IV. Adoption of Modified Proposal
A. Discussion
We have carefully weighed the cogent arguments presented at the workshop and in the comments that urge the Commission to promote regulatory certainty in California by enforcing the policies already in place, i.e., the resource obligations and planning directives established in our earlier decisions. In particular, we have established RAR for all LSEs,18 we authorized the IOUs to procure consistent with their LTPPs and we authorized cost recovery accordingly for 2005 through 2014.19 In addition, to address concerns for burdens on bundled customers from migrating customers, we allowed the IOUs to recover stranded costs from all customers for a 10-year period. When D.04-12-048, the RAR decisions and AB 57 are read in concert, the IOUs have no barriers to either building new generation or entering into long-term contracts for new generation. Yet, despite all the steps the Legislature and this Commission have taken to see that the state has adequate electric resources, it is clear that there is a need for new generation as early as 2009.
We are, however, concerned that if we jump too quickly into taking steps that appear to be protecting IOUs from any risk in investment in new generation, it could be interpreted as signaling an end to a hybrid electricity market in California. SVLG warns us of policy changes towards reintegration. In that climate, there is little potential for any non-utility to invest in new generation resources for California. We recognize that granting the IOUs too much price guarantee and risk protection, may undermine the development of a more competitive market.
IEP and WPTF caution us that there are no quick fixes, and they would prefer that we address problems with the IOUs' RFOs that exclude existing generation from bidding instead of adopting a new proposal. SDG&E also does not think we need any new policies since they were able to get new generation built. However, we note that SDG&E's new resources are partially supported through reliability-must-run (RMR) contracts, which is slightly different, yet analogous to the JP on cost shifting principles. This Commission has stated its preference to moving away from RMR, rather than perpetuating it.
Aglet and other parties suggest that the Commission just order the utilities to build new generation. While it is well within the Commission's legal authority to order the utilities to build without cost-allocation treatment, we do not expect that strategy will likely yield new generation by 2009.
CMTA/CLECA argue that we should investigate whether the IOUs have "complied" with our orders in D.04-12-048. But as TURN noted, it is more important that the Commission figure out how to ensure new generation needed for system reliability gets built when it is not in the interest of any LSE or its customers to take on such an obligation.
While we find these arguments well thought out and presented, we are still faced with a real scarcity issue. We must therefore make a careful analysis of what is at risk: if we do nothing, we could be putting the state in jeopardy of being short the generation facilities needed to assure adequate capacity and energy as early as 2009, or we could take the initiative now to promote new "steel in the ground" and take the chance that some will question our commitment to competition and customer choice. Allowing the fear of risks to create a stalemate, however, does not ensure that new generation will be built in the necessary timeframes needed by California.
Therefore, to assure grid reliability for the state as a whole, we adopt a plan to remove many of the remaining risks or barriers, perceived or real, to investment in new generation. We do not do this enthusiastically, but from necessity. Our ultimate goal is a robust and competitive wholesale market and a competitive retail market. Until that is a reality, we adopt an interim plan to encourage new generation. We intend this to be a short-term solution.
B. The Adopted Proposal
The interim proposal we adopt below contains the skeleton of the JP, as modified. We revised the JP to avoid some of the problems cautioned by those advocating the "stay-the-course" position.20 We accepted some of the revisions offered by the Indicated Parties, and then added further adjustments as suggested by the parties at the workshop and in their comments.
1. We adopt the provisions of the JP that the Commission designates an entity to procure new generation within an IOU's distribution service territory, with the costs and benefits associated with development of these new resources allocated to benefiting customers.21 We designate the IOU as the entity to procure new generation, until modified by Commission decision. The LSEs in the IOU's service territory will be allocated rights to the capacity that can be applied toward each LSE's RAR requirements. The LSEs' customers receiving the benefit of this additional capacity pay only for the net cost of this capacity, determined as a net of the total cost of the contract minus the energy revenues associated with dispatch of the contract.
2. New generation approved by this Commission and eligible for the cost allocation mechanism will receive cost recovery for a period of up to 10 years. We limit the maximum term of any cost paid by all customers to the term of the contract, or 10 years, which ever is less, from the time that the new unit comes online.
3. We intend this cost allocation mechanism to be in place for the term of the contract or up to 10 years, whichever is less, from the time the new unit comes on line. However, the mechanics of this cost allocation mechanism may charge depending on the new market-based system which may evolve.
4. We determine that the administrative cost of selecting the contract (i.e., the procurement administrative costs for contract negotiation and selection) will be born by only the bundled customers, because there is no way to easily separate out these costs. Furthermore, these costs are intermingled with the rest of the IOU's procurement activities. While these costs may be a slight burden on the bundled ratepayer-relative to the cost of the contract and the magnitude of the analysis required to unbundled the cost of contract selection from the cost of the contract-we find that it is reasonable to make this determination.
5. As previously determined in D.04-12-048, all currently bundled customers are responsible for any long-term commitments entered into by the IOUs for 10 years, unless otherwise modified by the Commission. Nothing we adopt herein relieves or adds to that responsibility. Contracts ineligible for this cost allocation mechanism, or contracts to which the IOU elects not to apply this cost allocation mechanism at the time it seeks Commission approval of the contract, are still subject to the rules of D.04-12-048. Numerous parties representing potential IOU departing load weighed in to this proceeding to argue that their customers should not be responsible for new resource commitments. In D.04-12-048, we already determined that future departing load is responsible for the resource commitments entered into by the IOUs on their behalf whilst they are still bundled customers.22
6. The IOUs are required to administer a competitive solicitation and select new resources for long-term contracts. We direct the IOUs to utilize a third-party independent evaluator (IE) to oversee any competitive RFO that produces a contract subject to this cost allocation mechanism. We continue the requirement that the IOUs must bring any contract to the Commission for approval via an Application if the contract is greater than five years, and be subject to other procedural rules such as oversight by the procurement review group and the IE. We do not expect that any contract for new resources would be for less than five years; however, we will only allow contracts brought to the Commission for approval via an Application to be considered for the cost-allocation mechanism adopted here.
7. Each IOU may fill its new generation need by way of a competitive RFO, which is open to any fuel type or technology from both green sites and repowered brown sites.23 In D.04-01-050, we strongly encouraged repowering if possible, and we continue to believe that repowered projects are beneficial. We do not explicitly require IOUs to give preference to repowerings, but we expect that IOU RFO evaluation procedures will value the economic benefits of repowering. The IOUs should be flexible with the on-line dates (including in SCE's fast track solicitations) so that potential viable resources, especially repowered sites, are not excluded if there is a short gap in which an existing power plant continues to produce power, before the new plant gets built and comes on-line.24
8. IOUs are encouraged to hold all-source solicitations to select long-term contracts but only new or repowered facilities of any resource type are eligible for the cost-allocation mechanism.
9. If the utility signs a "hybrid" contract which includes some years of service from an existing unit, and some years of service for a new unit on the same or on a near site-the cost-allocation method adopted herein only applies to the part of the contract with the new facility. Any part of the contract that uses the existing facility must be paid fully by bundled ratepayers.
10. We do not prohibit the utilities from owning their own generation, nor building their own power plants. However, we concur with Mirant, Sempra, AReM and other parties that recommended we not allow utility-owned generation to qualify for this cost-benefit allocation mechanism. We do not allow resources chosen by the IOU that are utility built or utility owned25 to be eligible for this cost recovery mechanism. As many parties noted, there are numerous long-term energy benefits to utility-owned generation, and it is difficult to isolate just the first few years worth of capacity value of a 30-year or longer utility-owned asset. We recognize that this determination affects PG&E the most because (1) SCE has already stated that it will only consider PPAs in its future LT RFOs and (2) PG&E has already selected two projects that will be utility-owned projects.26
11. Each IOU may fill its new generation need with resources that are within or outside of the CAISO's identified local reliability areas. However, given that all LSEs are expected to have local RAR as a result of the decisions in Phase I of R.05-12-013, we encourage the IOUs to give strong consideration, if not outright preference, to resources that reduce the local RAR for all LSEs. If a new unit subject to the cost-allocation mechanism falls within a local area, the local RA counting benefit will also go to all LSEs that are paying for the resource. The IOU should justify why any new contract procured on behalf of the entire system does not address local RAR.
12. On the subject of contract confidentiality and disclosure, we defer to the outcome of the Confidentiality proceeding, R.05-06-040 and D.06-06-066. Numerous parties requested that we find that all contracts subject to this cost allocation mechanism be deemed public. We do not make that determination here because the Confidentiality proceeding is already considering closely related matters.
13. We find that IOU conduct in RFOs (i.e., RFO processes) are not the subject of this decision. However, we reiterate our commitment to review RFO processes in Phase II of this rulemaking.
14. We find that the energy and capacity from any new resources should be unbundled, with the costs and benefits of the RA capacity component socialized to all customers connected to the utility's distribution system, and the costs and benefits of the energy component assigned to those that value the energy the most, as demonstrated through an auction or similar mechanism.
15. The IOU should charge the benefiting customers the net cost of capacity, determined as a net of the total cost of the contract minus the energy revenues associated with dispatch of the total contract. All RA counting benefits and net costs are spread to the LSEs whose cutomers are allocated costs based on share of 12-month coincident peak, adjusted on a monthly basis to facilitate load migration. The contract costs paid and RA benefits received by DA (or CCA and muni load) and bundled customers should be based on a share basis equal to the credit share received.
16. We agree that the energy component of the contracts for new resources can be managed by an IOU. However, as recommended by the Indicated Parties, we chose to separate the energy component so the risks can be assumed by individual market participants. We require that each IOU must file an Implementation Proposal for Commission approval in the LTPP proceeding (or a separate proceeding if notified by the Commission) for how it will plan to conduct periodic auctions, for the energy rights for each of the resources acquired under this interim proposal. These auctions will provide the right for another entity to manage the energy component of the contracts. Essentially the IOU will sell the tolling right, and retain the RA benefit which it will share with all customers paying for the capacity. The IOUs must retain an independent third party to administer the energy auction. The auction will be overseen by the IOU, the procurement review group and the third-party evaluator. The cost of administering the auction shall be considered part of the IOU's procurement expenses unless the IOU contracts with a third party, in which case, the cost of the auction shall be considered part of the cost of the contract. The IOU's own procurement group will be allowed to bid on the auction for the energy. The purpose of the auction will be to maximize the energy value and minimize the residual cost of the RA capacity. The auctions should be periodic, so as to capture the fluctuations in the energy market. If there are no bids accepted for the tolling right to the contract, then the IOU will manage the energy dispatch in accordance with the original terms of the JP, i.e., it will be valued at spot market prices, until time for the next periodic auction, or one year, whichever comes first. The Commission's Energy Division (ED), in consultation with the Assigned Commissioner, shall hold a workshop prior to the IOUs' filing their Implementation Proposals, and subsequent workshops as needed.
17. The IOU's Implementation Proposal filed with the Commission must include a proposal for how the RA credit and costs will be calculated and allocated. The IOU proposal will include how it will notify all LSEs, the Commission's ED, and the CEC of the amount of RA capacity that is expected to be available and when. As part of the normal notification of RAR, the ED and CEC could provide each LSE with a credit that it can use towards either its system RAR compliance showing, and if applicable its local RA showing. The IOU is obligated to auction the rights to the energy, unless the Commission directs otherwise.27
18. The ratemaking mechanisms to implement this cost proposal will be addressed in Phase II of this proceeding as well as in proceedings for each IOU's general rate cases and other relevant proceedings.
19. If an IOU identifies and selects a new power plant project outside of a competitive solicitation, i.e., through a "unique fleeting opportunity" ("UFO") such as Mountainview or Contra Costa 8, that "UFO" is ineligible to be considered for this cost-allocation treatment. Such opportunities must be weighed on their merits for currently bundled customers only.
C. Other Issues
We encourage other market participants to develop new generation in California, even without long-term contracts with IOUs. Nothing we do today prohibits IOUs (or ESPs) from contracting with other new resources that come online without the aid of long-term contracts with the IOUs. It is our expectation that as MRTU, and other market mechanisms evolve-investors will find it attractive to invest in California's energy market even without long-term contracts. In fact, we may find that the State has underestimated its forecast for future demand growth in the outer years, and if higher demand growth comes to pass - additional new resources may be needed by all LSEs even to satisfy their RAR. Additionally, we know that we are unable to predict retirements of aging power plants, which may also change the supply/demand outlook. While many have stated that new power plants require long-term contracts-we remain open to the possibility (and indeed hopeful) that eventually some power plants may be built without long-term contracts from IOUs. For example, WPTF cited a new power plant that is being developed by GE and Calpine in Romoland, CA. Although this power plant is not yet included in the CEC's supply forecast due to the early stage of its construction, we find this news encouraging in that it portends the development of non-IOU sponsored new power plant investment. We will revisit the IOU's LTPPs in Phase II and biennially thereafter, and if we find that additional power plants are coming on-line (or retirements are not imminent), we will readjust our directives to the IOUs.
We reject the Joint Parties characterization that the new resources constitute a "public good." To do so raises many legal and political issues that may actually prove to be impediments to our going forward with our decision. We are confident that the proposal as set forth below is based on sound legislative and Commission authority and precedent and does not need the designation as a public good in order to support the cost-allocation methodology we adopt.
We find that important goals for Phase II of this Rulemaking will be both to examine bundled customer need, as a repeat to the 2004 LTPP, and also to look carefully at the bundled customer need in the context of regional system need. We will review the need for new system resources in each IOU's territory and we may find that it is prudent for the IOUs to add additional resources to benefit the entire system. If so, we may authorize a continuation of the transitional mechanism to cover the next round of contracts.
We find that the concept of an opt-out mechanism to this cost and resource adequacy benefit allocation methodology is appealing, but we are unable to adopt such a plan today. While we would like to agree with WPTF, Sempra and others and say that "any LSE that can demonstrate that it is fully resourced with new generation for the 10-year time frame may opt-out of the cost allocation mechanism," the reality is that we have no viable enforcement program or mechanism for doing so. We do not currently have a multi-year RA program wherein an LSE could demonstrate it is fully resourced for the next four or 10 years. A forward looking RA showing that allowed LSEs to list "new" resources for three to four years out might be based on "expected" online dates, and would not be enforceable. Another version of an opt-out mechanism proposed by Sempra would be an extension of the RAR that would require all LSEs to demonstrate that a portion of their resource portfolio was sourced by new resources. We will defer an opt-out mechanism to Phase II of R.05-12-013, where we will consider it concurrently with capacity markets and multi-year resources adequacy.
We will determine at that time whether it is possible to allow an opt-out mechanism to apply to contracts that have already been approved to be covered by this cost allocation mechanism, or whether it can only apply to future RFOs, as of the time adopted. The latter case is supported by the JP, but we decline to make that determination without full knowledge of the nature and scope of the opt-out mechanism.
We reaffirm the already established immediate and urgent need for new resources. This is not, however, an exact science and we heed the cautions proffered by so many parties that if we are going to take this bold interim step, that we not use over-inflated estimates of need, but use conservative estimates until a record supports a larger increase. We will proceed using the need numbers from our last LTPP decision, D.04-12-048, and/or the numbers further supported by the CEC's 2005 IEPR. At the time of the LTPP filings in 2004, SDG&E had no need for more long-term resources within the referenced time frame. When PG&E, SCE and SDG&E file their 2006 LTPPs, they will have the opportunity to propose, and support, new need assessment numbers.
The CEC and the CAISO both participated in a discussion of the need determination issues at the workshop on March 14, 2006. Both the CEC and CAISO concur that there is an urgent need for new resources in South of Path 15 (SP-15). The need for new resources in North of Path 15 (NP-15) is driven by both load growth, as well as expected retirements.
In D.04-12-048, we determined that SCE28 and PG&E29 should continue to fill their net short with short-, medium-, and long-term contracts. In that decision, we found that it would be prudent for PG&E to add new long-term resources - and we specified that 1,200 MW of new peaking generation, and 1,000 MW of new peaking and dispatchable generation in 2010 was needed. We left open the opportunity to PG&E to justify slightly higher amounts.
We find that it is not necessary to revisit in this decision our previous need determination for PG&E since we already authorized PG&E to justify additional resources, above the 2,200 MW, when it brings in its Application following a RFO.30 Although our determination for 2,200 MW was based on PG&E's bundled customer need, not entire system need, we do not find it necessary to revise the need determination number at this time since we will revisit need determination in Phase II.
In D.04-12-048, we did not specify a precise amount of new resources for SCE, since SCE believed it was "long" on long-term contracts due to the number of Department of Water Resources (DWR) contracts in its portfolio. However, we left it open to SCE to return to the Commission with an application for new long-term contracts. In SCE's filing in this Rulemaking on March 7, 2006, it indicated a willingness to procure up to 1,500 MW of new long-term contracts on behalf of all benefiting customers. SCE indicated it would launch a two-track system for its LT RFO. SCE's first long-term RFO would be on a "fast track" with an expected online date of mid-2009, and SCE's second long-term RFO would be on a "standard track," with expected online dates of 2012-2013.
Attached in Appendix A and B are excerpts from the CEC's Integrated Energy Policy Report (IEPR) Transmittal Report and the CEC Supply and Demand Five Year Outlook. The CEC's IEPR Transmittal Report was developed in November 2005 and is intended to provide recommendations to the CPUC for use in the 2006 procurement and related proceedings, including developing and documenting the range of need for the three largest investor-owned utilities. Following the format of the 2004 procurement proceeding, the CEC's Transmittal Report focuses on the contractual needs of the IOU's bundled customers, although it can be combined with the CEC's Supply and Demand Five-Year Outlook on system needs to better understand system need by IOU territory. In the text of the Transmittal Report, the CEC urges significant use of new long-term contracts (signed by the IOUs) to allow for 14,000 MW of aging power plant replacement statewide.
The CEC analysis for SP-15 shows a need for new resources almost immediately. The CEC analysis for SP-15 includes both SCE and SDG&E territories, and we would prefer that future CEC analysis of the need for system resources in SP-15 be split into the SDG&E and SCE territories, consistent with our procurement paradigm. We would also prefer to have a better understanding of whether the future resource requirements are located within or outside of the region's local load pockets, as identified in the CAISO's Local Reliability Analysis studies. Regardless of which load pockets the SP-15 need is in, as shown in Appendix B, Slide 2, the CEC identifies the need for about 1,783 MW of new resources by 2010 to avoid a Stage 1 emergency situation (7% reserve margin) during adverse conditions (which includes a 1 in 10 load forecast). The planning reserve margin under normal conditions is 22.7% in 2006, and reduces to 15% by 2010. However, the adverse scenario reserve margin is only 2.4% in 2006, and is -5.5% by 2010. The adverse scenario reserve margin is very low. The figures presented above do not incorporate the CEC's revised (upward) 2007 demand forecast which we expect will further worsen the outlook for planning reserve and adverse scenario reserve margins. All of the CEC analysis assumes no additional retirements in SP-15 before 2010. In all likelihood, the state will need more than 1,783 MW in SP15 to allow for retirements, ensure against execution and plant building risk, and maintain at 15%-17% planning reserve margin and adequate adverse condition reserve margin. We recognize that SP-15 is neither the sole responsibility of SCE nor SDG&E, and we currently understand SDG&E is under contract to add new resources to SP-15 in the 2009 timeframe (i.e., Otay Mesa).
Based on the CEC's 2005 IEPR, which is supported by other data submitted by these parties in this rulemaking, we find that we can repeat our determination from D.04-12-048 that SCE is allowed to bring to the Commission an Application for new long-term resources. We further find that SCE's needs to procure at least 1,500 MW of new resources by 2009-2010, and that this finding is very conservative given the IEPR Transmittal Report and CEC's Supply Demand Outlook in SP-15. As with our order to PG&E in 2004, we leave it open to SCE to justify more MW, either in its application for approval of the contracts, or preferably in the Phase II of this docket.
For both SCE and PG&E, we urge the utilities to consider to be mindful of the need for resources that address the need for local reliability, as discussed in Phase I of R.05-12-013. In that docket, we are in the process of implementing local RAR. To the extent that the IOUs are going to procure new resources on behalf of all customers, we expect that they will give high priority (if not outright preference) to resources that meet local RA obligations. The IOUs should justify why any new contract procured on behalf of the entire system does not address local RA requirements.
In conjunction with their JP, the Joint Parties provided legal support for their cost-allocation scheme citing AB 380, codified as Section 380 in the Public Utilities Code, for the Commission's authority to approve the plan. The applicable section of the code is as follows:
An electrical corporation's costs of meeting resource adequacy requirements, including, but not limited to, the costs associated with system reliability and local area reliability, that are determined to be reasonable by the commission, or are otherwise recoverable under a procurement plan approved by the commission pursuant to Section 454.5, shall be fully recoverable from those customers on whose behalf the costs are incurred, as determined by the commission, at the time the commitment to incur the cost is made or thereafter on a fully non-bypassable basis, as determined by the commission.31
In summary, Section 380 allows an IOU to recover the costs it incurs to sustain "system reliability and local area reliability" from all customers "on whose behalf the costs are incurred." We construe benefiting customers as defined in Section IV.B.1 as those customers on whose behalf the costs are incurred.
Joint Parties posit that the Legislature's intent is clear from the statutory language that they did not want to limit recovery for system and local area reliability to just an IOU's bundled customers, but authorized recovery from a larger group of customers. Therefore, Joint Parties argue that the JP is consistent with the Legislative intent of AB 380 since it provides for an equitable cost allocation for the new capacity needed for system reliability from all benefiting customers.
We agree with the Joint Parties that Section 380 clearly authorizes the Commission to adopt a cost-allocation methodology that spreads the cost of new generation. In addition, we read Section 380 as mandating that as part of the Commission's obligation to establish RAR that we must support "new" generating capacity and equitably allocate the costs. The pertinent portion of Section 380 that addresses RA is as follows:
(b) In establishing resource adequacy requirements, the commission shall achieve all of the following objectives:
(1) Facilitate development of new generating capacity and retention of existing generating capacity that is economic and needed.
(2) Equitably allocate the cost of generating capacity and prevent shifting of costs between customer classes.
While we have adopted RAR for all LSEs, we have not specified that any portion of the capacity must be "new." Sempra, in its comments, points this out, and this may be an area that we address in the future. In the interim, the cost-allocation methodology we are adopting in this decision is intended to support new generating capacity.
To further bolster their claim that the cost allocation proposal in the JP is consistent with law and Commission precedent, the Joint Parties reiterate the Commission's mandate that rates it imposes must be "just and reasonable" and cannot be unfair or discriminatory. The Joint Parties cite to a number of cases where the Commission imposed recovery surcharges upon benefiting customers when costs are incurred by the IOU for the benefit of all customers, not just for its bundled-service customers.32
More recently, in D.04-12-048, the Commission found that it was appropriate and reasonable for the IOUs to recover the net costs of long-term commitments from all customers, including departing customers.33 As a corollary to that finding, the Commission allowed the IOUs to recover costs related to enhancing reliability from all customers in their respective service areas who benefit from the reliability, not just from those taking bundled service.34
Joint Parties also point to the "physical interconnectedness of California's electricity system."35 From their perspective, it is not the sufficiency of the largest entity's resources that ensures reliability, as much as it is the sufficiency of all entities' resources. Since a fully resourced LSE can be subjected to an outage because of an under-resourced LSE, all LSEs benefit, and all LSE's customers benefit from new generation that contributes to system reliability.
We agree with the Joint Parties that Section 380 supports the adoption of the cost allocation formula set forth herein, and in addition, we read Section 380 as mandating that we take proactive steps to facilitate new generating capacity and the cost sharing mechanism we prescribe is the appropriate way to equitably allocate the cost and keep rates just and reasonable.
Sempra and other parties requested that the Commission limit the applicability of this cost allocation mechanism to non-affiliate transactions. It was only in D.04-12-048 that the Commission lifted the ban on affiliate transactions. Although we are sympathetic to the concerns of parties that fear the IOUs will just use this cost-allocation mechanism to support affiliate projects, we are committed to being vigilant against affiliate abuse issues. We established an IE process in D.04-12-048 for the RFO process to protect against affiliate preference, and we do not yet have evidence in the record that would cause us to not trust the IE process. By this decision, we further require the IOUs to use an IE to oversee any RFO that produces a contract subject to the cost allocation mechanism.
Therefore, we do not find it reasonable to reverse course and limit this cost mechanism to non-affiliate transactions. We caution the IOUs to make sure their contract evaluation and selection procedures are above approach and we urge the IOUs to provide information about their bid selection process to as broad an audience as possible.
We are mindful of the optimism shared by several parties that a functioning, centralized capacity market will create the proper market signals to promote investment in new generation in California. While we adopt the cost-allocation methodology set forth herein, and a process for determining the mechanics of the methodology, we are hopeful that a market-based approach, such as a functioning, centralized capacity market, or satisfactory alternative, is in place soon. However, out of a need to ensure that new generation does get built, we adopt a cost-allocation methodology that is designed to provide an incentive for investment now.
We are forging ahead towards a market-based approach. However, a functioning new market, whether it is a capacity market or another market institution, takes time to design and implement as evidenced by models from other states and regional systems. Once implemented, a new market may take time to yield its desired policy results. For example, it is not yet clear that capacity market models in place in the eastern markets have yielded new generation investments. Therefore, we find that until there is a functioning market-based institution in California, we must use a transitional mechanism in order to ensure sufficient new generation for California.
Many parties indicated in their comments that they favored some form of a capacity market, not just to stimulate new generation, but also to insure that the energy costs are paid by those who need and value the energy. We note that under some capacity market design proposals, the cost of new generation is borne by all customers if there is a determination that there is a forecasted capacity shortfall in the system.36
The Commission signaled its interest in researching and examining capacity markets when it issued a staff white paper on capacity markets in August 2005 and invited comments on the paper.37 Those comments indicated a wide range of views on how to move forward with the design and implementation of capacity markets. In December 2005, the Commission opened R.05-12-013 to consider both local RAR, Phase I, and capacity markets-along with multi-year RA and other issues-in Phase II. Therefore, the issue in this Rulemaking is limited to what the Commission should do in the intervening time to support new generation investments in California.
Although the future state of the retail market is not within the scope of this proceeding, it is worth mentioning here that this cost-sharing plan should make the IOUs indifferent to the reopening of DA once the legacy of the DWR contracts expire. If DA customers are participating in the cost allocation plan, then there will not be a cost differentiation based on the cost of capacity of new generation between the price the IOUs charge their bundled customers and the price DA can offer. However, if the IOUs have to pass on the entire cost of the new generation to just their bundled customers, with no wider cost allocation scheme, then the cost of energy from an IOU will necessarily be more expensive that that from a competing DA provider. Because the non-utility LSEs do not have RAR requirements that necessitate them entering into long-term contracts, the non-utility LSEs would not have to pay the price of a contract for new generation. This situation will create an unacceptable inequitable balance between IOU bundled ratepayers and other ratepayers. However, under our new cost-allocation proposal, there will be no "free riders" vis-à-vis the cost of capacity of new generation, and the IOU's bundled customers will not be solely responsible for the costs of new generation that benefits the system as a whole.
PG&E is in a unique position. The Commission just approved38 a settlement agreement for the procurement of the CC8 facility that will be a PG&E-owned resource with a capacity of 530 MW. In addition, PG&E completed a long-term RFO pursuant to the need identified in the 2004 LTPP, and has contracts for an additional 2,250 MWs. Sempra and other parties argue that we should not allow this cost-allocation mechanism to apply "retroactively" to the PG&E long-term RFO. We disagree with Sempra, and we will allow PG&E to designate up to 2,250 MW of new generation that is not utility-owned from the recent LTPP RFO to be eligible for the cost-allocation methodology established in this decision. CC8 is not eligible for the cost allocation mechanism since it is a utility-owned resource. In A.06-04-012, PG&E has signed a Purchase and Sale Agreement (PSA) with E&L Westcoast Colusa, and an Engineering Procurement and Construction (EPC) contract with Wartsila Humboldt. Both projects will result in utility-owned power plants that are not eligible for this cost allocation. All three projects will count towards PG&E's needed MW.
SCE indicates that under the fast-track RFO, new resources would be brought to the Commission via an Application by February 2007 that might come online by 2010. We order SCE to file an Application no later than February 2007 seeking Commission approval of new resources, or the Commission will exercise its oversight authority to determine why SCE is delinquent in its compliance with today's Commission order.
SCE also wants to pursue new resources by way of a standard track RFO. SCE may conduct both RFOs to fill up to 1,500 MW of new generation as long as the utility files an application seeking Commission approval of some new resources to the Commission by February 2007. If SCE's application filed by February 2007 does not seek approval of 1,500 MW, SCE must justify in its application why it does not do so, including, inter alia, stating whether or not it received other bids in the fast track solicitation that are not included in the application (and the bid details), and why it is preferable for SCE to wait to seek approval of the remaining MW under its standard track solicitation.
The state, through the Governor and the legislature, and this Commission have signaled their joint commitment to reducing greenhouse gases (GHG). Although the Commission might not have a decision on its new GHG policy in place before SCE completes its fast-track RFO, we expect SCE and the other IOUs to follow the Commission's GHG policy, as enunciated in R.06-04-009, when they design RFOs and chooses the winning bidders.
In their comments to the draft decision, SDG&E and TURN request that the Commission extend this cost allocation mechanism to SDG&E's Otay Mesa facility. SDG&E elected Otay Mesa in its 2003 Grid Reliability RFP, and it has been assuming that the plant will receive RMR treatment, which is analogous but not identical to the cost allocation treatment adopted today.
We decline to extend this cost allocation mechanism to the Otay Mesa facility at this time, given that we limit application of this cost allocation mechanism in this decision to the need findings of the 2004 LTPP proceeding. SDG&E may propose additional need in Phase II of this proceeding and if approved, that need may be subject to the cost allocation treatment adopted here.
Our definition of benefiting customers subject to the cost allocation mechanism does not apply to POU customers, unless the customer is subject to D.04-12-048, as modified by D.05-12-022. As noted in D.04-12-048, Ordering Paragraph 9, IOUs are required to forecast and plan for departing load as they file their biennial long-term procurement plans which establish each IOU's long-term resource needs.
The CAC/EPUC requested that we allow cogeneration to bid in the all-source RFOs. We require that all new generation RFOs subject to this cost-allocation mechanism be open to any fuel and any technology. CAC/EPUC also request that cogeneration as departing load be exempt from this charge. We do not adopt this proposal at this time.
IEP and others requested that we examine RFO processes in this proceeding. We defer the review of IOUs RFO processes to Phase II of R.06-02-013.
The OIR issued February 16, 2006, preliminarily determined that the proceeding was ratesetting, and that the issues may be able to be resolved through a combination of workshops and formal comments (as well as evidentiary hearings).39 The schedule that was included in the OIR established dates for a prehearing conference, the filing of proposals on policies to support new generation, a workshop to discuss the proposals, post-workshop briefs, and a draft decision. No evidentiary hearings were forecast at that time. It was anticipated that the draft decision would reflect the record developed and informed by the proposals, the transcript from the workshop and the post-workshop comments and reply comments.
On March 29, 2006, the assigned Administrative Law Judge (ALJ) issued a ruling amending the comment schedule and setting an outline for the comments. Section VII of the outline asked parties to comment on whether there are "any issues of material fact that would benefit from evidentiary hearings, if so, please identify the issues and discuss hearing time needed for development of [the] record."40
Of the numerous parties submitting comments, only a few addressed Section VII with any substance. Many of the parties requesting hearings stated that evidentiary hearings are necessary on the issue of "need." We agree that if we were making a new finding of "need" in this decision, the record would have benefited from a robust examination of each IOUs' need numbers. However, we are not adopting new need numbers in this decision, but are relying on the numbers from the 2004 LTPP and/or the CEC's 2005 IEPR, both instances where need was heavily litigated and a record was developed on the subject. Furthermore, the need figures for SCE and PG&E are extremely conservative used in this decision.
We carefully reviewed the comments requesting hearings on subjects other than need and determined that we are not making any findings in this decision that revolve around any newly identified disputed material facts. Our findings in this decision are based on facts previously litigated and policy determinations. The Commission does not need an evidentiary record to exercise its discretion regarding policy matters.
Thus, additional material facts related to need and other issues that were identified by parties in their comments that would benefit from cross-examination are not being decided in this phase of the Rulemaking. The Scoping Memo that will issue for Phase II will indicate if evidentiary hearings will be necessary for the development of a record in that phase of the proceeding.
18 See D.04-10-035, D.05-10-042 et seq.
19 D.04-12-048.
20 In particular, we found the suggestions made by CLECA, CMTA, CCSF, Coral Power, DRA, EUF, J. Aron, SVLG and Strategic Energy, along with Sempra to be persuasive and adopted many of the modifications to the JP advanced in their comments.
21 Benefiting customers are defined as all bundled service customers, DA customers and CCA customers. Benefiting customers are also other customers who are located within a utility distribution service territory, but take service from a local POU subsequent to the date the new generation goes into service.
22 See D.04-12-048, Conclusions of Law 13-16.
23 In comments, parties representing other resources, such as co-generation facilities, wanted further clarification that all-source solicitations could also include co-generation as well as renewables sources. All-source means "all source," and we see no need for further elucidation at this time.
24 Numerous parties have complained to the Commission that the IOUs are designing their RFOs to specifically exclude certain bidders, in particular existing resources. It is our intention to address RFO procedures in Phase II of this proceeding, but in the interim, our guidelines from D.04-12-048, Section VIII(D) are to be followed. We specifically stated "all resources (IOU-built, Turnkey, Buyout and PPA) must participate in an all-source or RPS solicitation. However, the IOUs have the flexibility to tailor their RFOs to reflect their specific resource needs." (Page 128.)
25 The utility may participate in the all-source RFO, and may be a winning bidder. The restriction is only on having the costs of a utility built or owned resource recovered under the cost allocation mechanism adopted today.
26 In A.06-04-012, PG&E requests Commission approval, among others, for the following two contracts: a Purchase and Sale Agreement (PSA) with E&L Westcoast Colusa, and an Engineering Procurement and Construction (EPC) contract with Wartsila Humboldt.
27 In the draft decision, the IOU could determine that it no longer wanted to auction the rights to the energy. In response to comments, that option has been removed.
28 D.04-12-048, OP 5 states, "We find that SCE's LTPP resource plan is reasonable, subject to the compliance requirements covering its demand forecast, demand response, energy efficiency and other factors set forth in this decision and other Commission decisions in those designated proceedings. SCE has demonstrated that its primary residual resource need through 2011 is for peaking, dispatchable and shaping resources. SCE has considerable need for peaking and shaping resources, which should be obtained through short-, medium- and long-term acquisitions. SCE's strategy of relying primarily on short- and mid-term contracts during this planning period is reasonable, but it may be prudent to add some long-term resources. SCE is authorized to present such a case to the Commission as an implementation of its LTPP by way of an application following a RFP."
29 D.04-12-048, OP 4 states, "We find that PG&E's LTPP plan is reasonable and we approve PG&E's strategy of adding 1,200 megawatt (MW) of capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through RFOs because it is compatible with PG&E's medium resource needs, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty. Those commitments may need to be increased or expedited for PG&E to meet its 2006 resources adequacy obligations. Depending on the nature of the bids obtained, PG&E is authorized to justify to the Commission why higher levels might be desirable. Nothing in this decision precludes PG&E from offering local reliability contracts, should they become necessary, pursuant to D.04-10-035."
30 PG&E filed A.06-04-012 in April 2006. Included in that application was a request for approval of 2,250 MW of new resources.
31 Cal. Pub. Util. Code § 380(g).
32 Joint Parties Proposal, March 7, 2006, p. 13, citing D.02-11-022(addressing charges for direct access customers); R.03-09-007 (addressing charges for CCA); D.03-04-030 (addressing charges for distributed generation departing load); D.03-07-028 (addressing charges for municipal departing load) and D.05-12-041 (addressing charges for CCA).
33 D.04-12-048, pp. 58 -60.
34 Id., at 63.
35 Joint Parties' Comments, April 19, 2006, p. 3.
36 Under some capacity market design proposals, the CAISO would be responsible for contracting for new generation resources and spreading the costs to all customers, if it was determined that there was a forecast capacity shortage in the four-year ahead time frame. Under some models, the capacity authorized today as eligible to receive cost-allocation treatment may be seamlessly folded into the new mechanism; however, it is impossible to determine now if that will be the case.
37 The Capacity Markets White Paper was issued in R.04-04-003.
38 D.06-06-035.
39 OIR, February 16, 2006, p. 15.
40 ALJ Ruling, March 29, 2006, p. 2.
