might take the level of other collateral into account should an electrical corporation later seek to avoid a non-compliance penalty. We again urge parties to bring evidence of problems with collateral, if any, to our attention.
E. Resource Stacks
The LCBF Plan must include an assessment of portfolio supplies to determine the optimal mix of renewable resources with various deliverability characteristics. (§ 399.14(a)(3)(A).) In its discussion of supplies, PG&E's Plan addresses various resource types and the optimal mix based on PG&E's need. PG&E's Procurement Protocol states that, for turnkey proposals, it has a strong preference for small hydro and central station solar. At least some parties appear to have interpreted this as continued use of "resource stacks."
On the other hand, SCE states that:
"...the development of a `resource stack' of preferred or projected future renewable procurement has limited benefits...Moreover, given SCE's experience with recent solicitations, resource types cannot be definitely 'ranked;' therefore, a resource stack may be at odds with the least-cost/best-fit evaluation standards imposed by the RPS legislation. SCE also does not have an institutional preference for a particular resource mix or technology type, and the RPS legislation does not require any specific mix of technology types." (Plan, December 22, 2005, pages 18-19.)
We agree with SCE. We have noted the dangers of using resource stacks to pre-screen or discourage bids, and stated that we do not want resource stacks to act as hidden weighting factors in bid evaluations. (D.05-07-039, page 7.) In its reply comments, PG&E clarifies that "PG&E has previously explained that it would evaluate bids on a case by case basis, instead of using a resource stack to select its contacts." (Reply Comments, page 12.) We are satisfied that the IOUs are not using resource stacks.
PG&E, however, should not state a preference for particular resource types in its Plan Protocol. This may unreasonably discourage bids, or act as a hidden weighting factor. The Plan might generally assess portfolio supplies to determine the optimal mix of renewable resources with various deliverability characteristics. (§ 399.14(a)(3)(A)). Any specifics in the Plan, Plan Protocol and RFO, however, must be renewable resource neutral. Therefore, PG&E must amend its Plan, Plan Protocol and RFO as necessary to remove any specific statements of preference for renewable resource types (e.g., section titled "Ownership Alternatives, Turnkey Agreement;" elsewhere, as necessary).
F. CAISO Market Redesign
IOUs were asked to analyze and justify any proposed contract terms that would be effective upon implementation of CAISO market redesign.
PG&E points out that upon implementation of CAISO market redesign, transmission under CAISO tariffs will change from a zonal to a nodal basis. This affects the definition of "delivery point." PG&E proposes language that recognizes a change in the delivery point if the CAISO market redesign occurs. PG&E states the language is the result of extensive negotiations with interested parties in a successful attempt to address the risk of potential transportation charges that might emerge during the 10-20 year term of a PPA.
SCE does not propose a contract term concerning market redesign. Rather, SCE believes it is inappropriate to adopt a standard contract term allocating risk associated with delivery in the event of market redesign. SCE contends the appropriateness of such terms depend upon unique circumstances and should be individually negotiated.
SDG&E also proposes a contract term pertaining to the definition of delivery point upon CAISO market redesign. SDG&E says it expressly reserves the right to revise the draft RFO as necessary, pending conclusion of the 2005 solicitation evaluation.
PG&E and SDG&E each make their own proposal. Each should be permitted to employ their proposed contract term.
Aglet agrees with SCE that there may be complex issues related to risk associated with market redesign, but points out that the basic language used by PG&E and SDG&E provide protection to the utility, its ratepayers and suppliers. Aglet recommends SCE be ordered to adopt similar language. We agree.
SCE contends we should decline to allow relitigation of the issue of standard terms and conditions, and should reject Aglet's recommendation. To the contrary, the Ruling on the 2006 RPS Program specifically asked parties to address this issue. (Ruling dated November 9, 2005, page 3.) While we generally agree with SCE that IOUs should be able to use their best business judgment, we oppose individual negotiation on such a standard term. SCE shall amend its Plan and RFO to include language substantially similar to that proposed by either PG&E or SDG&E, as SCE determines best for its area (with specific references, of course, to the SCE area, as necessary).
G. Bid Selection, Evaluation, and Potential Discrimination
Each Plan describes the evaluation criteria the IOU will use to rank bids.15 It is clear from these descriptions that the evaluation process allows room for judgment. For example, PG&E specifically says one difference between its 2005 and 2006 solicitation process is that in 2006 the quantitative weightings have been eliminated, providing more flexibility and accommodation to the wide range of technologies and specific project circumstances.
Aglet is concerned with the role of judgment in the selection process, and asks: "what assurance does the Commission have that the final selection will not discriminate against a particular technology?" (Comments, page 3.) We share this concern. It is our responsibility, on behalf of the state's ratepayers and businesses, to approve a program and process that is fair and equitable. Further, it must be equitable not only between technologies but also be nondiscriminatory between bidders within a technology.
To cure this problem, Aglet recommends that each utility's contract evaluation model be determined before, not after, bids are received. At a minimum, Aglet recommends that each IOU present the Commission with a description of its contract evaluation model, inputs, and how inputs are to be weighed. DRA strongly agrees. (DRA Reply Comments, pages 1-2.) In response, IOUs argue for increased, not decreased, flexibility in the selection process. IOUs recommend against micromanagement of the procurement process. PG&E asserts that:
"Requiring the micro justification described by Aglet would be to place a straightjacket on PG&E at a time when it is important to understand the commercial viability of a project. The utility must be able to exercise its business judgment..." (Reply Comments, page 12.)
We agree with the concerns expressed by Aglet and DRA, but conclude that the RPS project evaluation and selection process within the LCBF framework cannot ultimately be reduced to mathematical models and rules that totally eliminate the use of judgment. Rather, the process of negotiating the lowest price while shaping the best fit can involve give-and-take between bidder and IOU, and judgment by each party. We do not seek to eliminate the reasonable and proper use of judgment by any participant, including IOUs, bidders, parties and the Commission. Nonetheless, because we agree with the concerns of Aglet and DRA regarding the potential for discrimination and bias in the project evaluation and selection process, along with the need for a fair and equitable procedure, we take several steps to address these concerns now, short of adopting standard offers.16
First, we adopt Aglet's "minimalist" recommendation. That is, we require certain information, but decline to determine each IOU's modeling method before bids are received. We think an order now that requires IOUs to file more information on evaluation models, with comments and replies by parties followed by a subsequent Commission decision before bids are received, would unreasonably divert limited resources of parties and the Commission, and unduly delay the process.
Rather, we will require each utility to provide a report when it submits its short list of bids. Each utility should also serve a copy on the service list, and make the report available to the fullest extent possible to any other person or party expressing interest, subject to confidential treatment of protected information. The report shall explain each utility's evaluation and selection model, its process, and its decision rationale with respect to each bid, both selected and rejected. We are confident each utility can craft such report. We will hold each utility to the requirement of submitting a reasonable report consistent with our previous direction that "utilities should make their evaluation process transparent to their Procurement Review Groups and the Commission." (D.05-07-039, page 7.)
To assist each IOU complete that goal, however, we note certain elements that should be in each report. For example, it should start with an executive summary that summarizes the model, process, all bids (both winning and losing), prices, the evaluation of each bid, and any other relevant summary information. In more detail, subsequent chapters of the report should describe each IOU's evaluation criteria, selection model and the process used. It should contain a table, matrix or other device to show all evaluation factors used (both quantitative and qualitative). For the quantitative elements, it should show the bid's all-in electricity price, the most recently adopted applicable MPR, the scoring of each quantitative factor, and the final quantitative score. For the qualitative elements, it should contain a narrative description of each qualitative factor, and the evaluation of each qualitative factor for each project as it was used in the final selection process. It should conclude with the final result for each project. It must contain anything else reasonably necessary for a full and complete explanation to the Commission of the evaluation and selection process by the IOU.
Energy Division may, but is not required to, work with the IOUs on a format for this report and may, if it wishes, specify a format. That format should be designed to assist Energy Division (plus the Procurement Review Group (PRG) and others who are involved) assess the projects as they work their way through the evaluation process. It should eventually make approval of the Advice Letter (AL) for specific projects routine, since a standard format is used throughout the process, and data is updated as necessary for quick assessment.
We note that in this context the report may serve as a screening tool. We encourage IOUs and Energy Division to consider its use in that way. As such, it may potentially become more complete as the process unfolds.
For example, it may be used early in the process to initially screen projects. When more data is available (e.g., MPR), the data may be entered and the tool updated. Using the same tool with updated information, assessment, analysis and conclusions should help make the process transparent and easy to follow. It should also simplify the review of the ALs for specific projects.
Finally, if different, each IOU shall separately submit a copy of each important decision document used by the IOU's management to reach critical intermediate decisions, along with the final evaluation and selection.
Because of the complexity, importance, and potential for conflicts and disputes, we also require each IOU to use an Independent Evaluator to separately evaluate and report on the IOU's entire solicitation, evaluation and selection process for this and all future solicitations. This will serve as an independent check on the process and final selections. The Independent Evaluator's preliminary report should be provided with the IOU's short list, and a final report with the AL for approval of selected bids. This requirement is independent of whether or not there are utility owned or utility affiliated projects under consideration.
The costs of the Independent Evaluator may be entered into the Long Term Procurement Memorandum Account or other appropriate account. (See D.05-07-039 and D.04-12-048). Each IOU should consult with the PRG and Energy Division Director before selecting the Independent Evaluator. To the fullest extent feasible, each IOU should seek to follow the advice of the PRG and Energy Division Director on the selection, and subsequent management, of the Independent Evaluator. In addition, as we stated in D.04-12-048, each IOU shall allow periodic oversight by the Commission's Energy Division, and shall coordinate to a reasonable degree with assigned Energy Division management and staff as a check on the process. The Independent Evaluator shall also make periodic presentations regarding its findings to the IOU and the IOU's PRG. (See, D.04-12-048, Findings of Fact 94-95; Ordering Paragraph 28.) Our intent is to preserve the independence of the Independent Evaluator by ensuring free and unfettered communication between the Independent Evaluator and the Commission's Energy Division, and an open, fair, and transparent process that the PRG can confirm.
3. Workshops and Use of Alternative Dispute Resolution Procedures
The November 9, 2005 Ruling directed IOUs to include a discussion of specific plans for pursuit of wind repowering. On this topic, SCE states that it sent a letter to existing wind projects soliciting interest in repowering and expansion. SCE also discussed repowering and expansion at the 2005 bidders' conference. SCE reports that it received very limited interest. According to SCE, it is unclear what has caused such a low level of response from the wind industry given their frequent public statements of interest in repowering and expansion. SCE says it is willing to sponsor a workshop specifically aimed at identifying the issues and potential solutions that would encourage a more robust response from existing projects.
We encourage SCE to do so, even though SCE does not need specific encouragement from us to conduct a workshop. Rather, IOUs are already under our direction to secure 20% renewables by 2010, and are potentially subject to penalties if they do not. That should be encouragement enough.
We re-emphasize that SCE, as all IOUs, should undertake all reasonable actions to reach the RPS goal. If that involves conducting a workshop, we are confident that SCE will do so. If SCE is later subject to penalties, but seeks reduction or waiver of those penalties, we will include in that assessment whether or not SCE took all reasonable actions, such as whether or not it conducted workshops. The burden will be on SCE to establish that it in fact took all reasonable steps, but the industry simply did not respond at the level of MPRs and SEPs.
There may or may not, however, be other tools that might be useful to advance program goals. For example, IOUs, RPS generators, and/or industry groups should consider taking advantage of resources for ADR at the Commission.
In particular, the Commission has encouraged ADR for more than two decades, and we have facilitated and approved many settlements since the 1980s. Most recently, we have adopted an expanded ADR program under the supervision of the Chief ALJ. (See Resolution ALJ-185, August 25, 2005.) We encourage parties to take advantage of our program, which includes facilitation, mediation, arbitration and early neutral evaluation.
We note with approval that SCE states a seller has no liability to SCE for certain damages "provided that Seller uses commercially reasonable efforts in developing and submitting such forecast to SCE." (PPA, § 3.10(d).) SCE pledges that it "shall in good faith work with Seller" under certain conditions. (Id., § 10.05.) Similarly, PG&E pledges that certain approvals will "not to be unreasonably withheld." (Solicitation Protocol, Attachment I, Master PPA for Firm Product, § 3.7(b).)
We encourage IOUs to include such language throughout their Plans, RFOs, and PPAs, as appropriate. In this way, burdens are shared and equal between parties, and obligations are neither one-sided nor unfair. The duty here is for good faith, fair dealing, and reasonable behavior by both parties.
To the extent not now clear in the Plans and proposed PPAs, each Plan and PPA should be amended to incorporate a term which requires equal treatment, fair dealing, reasonable behavior, and good faith performance from each party.17 This should be included as a general term early in the PPA, making clear that this expectation applies to both parties throughout the entire agreement.
Each IOU's Plan states many disclaimers which allow it to reject offers and/or terminate the solicitation.18 We do not limit these disclaimers per se. Nonetheless, we note that each IOU reserves for itself considerable discretion not normally available in the framework of either tariffs (when the IOU is a seller) or standard offers (when the IOU is a buyer).
We expect each IOU to achieve the 20% by 2010 requirement, absent appropriate application of flexible compliance rules. We will hold each IOU to having undertaken all reasonable action to achieve that requirement. As such, each IOU may wish to reconsider the tone and nature of its disclaimers. Each IOU may wish to present a Plan that focuses more on the many positive ways it intends to accomplish the state policy to have 20% renewables by 2010, and how it will work with all stakeholders in reasonable ways to make that happen.
H. Evaluation Criteria, Environmental Stewardship and Water Action Plan
In adopting the RPS legislation, the Legislature specifically found and declared (§ 399.11) that increasing California's reliance on renewable energy resources to reach the target of 20% promotes the purposes of, and may do, each of the following:
· increase the diversity, reliability, public health and environmental benefits of the energy mix
· promote stable electricity prices
· protect public health
· improve environmental quality
· stimulate sustainable economic development
· create new employment opportunities
· reduce reliance on imported fuels
· ameliorate air quality problems
· improve public health by reducing the burning of fossil fuels
Further, the Legislature specifically stated that each electrical corporation, in soliciting and procuring renewable energy, "may give preference to projects that provide tangible demonstrable benefits to communities with a plurality of minority or low-income populations." (§ 399.14(a)(5).)
We have discussed these and other potential benefits from RPS generation, and bidders are encouraged to describe these benefits, if any, in their bids. We have directed IOUs to make it known in their Plans that such benefits are sought, and apply transparent criteria to evaluating such claims. (D.03-06-071, page 37.) We have further discussed this assessment by application of quantitative and qualitative factors used in bid evaluation. (D.04-07-029, page 28; also Findings of Fact 27 and 28.)
IOUs' Plans differ on their treatment of these factors. For example, some plans list several of these factors (e.g., PG&E and SDG&E). Others only say attributes identified by the Commission will be used as tie-breakers (e.g., SCE).19
Because we have directed IOUs to make it known in their Plans that such benefits are sought, and apply transparent criteria to evaluating such claims, we believe each IOU can and should do a better and more consistent job of actually stating the specific criteria and encouraging bidders to state such benefits, if any, in their offers. Thus, each IOU should amend its Plan to do a better job of specifically identifying and stating each factor found and declared by the Legislature, and discussed in our decisions, along with specifically encouraging bidders to address such benefits, if any.
Among the criteria and benefits to consider is environmental stewardship. We include environmental stewardship as a qualitative factor for IOUs to consider when evaluating bids. (D.03-06-071, page 37; D.04-07-029, page 29.)
Our interest in the environment and environmental stewardship includes our air, land and water. IOUs must consider all aspects of the environment in their assessments. Since our last RPS decision, we have taken further action regarding environmental matters. We take this opportunity to link these actions.
In particular, on December 15, 2005, we adopted a Water Action Plan. Among our action items is:
· Educate water industry stakeholders regarding policies and practices which reduce water and energy consumption. (Water Action Plan, page 7.)
· Consider energy use as an important outcome of all water policy decisions and work toward a 10% reduction in energy consumption by the utilities over the next three years. (Water Action Plan, page 10.)
· Collaborate with the California EPA to reduce California greenhouse gas (GHG) emissions. (Water Action Plan, page 11.)
Environmental stewardship requires balancing all competing demands and supplies of precious resources to reach the best outcomes. We clarify here that environmental stewardship includes the environmental impacts of the proposed RPS generation facility on California's water quality and use. RPS projects which provide particular benefits in helping us achieve responsible and reasonable water quality, use and improved water resource management consistent with our Water Action Plan, EAP II, and environmental stewardship generally, are encouraged to identify such benefits in their proposals. IOUs are expected to include this factor in their "transparent criteria in evaluating such claims." (D.03-06-071, page 37.)
I. Multiple Bids
PG&E does not permit a bidder to simultaneously submit competing offers to other electricity corporations.20 In contrast, SDG&E permits a bidder to submit competing offers to other electrical corporations, but the bidder must withdraw the offer from other solicitations once the bidder is selected for SDG&E's short list. (SDG&E Draft RFO, December 22, 2005, page 14 of 30.) SCE's approach is similar to that of SDG&E.21 SDG&E's approach is superior, and PG&E is directed to amend its RFO to allow simultaneous bids in the same manner as SDG&E for the reasons stated below.
We found for the 2004 Solicitation that it is "reasonable to permit bidders to participate in more than one utility's RPS solicitation." (D.04-07-029, page 41, Finding of Fact 5.) We also found that "all bids should be treated as potentially multiple until the bids are short-listed and negotiations begin." (D.04-07-029, page 42, Finding of Fact 13.) Nothing is presented here to convince us to change that view.
Competition is diminished to the extent potential buyers and sellers face barriers to making trades, and is increased to the extent unreasonable barriers are removed. In this case, competition is reasonably increased by allowing simultaneous bids to more than one electricity corporation, at least to the point that the bidder is selected for the short list. This facilitates the fullest presentation of projects and information to the market so that buyers can make a wise selection between choices. Because of different evaluation criteria, the same project might be rejected by one IOU but selected by another. Allowing simultaneous bids is the best way to make sure the project gets full consideration.22
In the interest of promoting competition, promoting full consideration of all proposals, and removing barriers to the effectiveness of the RPS program, we direct, as we did in D.04-07-029, that bidders may bid into multiple solicitations, and bids are to be treated as potentially multiple until the short lists are created. Any IOU Plan that provides otherwise must be amended.
J. Timing of Next Solicitation and Compliance for 2006
In the November 9, 2005 Ruling, IOUs were asked to address the possibility of a firm deadline for submission of contracts for Commission approval. In response, IOUs generally oppose firm deadlines, arguing that "flexibility is the key to a successfully managed power procurement solicitation." (PG&E Plan, December 22, 2005, page 10.) Both PG&E and SCE state they intend to conduct a solicitation in 2006, but SDG&E says it has not yet decided. SDG&E says it will make its final decision after conclusion of negotiations with bidders in its 2005 solicitation. (SDG&E Procurement Plan, page 4.)
In its comments, DRA recommends that IOUs follow a competitive simultaneous bid process, which DRA believes is consistent with the periodic determinations of MPRs and SEPs in the RPS statutes. Aglet recommends SDG&E conduct a solicitation in 2006. In reply comments, IOUs argue against micromanagement and "a one-size-fits-all time period for contract negotiations." (SDG&E Reply Comments, page 6.)
Annual Framework: Our approach so far has been one of giving IOUs flexibility largely within an annual framework. This is consistent with the RPS legislation which, for example, contemplates annual procurement targets. (§ 399.14(a)(3).) At the same time, however, the legislation does not specify the frequency of RPS solicitations. It also does not state the cycle for determining the MPR, other than "after the closing date of a competitive solicitation." (§ 399.14(a)(2)(A).)
There may be a tension here between two approaches. On the one hand, the process might be very structured, with electric corporations' annual bid solicitations beginning and ending on the same dates, plus the same dates for evaluations, determinations of MPR, annual compliance reviews, and submission of contracts to Commission approval. Alternatively, the process might essentially be continuous, flexible and open to all renewable generation sellers at all times.23 In this second approach there might be periodic determination of MPRs (e.g., so that projects may seek SEPs, as necessary), with procurements measured annually for purposes of determining APT and IPT compliance (including the application of flexible compliance rules).
We do not here make a final determination on approach. Nonetheless, we are not persuaded by IOUs' desire for broad flexibility to determine not only when, but if, they begin and end a solicitation, particularly given concerns expressed by nearly all parties regarding whether or not RPS targets may be reached by 2010. Until we are able to explore the merits, if any, of a more continuous process, the next round needs reasonable structure, similar to that which we have used to date, with a renewed focus on seeking to reach program targets.
As SCE candidly notes, there "are advantages and disadvantages to imposing a firm contracting deadline." (SCE Procurement Plan, page 16.) While parties need sufficient time to resolve and negotiate matters, we are persuaded by SCE and UCS that one lesson learned from SCE's protracted 2003 solicitation is that "a final cutoff for submitting contracts to the Commission for approval can operate as a catalyst to resolving outstanding issues in negotiations." (Id.) UCS says it "agrees with SCE, as a Commission-imposed deadline on SCE's 2003 solicitation resulted in swift finality and signed contracts." (Comments, page 3.)
We accomplish this by adopting the same RPS Solicitation Timeline employed for prior solicitations, with limited additional guidance. In particular, we set dates and time intervals with the flexibility to modify those intervals if necessary. (See D.05-12-042, Appendix B; also see this order, Appendix A.)
We encourage parties to follow the schedule in Appendix A to this order. We authorize the Energy Division Director, in administration of this program, to modify the dates on Energy Division's own initiative, as necessary, in order to bring the next solicitation to conclusion by the end of 2006 or early 2007. If a party desires modification, the party may seek an extension by letter or electronic mail to the Executive Director, with copy to the Energy Division Director. (See Rule 48(b).24)
Contracts for 2006 Targets: We previously granted IOUs, at their option, the ability to treat contracts resulting from the 2005 RPS solicitation and signed on or before June 30, 2006, as available to demonstrate compliance with their 2005 APT, for the event of deficits greater than 25%. (D.05-07-039, Ordering Paragraph 15.) Given the timing of the 2006 solicitation cycle, we again believe it reasonable to grant IOUs, at their option, the ability to treat contracts resulting from the 2006 RPS solicitation, but signed after December 31, 2006, as available to demonstrate compliance with their 2006 APT, for the event of deficits greater than 25%. Given the schedule adopted in Appendix A, however, the deadline for the 2006 solicitation need not be June 30, 2007. Rather, IOUs may, at their option, treat contracts resulting from the 2006 RPS solicitation and signed by the later of December 31, 2006, or within 45 days after the Commission adopts the resolution approving the PPAs from the 2006 solicitation, as available to demonstrate compliance with their 2006 APT, in the event of deficits in greater than 25%. By the schedule in Attachment A, that will most likely mean a date before June 2007.
2007 RPS Plan Cycle: In our continuing efforts to move toward a calendar year solicitation cycle, we adopt the approach used in developing and reviewing the 2006 Plans for the next solicitation cycle. (D.05-07-039, page 29.) That is, we expect the filing and service of 2007 draft RPS plans and draft RFOs later this year. The specific schedule will be set by the Assigned Commissioner or ALJ. Moreover, as we have also done before, we authorize the Assigned Commissioner to assess the adequacy of Transmission Ranking Cost Reports (TRCRs) used in the LCBF ranking of bids. (D.04-06-013, D.05-07-040.) The Assigned Commissioner or ALJ should set dates, as needed, for utilities to request information for the TRCRs, to file draft TRCRs, and for parties to file comments and replies on the draft TRCRs. The Assigned Commissioner should then assess the adequacy of the draft TRCRs, and determine whether the reports should be modified or other steps taken before the results are used in the ranking of bids. (D.05-07-040, Ordering Paragraph 7.)
Adjustments to 2006 Plan Schedule: In comments on the draft decision, several parties recommend more time in each of several parts of the timeline. We adopt some, but not all recommendations, and further adjust the schedule to focus on completion in 2006.
For example, we are persuaded by parties to grant more time for IOUs to file amended RPS Plans.25 We also provide time (which had not been specifically identified previously) for IOUs to validate and clarify bids, as recommended by SCE. We compress time for calculation of the draft MPR (since it may be calculated simultaneously with other events, as long as it is not published before the solicitation is closed). We compress Commission time in other places where possible (e.g., timeline for preparation of draft resolution approving some or all PPAs).
We grant more time for parties to negotiate and execute PPAs after IOUs submit their short lists, but not the full 90 days recommended by some parties. Rather, RPS generators and IOUs should be fully engaged in negotiating and resolving issues as necessary through the entire process. They should not wait until the short list is developed. Each RPS generator's bid should be reasonably complete when submitted, and subsequent negotiations should be focused and limited. IOUs should develop their short lists with all, or nearly all, issues resolved, including price. Each IOU may sort its short list by price once the MPR is adopted. Although we grant some additional time, we are not persuaded that parties should need a great deal of additional time to further negotiate and execute the PPA once the short list is developed.
Unless and until parties recommend-and we adopt-RPS solicitations that are essentially continuous, we want to move this process to an annual cycle that is completed at the end of each calendar year, to the fullest extent possible. As such, this solicitation cycle should be completed by the end of 2006, and we adopt a schedule with that in mind. As provided above, however, the Energy Division Director may adjust the schedule, and parties may ask for more time, to the extent necessary. Nonetheless, we expect all parties to move the 2006 solicitation process forward reasonably and without delay, unless particular facts or individual circumstances arise that necessitate and justify the granting of more time.
K. Other items
SCE states it will seek to "procure the difference between its high procurement needs obligation...and the amount of contracted-for output available in 2010 from its 2005 solicitation." (Plan, page 10.) Aglet suggests that SCE spread its procurement over four years (2006-2009) instead of attempting to procure all its remaining needs in 2006. As such, Aglet recommends that SCE set a minimum procurement goal in 2006 of 25% of the difference between its high needs obligation and the amount of contracted for output. (Aglet Comments, page 7.) We disagree, and reject Aglet's recommendation.
The state's RPS goal is not 20% in 2010, but 20% by 2010.26 There is nothing that reasonably prohibits reaching this goal before 2010. While parties talk generally about incurring too much cost by agreeing to contracts now versus later, they provide no specific or compelling evidence. For example, we have no good estimate at this time of whether the MPR will be more or less next year than this year. Moreover, the program itself is designed to control costs. That is, no bids above the MPR need to be accepted by IOUs, nor approved by the Commission. Thus, ratepayers are never burdened with costs above the reasonable long-term cost of the alternative. Whether or not the state incurs costs above the "market" cost via SEPs is a decision for the CEC, taking into account all the factors that will properly be before them. We reject Aglet's suggestion, and strongly encourage each IOU to aggressively pursue RPS generation now.
Parties comment on several other items, such as confidential treatment of elements of each Plan and use of Renewable Energy Credits (RECs). Confidentiality has been, or will be, addressed soon by ALJ Ruling. Other important matters will be decided soon by subsequent Commission decision.
7 SDG&E says it currently accepts offers from projects anywhere in California.
8 GPI asks that this issue be addressed in R.05-09-005. To do so, GPI should make specific proposals there, to the extent consistent with the issues and schedule in the Assigned Commissioner's Scoping Memo for that proceeding.
9 See D.03-06-071, page 50. Seller non-performance includes contract default, force majeure, terminations, and project development delays, assuming non-performance is due to factors beyond the control of the utility. No IOU excuse is permitted if the IOU was responsible for the seller's non-performance.
10 Among other things, we may use this to help assess whether an IOU had (or should have had) reasonable expectation or knowledge of upcoming non-compliance, and should have taken more aggressive action in order to avoid potentially being liable for a non-compliance penalty. Each IOU should notify Energy Division when a major milestone is missed.
11 PG&E says that certain references to APT should be to IPT, citing D.04-06-014, Appendix B, page B-2 in support. (PG&E Comments, page 2, footnote 2.) As a result, PG&E explains that its comments refer to IPT, not APT. We understand the proposal here to be with respect to IPT. We expect to address the treatment of APT and IPT, as used for reporting and flexible compliance, in a decision in the near future and there reconcile confusion, if any. We do not need to address the APT and IPT distinction here, however, to dispose of the proposal.
12 The June 30, 2006 date is set in D.05-07-039, ordering paragraph 15.
13 The formula means that projects of 8,333 kW and smaller have a Short List Deposit of zero, and projects over 8,333 kW have an increasing deposit amount. For example, a 5 megawatt (MW) project would have a Project Deposit of $25,000 and a Short List Deposit of zero, for a total deposit of $25,000. A 10 MW project would have a Proposal Deposit of $25,000 and a Short List Deposit of $5,000, for a total deposit of $30,000.
14 The credit application was not submitted with the 2006 Plan. Bidders are referred to an RFO website for the application. The website address, however, indicates it is "TBD." We understand this to be "To Be Determined."
15 For example:
PG&E states it will use: market valuation (either as "forwards" or "options" with consideration of debt equivalents), portfolio fit, non-price factors (credit, project status, technology viability), transmission adders, integration costs, and other non-price considerations (social, reliability, environmental, resource diversity, transmission network benefits, modification to solicitation requirements and agreement). (Plan Protocol, pages 25-28.)
SCE states it will take into account the criteria expressed in the Commission's LCBF decision (D.04-07-029), and will specifically employ a production simulation model to calculate total system production costs and benefits (incorporating effective load carrying capacity values, transmission costs, and integration costs and benefits), plus debt equivalence, credit and seller qualifications, and will use other attributes as tie-breakers. (RFO, pages 14-15.)
SDG&E states it will evaluate offers on the basis of an LCBF analysis with three components having primary importance (delivered energy cost, overall fit with SDG&E's resource portfolio, transmission system upgrade costs), with high emphasis on the offer prices not only as initial cost but long-term cost, and differentiation of similar cost offers using several factors (e.g., location, benefits to minority and low income areas, resource diversity, environmental stewardship, delivery reliability, ability to advance schedule, technology, operational flexibility, development risk, financing plan, corporate capabilities). (RFO, pages 21-23.)
16 A standard offer for buying electricity is similar to a standard tariff for selling electricity. It eliminates undue discrimination on the basis of project, price, bidder, technology or type.
17 Such term might be modeled, in part, after an item commonly in the General Terms and Conditions section of telecommunications interconnection agreements. For example, in the recent interconnection agreement arbitration between AT&T California and Verizon Access Transmission Services, parties agreed to the following term: "Each party shall act in good faith in its performance under this agreement and, in each case in which a Party's consent or agreement is required or requested hereunder, such Party shall not unreasonably withhold or delay such consent or agreement." (Application (A.) 05-05-027.)
18 See, for example, PG&E Solicitation Protocol, Item I.C., page 1; SCE 2005 RFP, § 1.02; and SDG&D Draft RFO, Items 1.0 (e.g., paragraph 2) and 10.0.
19 SCE's Plan identifies these other factors under tie-breakers, and says "SCE will utilize those attributes identified in D.04-04-026 [sic] as quantitative methods for evaluating tie-breakers." (SCE 2005 RFP, Item 5.02, page 15.) It is unclear if SCE means to refer to the R.04-04-026, or to D.04-07-029 (where quantitative and qualitative factors are addressed). SCE should make this clear. More importantly, however, as we direct in this order, SCE must state each quantitative and qualitative criterion and solicit bidders to address such benefits, if any, within these criteria.
20 PG&E requires that the bidder state it has not provided, and will not provide, during the time the offer is deemed binding, an offer to another party. (Solicitation Protocol, Attachment A, page 1, item F.) Bidders submitting offers are bound by their offers for a period of 9 to 12 months from the date of submittal. (Solicitation Protocol, page 5, Item IV.A.) In comments on the draft decision, PG&E asserts it actually permits bidders to participate in multiple solicitations but, once the project is short-listed, the bidder must commit its project to PG&E or withdraw its bid, citing page 7 of its Solicitation Protocol in support. (PG&E Comments on Draft Decision, May 15, 2006, page 14.) Page 7 of the Solicitation Protocol, however, says if the bidder does not notify PG&E of its intent to withdraw then the bidder's offer "will remain binding." (Emphasis added.) To remain binding, it must have been previously binding.
21 SCE requires that the seller grant SCE exclusive negotiating rights within five days of being notified the seller has been selected for SCE's final short list. (RFO, page 13, Item 4.02.) This is understood to mean that sellers may offer and negotiate simultaneous bids until selected for the final short list.
22 For example, even if the bid price to each utility is the same, and the MPR is the same between the two utilities (so that the preliminary least cost comparison is the same), the ranking of bids by price, LCBF and other quantitative and quantitative factors might be different between the utilities. This might be because there may be a different mix of bids submitted to each IOU. It might be because the best fit assessment is different between IOUs for the same project. It might be because each IOU applies different qualitative evaluations of the same project, resulting in different raking. Also, the same bidder might have two different prices between IOUs due to different costs to serve each IOU (e.g., different interconnection or other costs). The result might be different short list selections between two utilities even with essentially the same projects for consideration.
23 According to SDG&E, IOUs now accomplish this via bilateral contracts, which may be signed at any time.
24 The letter or e-mail "must be received by the Executive Director at least three business days before the existing date for compliance." (Rule 48(b).) A copy must be served at the same time on all parties to this proceeding. The "existing date for compliance" is either the date in Attachment A hereto, or a modified date by notice subsequently served on all parties by the Energy Division Director.
25 SCE asks for 30 days, citing in support that it is conducting a workshop with bidders on May 25, 2006, and may revise its RFO in response to comments made at the workshop. We encourage SCE and each IOU to make reasonable improvements to its Plan and RFOs. We point out, however, that any material change from the Plan submitted and under consideration here must be resubmitted to the Commission for the Commission to "accept, modify or reject." (§ 399.14(b).)
26 The accelerated RPS goal is "20 percent renewables by 2010." (EAP II, October 2005, page 8.) An entity may seek to reach this goal before 2010.
