XI. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and ALJ Brown is the assigned ALJ in this proceeding.
1. The purpose of this decision is to give the three IOUs authorization to plan for and procure the resources necessary to provide reliable service to their customer loads for the planning period 2005 through 2014.
2. This decision must work in concert to coordinate and incorporate Commission and legislative efforts from other proceedings, in particular: Community Choice Aggregation (CCA), Demand Response (DR), Distributed Generation (DG), Energy Efficiency (EE), Avoided Cost and Long-term Policy for Expiring Qualifying Facility (QF) Contracts, Renewables Portfolio Standard (RPS), Transmission Assessment and Transmission Planning. This decision must also incorporate the Commission's direction, articulated in D.04-10-035, the Resource Adequacy (RA) decision in this docket.
3. Since the EAP was adopted, we have directed the utilities to prioritize their resource procurements following the loading order of preferred resources established in the EAP. The EAP's loading order framework identifies certain demand-side resources as preferred because they work towards optimizing energy conservation and resource efficiency while reducing per capita demand, as well as certain preferred supply-side resources. The EAP loading order is: energy efficiency (EE) and demand response (DR), renewables (including renewable distributed generation), clean fossil-fueled distributed generation (DG) and clean fossil-fueled central-station generation. Sensible transmission investments should be made in concert with these other resource choices.
4. After existing resources and policy preferred resources have been compared to load and necessary reserves, the result is the amount of energy and capacity which a Load Serving Entity must still acquire. This is called either "need" or the "net open" position, sometimes subdivided into "net short" and "net long."
5. The Assigned Commissioner appropriately directed the IOUs to file LTPPs based on 3 scenarios:
a) The medium-load plan is the preferred resource plan of each utility that meets the needs identified in its Alternative Base Case load-forecast scenario or, if the utility does not choose to file an Alternative Base Case load-forecast scenario, its IEPR-CEC base case scenario;
b) The high-load plan is a reasonable guess at how great the burden of service could become under high, but not unreasonable assumptions about future load growth, and should be based on the assumption of greater than expected economic growth, resulting in higher load growth, assumption of a modest core-noncore load loss and a modest development of CCA beginning in 2009, and assuming that current levels of DA will continue throughout the time horizon; and
c) The Low-Load Plan is based on reasonable but pessimistic assumptions about the economy and assumes aggressive CCA development beginning in 2006, and an aggressive core-noncore scenario, as well as the continuation of DA service at current levels.
6. The purpose of the three resource scenarios is to assist the Commission in understanding how each utility intends to respond to a wide range of load scenarios; the focus is not on forecasts, but on the adoption of long-term plans that can accommodate many outcomes.
7. Although all three IOUs relied on different assumptions in modeling their medium case and in setting floors and ceilings for the high and low scenarios, for the most part the three LTPPs complied with the resource scenario request. The differing assumptions made cross-utility comparisons difficult, but each LTPP taken on its own provided a reasonable range of scenarios as boundaries of risk.
8. The "service area" or "reference" forecasts presented by the IOUs in their LTPPs indicate reasonable growth trends and levels. The utilities use similar growth factors and are generally consistent with the IEPR forecast trends, except the levels are higher because they are updated from a 2001 baseline to a 2003 baseline. This update reflects the unanticipated economy recovery in 2002 and 2003 that was not reflected in the IEPR forecast.
9. Since CCA has been set in statute and is the subject of an on-going CPUC implementation proceeding, it is reasonable to assume that some CCA will start to occur in 2006. There was not sufficient evidence in this proceeding to prove that CCA alone will have a material effect on IOU resource needs in the next few years.
10. A major issue in this proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligations to provide reliable service to their customers. The implementation of CCA, departing municipal load, and the potential for lifting, in some form or another, the current ban on allowing new direct access, all create uncertainty as to the amount of load the existing utilities will be responsible for serving in the future.
11. Existing resource planning uses average weather (1-in-2) and then adds a reserve margin which, in part, provides the cushion should hotter than average weather occur. This is the approach we adopted to implement our resource adequacy requirements and should also be applied here.
12. We provide guidance on resource planning based on the EAP and current circumstances, but only market-tested bids will actually produce a portfolio of specific resources. In this setting, planning is largely indicative, not deterministic.
13. Approving a mixed portfolio of different contract terms and lengths will help to ensure that the utilities will not over-subscribe to long-term contracts that will crowd out future opportunities.
14. All three IOUs have capacity needs throughout the planning horizon. Capacity needs expand considerably in 2011, due to the expiration of most of the DWR contracts. All three IOUs are long on energy, primarily in the off-peak and shoulder hours, through 2009 (PG&E) and 2010 (SCE and SDG&E) until the bulk of DWR contracts expire. Because resources are `lumpy', adding preferred resources upon existing resources somewhat exacerbates this long position, requiring utilities to be energy sellers in many off-peak and shoulder hours.
15. We must balance grid reliability with our other primary public duty of protecting ratepayers from excessive charges and also be mindful of potential departing loads and stranded costs.
16. The IOUs complied sufficiently with Commission direction in preparing their resource scenarios so we will not require the preparation and resubmission of LTPPs at this time. Any deficiencies in the LTPPs can be addressed by requesting updates as the Commission gives new direction or clarification in other resource/procurement proceedings and can direct us in giving guidance for the next LTPP proceeding.
17. Because there is no way to predict the energy demand/supply situation with any certainty, especially in the face of changing load situations, the IOUs should include a mix of resources, fuel types, contract terms and types, with some baseload, peaking, shaping and intermediate capacity, with a healthy margin of built-in flexibility and sufficient resource adequacy in their procurement portfolios.
18. The IOUs must have sufficient flexibility in their plans to procure resources as directed by the Commission in the areas of EE, DR, DG, renewables, and soon QFs. The IOUs must balance expiring DWR contracts with meeting required targets in EE, DR and renewable generation.
19. We find that PG&E's LTPP plan is reasonable and we approve PG&E's strategy of adding 1,200 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 resource adequacy obligations. 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.
20. We find that SCE's LTPP resource plan is reasonable, subject to the compliance requirements covering its demand forecast, demand response, energy efficiency, QFs, 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.
21. SDG&E's resource scenarios were the most complete and useful in understanding the impact of differing loads, risk strategies, and the complex process of compiling a portfolio that meets reliability, adequacy, policy preferences and cost moderation goals.
22. We find that SDG&E's resource plan is reasonable, subject to the modifications required for the compliance filing described herein. SDG&E is essentially fully resourced through 2009, other than needed investments in renewable resources to meet RPS targets.
23. We find that the IOU filings comply with the direction provided in the EAP because they included the EAP targets established in the RPS, DR and EE proceedings; included, at a minimum, the DG forecasts in the 2003 IEPR, and added transmission and clean central-station generation to meet remaining energy and capacity needs.
24. We concur with the CAISO that the transmission elements of the plans were insufficient to meet our goals and accept their recommendations that future plans should include conceptual scenarios that illustrate the impact of potential generator location.
25. When an IOU proposes a major transmission line, it should include a companion scenario without the line. Pursuant to the September 16, 2004 ACR issued in this proceeding, these resource scenarios will be examined in the Energy Commission's 2005 IEPR. To the extent an IOU believes that the range of need identified in the 2005 IEPR is sufficient to justify a transmission project then it may be identified as a specific proposal to satisfy need in the 2006 procurement proceeding filings.
26. Utilities should update their gas price forecasts in future LTPPs using the criteria set forth in D.04-01-050 and the June 4, 2004 ACR.
27. Potential community choice aggregators raised policy issues centered on how the IOUs should plan prospectively and judiciously for upcoming CCAs, or other departing loads, so that there would not be excess energy if, or when, the CCAs became fully functional and able to serve customers previously served by one of the IOUs.
28. The threshold policy issue underlying cost responsibility surcharges is to ensure that remaining bundled ratepayers remain indifferent to stranded costs left by the departing customers.
29. We will not determine a precise trigger point when an IOU can stop procuring for a CCA in this decision. Instead, we encourage cities and counties that are seriously considering CCA to approach their IOU and proactively consider strategies in which the two parties can share procurement risk going forward. Such strategies could include agreements between the IOU and CCA to allocate certain contracts to the CCA once it is formed. A CCA may execute a binding notice of intent with a commitment to a target date, at which the CCA is responsible its own energy procurement and resource adequacy. If the CCA does so, its customers will not be responsible for stranded costs of any utility commitments entered into after the agreed upon date. However, if the CCA does not meet the target date, it will be liable for any incremental costs that the utility incurs in excess of its average portfolio cost to serve the load that the CCA is not able to serve. We support parties working together to seek the most efficient transaction between the IOU and CCA.
30. Given the potential for a significant portion of the utilities' load to take service from a different provider, the utilities are concerned that they could end up over-procuring resources and incurring the stranded costs associated with these resources.
31. In D.04-01-050, we stated that a flexible utility portfolio, consisting of a mix of short-, mid- and long-term resources would be the best mechanism to protect against utility over-procurement. Since the issuance of that decision, we have made the utilities responsible for ensuring local reliability, accelerated the resource adequacy requirement from 2008 to 2006, and adopted RPS target goals resulting in the solicitation of new renewable energy sources by the utilities. These initiatives, combined with the existing overhang of utility retained generation and long-term DWR contracts significantly limit the flexibility that the utilities have to quickly adjust their resource portfolios. All of these resource additions benefit all existing customers by improving reliability and promoting renewable energy development.
32. We recognize a potential mismatch between the types of resources that the utilities need to procure (primarily peaking and load following) and the resources that departing customers require (primarily base load with a lesser amount of peaking/load following capability). Thus it may not be possible for the utility to develop a resource portfolio that accurately matches the load profile of expected departing load.
33. In general we agree that the utilities should be allowed to recover their net stranded costs from all customers, which may require the application of additional cost responsibility surcharges or other non-bypassable surcharges.
34. Providing for stranded cost recovery provides a greater incentive for the utilities to enter into longer (3 to 5 year) contracts for existing capacity that many parties advocate as the optimal approach to ensure the availability of these resources.
35. The utilities may need to enter into new contracts or construct new capacity to ensure that California has sufficient resources toward the latter years of this decade. In order for these resources to be on-line when needed, it may be necessary to begin construction of these projects in the very near term, since the record demonstrates that new construction would require a minimum ten-year contractual commitment. In the near-term, it appears that the utilities are the only entities capable of financing these projects.
36. New renewable projects, necessary for the achievement of the EAP and legislative goals, also require long-term commitments in the range of 10 to 20 years.
37. The utilities should be allowed to recover the net uneconomic costs of these commitments. Similar to the treatment of DWR energy commitments, the utilities should take appropriate steps to minimize the costs by selling excess energy and capacity needs into the marketplace. These other revenue sources include market sales, sales into the CAISO's energy/ancillary services market, and potential sales into capacity markets, should they develop. All revenue sources should be credited against the utilities costs.
38. Development of liquid and competitive capacity markets may reduce the risk of capacity investment in the face of potential customer migration. They may facilitate the reduction and mitigation of stranded costs.
39. Demand response programs can be used to help achieve both system efficiency and reliability goals. There are two general types of demand response programs that the IOUs use to reduce demand when energy prices are high or when supplies are tight: `price-responsive' programs (in which customers choose how much load reduction they can provide based on either the electricity price or a per-kW or kWh load reduction incentive), and emergency-triggered programs (in which customers agree to reduce their load to some contractually-determined level in exchange for an incentive, usually a commodity discount).
40. Both types of demand response programs should be designed to motivate customers to reduce their loads in exchange for some type of benefit, such as reduced energy rates, bill credits or exemptions from rotating outages. As used in this decision, the term `demand response program' means `price-responsive' programs for which the Commission has established specific MW targets to be incorporated into the IOU's LT procurement plans.
41. D.03-06-032 adopted price-responsive programs, set target goals and directed the utilities on how to integrate demand response goals into their procurement plans. As of July 2004, the IOUs have a combined total of 519 MWs enrolled in the authorized programs. D.03-06-032 also adopted demand response goals for years 2003 - 2007. The 2005 goal is 3% of `annual system peak demand', increasing to 4% in 2006 and 5% in 2007. The adopted goals apply only to `price-responsive' demand response programs. MW savings generated by interruptible programs do not count toward the demand response goals articulated in the Energy Action Plan. Enrollment in interruptible programs is capped at 2,500 MW.
42. It is clear that the utilities have used inconsistent definitions of annual system peak in arriving at their MW targets for price-responsive demand. For each utility, the "annual system peak" should be the annual system peak for their respective service territories, inclusive of all customers taking service within those boundaries
43. It is too early to judge whether or not the current demand response goals are achievable. Rather than adjust them now or institute an annual review/adjustment process as suggested by the IOUs, the Commission will retain the current 3% of annual system peak goal and further encourage the IOUs to continue with their best efforts in reaching them. Cost-effectiveness of demand response programs is also important to the Commission, and future demand response proposals will be evaluated for their cost-effectiveness in the demand response rulemaking (R.02-06-001) or its successor.
44. The Commission's efforts in the area of DG have focused on promoting customer-side DG installations in utility service territories. These efforts are directed in four areas: Financial Incentives - rebates are offered to customers installing DG through the Self-Generation Program & CEC's Emerging Renewables Technology program; Interconnection Rules -- streamlining interconnection regulations and processes through the Rule 21 Working Group; Special Tariffs and Exemptions -- such as the standby charge exemptions for certain DG in accordance with PU Code Sections 353.1 and 353.2 and the Departing Load Cost Responsibility Surcharge exemptions from D. 03-04-030; and Net Metering - the PUC expanded net metering eligibility to include biogas digester and fuel cell projects along with the currently-eligible solar and wind projects.
45. In addition to promoting customer-side DG, the Commission is also pursuing grid-side initiatives. In accordance with D.03-02-068, the three IOUs are required to evaluate DG as an alternative to distribution system upgrades, subject to a prescribed set of conditions enumerated in the decision. As of the effective date of this decision, none of the utilities have yet issued RFOs identifying projects where DG might serve as an appropriate alternative.
46. The DG rulemaking's progress towards developing a cost-benefit analysis methodology for DG will inform future policy guidance we provide to the utilities regarding DG as a procurement resource.
47. The utilities appropriately reflected the Commission's preferred loading order by including energy efficiency savings targets in their LTPPs as the priority procurement resource. Since the IOUs filed their LTPPs on July 9, 2004, the Commission issued D.04-09-060 on September 23, 2004. D.04-09-060 translated into a numeric goal the mandate from the EAP to reduce energy use per capita. For the electric IOUs the adopted savings goals reflect the expectation that energy efficiency efforts in their combined service territories should be able to capture on the order of 70% of the economic potential and 90% of the maximum achievable potential for electric energy savings over the 10-year period covered by the LTPPs.
48. As discussed in this decision, any incremental investments in energy efficiency over and above the PGC funding needed to achieve the Commission adopted energy savings targets will be considered in R.01-08-028 and related ratesetting dockets for energy efficiency funding that we may initiate.
49. SCE proposed to add a 1% reliability factor to downgrade program savings from non-utility energy efficiency programs operating in its territory. SCE asserted that this reliability factor would address the uncertainty in the timing and magnitude of savings from non-utility programs until rigorous evaluation, measurement and verification (EM&V) of these programs becomes available. We reject SCE's proposal and reiterate our prior directive in D.04-01-050 for the utilities to count expected energy savings from non-utility programs that operate in their service territories.
50. Energy efficiency issues such as the program administrative structure, program funding cycle and duration, funding levels and program portfolios, EM&V framework and protocols, performance incentives, fund shifting authority, and avoided costs used in cost effectiveness calculations will be considered in the energy efficiency rulemaking (R.01-08-028) and not in this proceeding. The Commission has also instituted R.04-04-025 to address avoided cost issues pertinent to energy efficiency programs and other resource applications. We will continue to coordinate these various proceedings to the extent that our decisions in those proceedings impact the utilities' LTPPs.
51. QFs whose contracts expire after December 31, 2005 are not eligible for the one-year or five-year contract extension options set forth in D.03-12-062 and D.04-01-050, respectively. Currently, the only recourse for QFs, whose contracts expire in 2006 and beyond, is (1) to participate in any upcoming power solicitations, or (2) negotiate bilateral contracts with utilities. Neither of these two options is entirely certain. We recognize that without contract extensions or a new long-term policy, QF contracts that lapse in 2006 could cause QF power to go off-line at that time; however, our plan to address these issues by mid-2005 will avert these concerns.
52. On August 8th, 2003 the Commission established via Assigned Commissioner's Ruling the interim guidelines for renewable energy procurement prior to full implementation of the RPS program. In the intervening 16 months the RPS program has been fully established as the central mechanism guiding renewable resource development.
53. In general, IOUs must procure the maximum feasible amount of renewable energy in the general solicitations authorized by this decision, and will be allowed to credit this procurement towards their Renewables Portfolio Standards (RPS) targets. If an IOU succeeds in procuring sufficient renewable resources to meet its RPS Annual Procurement Target (APT) via an all-source RFO, it will not be required to undertake an RPS-specific solicitation.
54. We agree that the renewable procurement sections in SCE's and PG&E's LTPPs are inadequate and need revision. The revisions, with a detailed analysis, will be developed in the IOUs' 2005 RPS procurement plans, which will be filed in R.04-04-026, incorporating additional guidance to be developed in that docket, and with full access to the record in this proceeding. The IOUs must provide detailed annual analysis of renewable resource potential over the next 10 years in their 2006 LTPPs and must include transmission planning for renewable resources in their 2006 LTPPs. Transmission issues will be further addressed in I.00-11-001, in coordination with the RPS docket.
55. We find that RPS targets are a floor - not a ceiling. The EAP loading order places renewables above conventional generation.
56. Using unbundled RECs for RPS compliance is complex and the record here is insufficient; therefore, it is premature to make a determination on this policy at this time. We will consider this issue in R.04-04-026 as appropriate.
57. We recognize that the IOUs' LTPPs did not fully, or adequately, integrate generation and transmission system planning. On October 15, 2004, the Assigned Commissioner in R.04-01-026, the Transmission Assessment OIR, issued a ruling stating "To achieve a comprehensive resource planning framework, the Commission must streamline the transmission planning process and integrate that with the biennial procurement process." The legislature has enacted and the Governor has signed SB 1565 directing the CEC to develop a strategic transmission plan.
58. The purpose of R.04-01-026, issued January 24, 2004, is to streamline the transmission planning process for the IOUs by eliminating the duplicative transmission need assessments that currently exist at the CAISO and the Commission. A component of this streamlining is the Commission's proposed deference to need determinations made in the CAISO's grid planning processes.
59. I.00-11-001 was undertaken for the implementation of Assembly Bill 970 regarding the identification of electric transmission and distribution constraints, actions to resolve those constraints, and related matters affecting the reliability of electric supply.
60. The present procedure for transmission expansion and upgrades is for the IOUs to prepare annually a grid expansion plan, which looks five and ten years into the future. The plans forecast growth in load, the connection of new generation, the retirement of plants whose service lives have come to an end, new transmission facilities and interconnections with adjacent and out-of-state networks. The plans are the product of several iterations of work by engineers followed by stakeholder meetings at which preliminary results are presented and commented upon by the stakeholders. This is an open process in which the Commission staff participates. The plans are then finalized for the year and submitted to the CAISO for review. The CAISO approves, modifies or rejects individual projects. Projects costing up to $20 million are approved by CAISO staff and projects whose cost is greater than that amount require approval of the CAISO Board of Governors. The CAISO also participates directly in the planning of transmission between utilities and, in particular, transmission interconnections with other states.
61. LTPPs should more fully integrate generation and transmission planning. It would be helpful to the Commission's review of the LTPPs if they included scenarios of potential resource portfolios to fully meet future resource needs, and identified the transmission expected to be needed to make the potential resource portfolios feasible. It is not acceptable for IOUs to take the position of only responding to interconnection requests, as SCE proposes. We will work with the CEC to provide guidance for LSE filings in the 2005 IEPR proceeding so that progress toward integration may be made.
62. Phase 2 of the RA portion of this proceeding is scheduled to adopt procedures that will allow identification of "year-ahead" local capacity requirements and overall deliverability for resource adequacy in the early summer of 2005. Those analytic procedures that identify local capacity requirements will inform and govern the utility transmission and procurement requirements going forward.
63. It is premature to address specific requirements regarding local capacity and deliverability in this proceeding or make a judgment as to the sufficiency of the instant filings. However, it is important to provide clarity on how the local capacity and deliverability requirements will come into play in future planning decisions.
64. We expect that the CAISO will work closely with the Commission to establish the analytic procedures that identify local capacity procurement requirements based on deliverability of resources into load pockets and transmission constrained areas of the grid. We expect that once established, the CAISO will work to update the criteria as changes, such as new transmission or generation, occur that alter these local needs as deliverability constraints evolve.
65. In the next few years, IOUs could add extensive new generation to their resource portfolios in order to meet their future resource needs. We believe a ratemaking mechanism needs to be in place to ensure proper and timely cost recovery for these facilities.
66. Cost recovery should begin when the new facility starts operation to serve utility customers.
67. We adopt SDG&E's proposal for cost recovery framework for turnkey projects. Each utility should establish rate-base and O&M-related revenue requirements associated with the generation plant and should use its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) to record costs associate with the turnkey plants and for recovery through each utility's commodity rates.
68. Planning and administrative costs of preparing for the construction or acquisition of the generation facilities, financing costs as incurred, and costs if the project is ultimately abandoned will be considered in our review and evaluation of IOU contracts for turnkey projects and may be considered as part of establishing the revenue requirement for these facilities. Therefore, these types of costs should not receive special recovery treatment and PG&E's proposed approach should be rejected.
69. The current ERRA trigger mechanism requires the Commission to adjust procurement rates if the ERRA balancing account becomes undercollected or overcollected by more than 5% of the previous year's non-DWR generation revenues. This trigger mechanism is set to expire on January 1, 2006.
70. We find that the ERRA trigger provides the IOUs assurance that procurement costs will be recovered in a timely fashion, and we keep the trigger in effect during the term of the long-term contracts, or ten years, whichever is longer.
71. The current disallowance cap is applicable to contract administration and dispatch from the integrated DWR-IOU portfolio. The cap amount is equal to two times the utility's costs of procurement function. In D.03-06-067 the Commission ruled that SCE's request to expand the disallowance cap established in D.02-12-074 to include all procurement activities violates the legislative mandate of Assembly Bill 57, as codified in Pub. Util. Code § 454.5, as well as Sections 451 and 702.
72. PG&E requests that the disallowance cap apply to all utility dispatch, including URG, PPAs, and allocated DWR contracts on the grounds that this would provide certainty in estimating the potential financial risk utilities face. Consistent with our determination in D.03-06-067, as discussed above, that an extension of the disallowance cap violates legislative intent and the statutes, we reject PG&E's request. In its Petition to Modify (PTM) D.03-12-062, filed February 20, 2004, PG&E asks the Commission to clarify that for purposes of upfront standards for procurement transactions, "short term" means up to and including 3 calendar months, or one quarter, not "90 days." PG&E also wants a clarification that the IOUs can conduct competitive solicitations in an auction format. PG&E argues that the use of online auction techniques for competitive procurement falls within the guidelines presented in D.03-12-062 and D.04-01-050.
73. We clarify that D.03-12-062 authorized IOUs to conduct procurement using negotiated bilateral agreements for transactions of up to three calendar months, or one quarter, forward; and that utilities will consult with their PRGs for transactions with delivery periods of greater than three calendar months, or one quarter. We further clarify that D.03-12-062 authorized IOUs to conduct procurement using an electronic auction format for execution of competitive solicitations, among other transactional methods. The authorized products are good for short-, medium-, and long-term procurement.
74. On February 19, 2004, SCE filed a Petition for Modification (PFM) of D.03-12-062 (the 2004 Short Term Procurement Plan Decision). SCE's PFM presented argument on twelve separate issues in the D.03-12-062 that, SCE contends, affect its ability to procure power and make it difficult for SCE to comply with portions of the decision as it is written. SCE's list of twelve requested modifications are set forth in its LTPP, Vol.2, p.13-16.
75. We grant ten of SCE's twelve requested modifications with the exception of modifications seven and nine. Thus, we deny the PTM regarding modification of language that would require an "unqualified certification" as a basis for authorizing SCE's proprietary risk model. We deny the request to eliminate the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges.
76. It is likely that greenhouse gas emissions will be regulated within the timeframe addressed in the utilities' LTPPs and the lifetime of the utilities' long-term resource commitments.
77. Greenhouse gas emissions pose a real and substantial financial risk to customers and the utilities.
78. The Commission should require the utilities to explicitly assess and mitigate the financial risk from greenhouse gas emissions in procurement and in future LTPPs.
79. Consistent with established Commission policy, and the positions of several parties, including PG&E, we adopt a range of values to explicitly account for the financial risk associated with greenhouse gas emissions (which we call a "GHG adder"), of $8 to $25 per ton of CO2, to be used in the evaluation of generation bids. This range is taken from information in the present record. Each IOU will select a value within the adopted range and respond to party comment on the value, before employing the adder in analyzing RFO responses.
80. The GHG value will be added to the prices bid in future procurement, and will be used to develop a more accurate price comparison between and among fossil, renewable and demand-side bids. In the event that the fossil bid is ultimately selected, the adder will not be paid to that generator or charged to ratepayers; it is an analytic tool only.
81. It is anticipated that the Commission will adopt a fixed value for GHG emissions (not simply a range) in approximately March 2005 in the Avoided Cost Rulemaking (R.04-04-025). Once adopted, the IOUs will use that value when analyzing bids. Additionally, the IOUs will use the value adopted in R.04-04-025 in their next LTPPs when modeling alternative resource portfolios and selecting a preferred portfolio.
82. The California utilities are moving forward in a new hybrid market structure supported in large part by this Commission. Since the crisis, the Commission has authorized, and the utilities have conducted, a number of all-source and renewable power solicitations that have successfully procured thousands of megawatts of power under short- and long-term contract to serve California customers.
83. Our most recent experience with procurement solicitations was the SDG&E Grid Reliability RFP process that involved head-to-head competition among both supply-side and demand-side resources (megawatts and negawatts), peaking and baseload resources, an affiliate resource, renewable generators, a merchant PPA, and utility turn-key power plants. This was our first experience with such diversified head-to-head competition among competing resource types, yet it was a successful undertaking.
84. We have determined that it is time to allow greater head-to-head competition and hereby lift the affiliate ban on long-term power products. Accordingly, we adopt certain guidelines and safeguards, including an independent third party evaluator requirement. We will allow the consideration of debt equivalence in the bid evaluation process as specified herein, and we will also require the use of a GHG adder as a bid evaluation component. With these policies we continue to shape and define the hybrid power market in California so as to advance the positive benefits of competition, and deliver California's energy services according to the priorities of state policy.
85. While the Commission has stated a preference for a hybrid wholesale electric market consisting of PPAs and IOU owned resources, this should not undermine the Commission's goal of having the IOUs acquire supply-side resources based on LCBF principles, regardless of ownership form.
86. We are not persuaded by SCE's argument that D.04-01-050 precludes the IOUs from doing an all-source open RFO because a bid evaluation methodology doesn't exist. The IOUs will employ the LCBF methodology when evaluating PPAs and utility-owned bids in an all-source open RFO, taking into account the qualitative and quantitative167 attributes associated with each bid. In addition, when seeking Commission approval for the proposed contracts the IOUs will need to demonstrate that they employed LCBF principles. It is expected that the Commission will revisit the LCBF methodology, integrating "lessons learned" from future all-source open RFOs.
87. We agree with Calpine that, "Putting shareholders - not ratepayers - at risk for cost overruns will put IOU-owned projects and PPAs on equal footing (at least with respect to the allocation of risk), impose some measure of market discipline on IOUs when formulating their bids, and better ensure that the resource solicitation process is fair and competitive."168 Consequently, IOUs will not be allowed to recover initial capital costs in excess of its final bid price for utility-owned resources.
88. 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 (i.e., IOU-built, turnkeys, buyouts, and PPAs do not need to participate in every all-source and RPS solicitation).
89. Bids should reflect total cost (generation and transmission) of delivery to load. In addition, bids from Utility-owned generation (IOU-build, turnkey, and buyouts) will be capped at initial capital costs. If actual costs come in under the capped bid, then there should be a 50/50 sharing of savings between ratepayers and utilities. Lastly, utility-owned resources that are selected in a solicitation will be eligible for Cost-of-Service ratemaking (future plant additions, annual O&M expenses etc.).
90. Utility-built resources that are selected in a solicitation will file a CPCN with the Commission. Solicitation - CPCN process: CPCN process incorporates need determination, cost caps, and CEQA review. Having said that, bid cap would come from the RFO process, need determination would come from the approval of the Long Term Procurement Plan. The only issue left to be addressed in the CPCN is the CEQA review.
91. If an IOU considers the bids from a particular solicitation too high they have the right to terminate the solicitation. However, the IOU will need to reissue another solicitation if they want to file a CPCN with the Commission. They will not be allowed to file a CPCN for a project unless it was selected in a solicitation.
92. FERC has recently set forth Guidelines for Reviewing Future Section 203 Affiliate Transactions, which include guidelines for IEs in 108 FERC 61,081 (July 29, 2004). FERC explained that to the extent to which a utility demonstrates that its RFP process follows the stated guidelines, its application processing time (including litigation) will likely be reduced, thus increasing the possibility of more timely Commission approval through an adequate showing under the Edgar standard.
93. The FERC guidelines provide for substantial IE involvement in resource solicitations at the "design, administration, and evaluation stages of the competitive solicitation process." FERC has set forth "minimum standards for assuring independence and the scope of the third party's role."
94. We acknowledge the detailed IE guidelines set forth by FERC in its recent July 2004 and generally endorse them. At this time, we will outline an interim approach, which we may refine at a later date based on our further experience in this area. We determine here that we will not allow the IEs to make binding decisions on behalf of the utilities. We will require the use of an IE in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders. However, we will not require that the IEs administer the entire RFO process. The IOU shall consult with its IE and PRG on the design, administration, and evaluation aspects of the RFO to ensure that the overall scope is not unnecessarily broad or otherwise too narrow. IEs should be available to testify as an expert witness in any associated Commission proceeding regarding upfront review of potential solicitation transactions.
95. IEs should come equipped with technical expertise germane to evaluating resource solicitation power products. In the case of an affiliate/IOU-turn key power plant, IEs should be able to quickly scrutinize, examine, and essentially break down bids to determine whether the various cost components are reasonable as presented. IEs should be skilled in analyzing a range of power market derivatives (e.g., futures, contracts, options, swaps). IEs should be familiar with the various standard contracts and industry practices. IEs should have experience analyzing the relative merits of various types of PPAs. IEs should be able to evaluate PPAs, turn-keys, and IOU-builts on a side-by-side basis. An IE should make periodic presentations regarding their findings to the IOU and to the PRG.
96. Cost overruns associated with utility-owned resources should be borne by shareholders, because this approach will level the playing field for IOU-owned projects and PPAs, with respect to risk allocation. Cost Savings should be shared 50/50 with ratepayers and shareholders.
97. The IOUs have shown that rating agencies employ various methodologies to assign debt equivalence on their balance sheets for power purchase agreements.
98. Standard & Poor's (S&P) has the most robust methodology for calculating debt equivalence, but their 30% risk factor is based on subjective criteria that should be adjusted downward. So it is reasonable to adopt a 20% risk factor to be used by the IOUs in evaluating PPAs.
99. The arguments presented by SDG&E that keeping Sunrise in its plan reduces its option to address local reliability issues and ORA's proposal that SCE contract with SDG&E for dispatch rights for specific units under the DWR-Williams contract, will be addressed either in the next phase of RA, or in the DWR contract proceeding.
100. In the short- to mid-term, RMR and contracts should suffice to keep the aging plants in operation. These plants could bid into RFOs and because of their advantage over new plants, such as proximity to load centers and infrastructure, they should be competitive in their bids.
101. To the extent feasible, old plants should be retrofitted, and refurbished. It is generally good policy to consider using brownfields first instead of using greenfields, because of existing infrastructure, being close to load centers, and other benefits.
102. While we expect RA Phase II to resolve local reliability, in the interim we extend the requirements of D.04-07-028. In particular, the policy requirements of D.04-07-028 and any implementation procedures should be handled by IOUs filing Advice Letters until local reliability is resolved in RA Phase II, or by other action of this Commission.
103. SDG&E is a unique case among the three IOUs in that within service area resource additions almost certainly will provide local reliability benefits, unlike SCE or PG&E. We therefore direct SDG&E to pursue the EAP loading order priorities when it makes resource additions.
104. The three utilities have presented information on the processes they undertake to develop bottom-up forecasts of their needs and of the plans to deal with those needs. We are satisfied that the utilities are complying with our orders and taking into account the needs of local areas within their service areas in developing their plans.
105. We endorse the coordination agreement and the direction to IOUs stated in the September 16, 2004 ACR. We direct IOUs to participate in the CEC IEPR proceeding as the one forum in which long-term load forecasts, resource assessments, and need determinations will be considered. We believe Appendix B constitutes a good foundation for coordinated proceedings and the minimization of duplication between various planning proceedings. We direct staff to work with the CEC and CAISO to effectuate this agreement in a complete and practical manner.
106. We find that no change is necessary at this time for the Semiannual ERRA Application. As for the Short-Term Procurement Plan, the 2006 Long-Term Procurement Plans will contain the features of the Short-Term Plans that are not covered by the proposed 2004 LTPPs. That is, ultimately, we will eliminate the STPPs and the IOUs will act in accordance with a single Commission-approved plan. Until then, the existing STPPs will be in effect. Updates or modifications to the plans in between the biennial review will be filed with an advice letter. Any updates to the existing STPPs should be filed with an Advice Letter 30 days after the issuance of this decision.
107. No change is necessary at this time to the semi-annual gas supply plans and biennial LTTPs.
108. If an increase to SCE's collateral capacity is required to carry out the LTTP approved by the Commission, SCE will provide updated collateral estimates. No party has taken issue with SCE on this issue. Accordingly, we accept SCE's stated approach.
109. We also note here that SCE can, and does, require counterparties to make similar collateral postings aimed at ensuring contract performance under changing market conditions. We are not aware of any specific claims of over-collateralization or associated recommendations.
110. SCE has informed the Commission of two relatively new accounting rules promulgated by the Financial Accounting Standards Board (FASB) "that, like the debt equivalence issue, may affect electric utilities' costs of contracting for power. While SCE has not requested any specific relief related to these new accounting rules, SCE may seek further guidance from the Commission when appropriate in the same manner as set forth in the Cost of Capital proceeding.
111. Consistent with the Commission's direction in D.04-01-050, it is our intention that many more categories of planning information will be open to the public and will be considered so in our review of the IOU's LTPPs. We have yet to determine if any information that routinely was considered confidential under former protocols might be deemed public when this decision is issued in final.
112. We must balance the competing interests of the need of some confidentiality of IOU data to protect ratepayers, against the public interest in disclosure and the desire of intervenors to have better access to IOU confidential data to more fully participate in Commission proceedings. While we move closer to "open decision-making" we need to be pragmatic about mitigating any adverse ratepayer consequences.
113. Currently under AB 57, that added Section 454.5 to the Pub. Util. Code, the Commission is to have in place procedures that ensure the confidentiality of any market sensitive information submitted by an IOU as part of its proposed procurement plan, while ORA and other consumer groups that are not market participants (NMP) access to the information under confidentiality provisions. This provision of AB 57 was an attempt to balance the compelling ratepayer interest in ensuring that certain legitimately confidential information is kept out of the hands of those who can use it to manipulate wholesale energy markets, with promoting a sufficiently transparent decision-making process to allow for scrutiny and review by the legislature and the public.
114. Following a request from SDG&E to amend the April 4, 2003, ALJ ruling to protect information submitted by parties to a RFP, the ALJ issued a ruling on December 1, 2003, amending the previous protective order allowing certain bid information to remain confidential, but also soliciting comments on a further modification to the protective order to incorporate a provision allowing outside attorneys and/or consultants to a MP who do not perform competitive duties for or on behalf of their client, and who execute a Non-Disclosure Certificate, to have access to materials relevant to the SDG&E RFP. On January 14, 2004, following the receipt of comments on the FERC model, the ALJ issued a ruling adopting an Amended Protective Order that was substantially consistent with the FERC orders and that allowed the MPs access to Protected Materials following the FERC guidelines. As referenced earlier in this decision, this Amended Protective Order controlled confidentiality issues in this current procurement proceeding.
115. In preparation for review of the IOUs' LTPPs in this proceeding, in D.04-01-050 the Commission expressed its desire to move towards more open and transparent decision making and asked the parties to submit comments on how to allow more access to utility data, but not at the expense of the ratepayer/consumer. Comments were received on March 1, 2004. By that time SB1488 was already in committee, so instead of issuing a new iteration of the January 14, 2004, Amended Protective Order we followed the guidelines implemented therein for this procurement proceeding.
116. We also note that more intervenors, in particular the environmental groups, had access to the IOUs confidential data since they signed on to the Amended Protective Order. So in addition to the consumer groups, other NMP also had the benefit of reviewing all the utility data. None of the MPs chose to sign on to the Amended Protective Order. The utilities and the MPs may have reached a point of equilibrium in that if the MPs had more access to utility information, the utilities may have demanded equal access to MP information.
117. SOS may be a useful mechanism for wholesale procurement by LSEs, and it may be appropriate for California once it is further developed and considered. SOS is substantially different from the procurement methods currently being used by the IOUs, and we do not have the knowledge or confidence to mandate SOS at the present time or on the basis of the current record. This topic should be further developed by participants in the second generation of topics for the RAR process, for it is a companion to another topic to be considered, the development of markets for trading capacity.
1. We must incorporate the demand uncertainty factors into our consideration of the LTPPs and consider this uncertainty in determining the level of acquisition and the need for flexibility in the resource plans. Based on this uncertainty, we will not adopt a fixed assumption regarding the level of departing load. We acknowledge that the IOUs face considerable load variability risk, and will set policies accordingly.
2. We will not set a procurement cap based on the low cases, since this could seriously under-resource California's service areas during the planning period. Instead, we will rely on a portfolio approach and allow justification of specific contract types as the need arises. This will allow us to balance between obtaining adequate resources and not over-procuring in the case of departing load or crowding out of preferred resources towards the end of the planning period. We will monitor the IOUs' efforts to obtain resources to meet their resource adequacy requirements on a forward-looking basis.
3. We find all three LTPPs consistent with the 2003 IEPR, are reasonable for planning purposes and that the medium, preferred case should be followed for making planning and procurement decisions.
4. The EAP contains explicit direction regarding the state's preferences for meeting identified resource needs and the IOUs are to prioritize their resource selections accordingly.
5. It is reasonable to require a compliance filing of annual energy and capacity resource accounting tables, consistent with directions on baseline load forecasts, EE, QFs and DR. We do expect the IOUs to make incremental improvements in their next round of analysis to be filed with the CEC in the 2005 IEPR process.
6. It is not our intent to provide the means by which market power could be exercised against the LSEs and, hence, against electric service customers in California. Therefore, this decision does not present information about the current net open positions of the utilities, nor do we provide the elements from which that information can be calculated. It is reasonable to provide simplified tables based on projections of future resource balance information for the years 2007-2014 after those numbers have been refreshed from their initial filing in July 2004.
7. Pursuant to the direction adopted in D.04-10-035, the current focus is on maintaining and enhancing grid reliability through accelerated reserve margin targets. When this goal is integrated with the directive from D.04-07-028 issued by the Commission this summer ordering the utilities to concentrate on near-term reliability, it is evident that the IOUs must increase and retain supply for the near future.
8. Since SDG&E's estimated reserve margins, which exceed 17% in some years during the planning period are the result of prior Commission decisions, there should be no finding of unreasonableness if they exceed 17%.
9. While we do not approve SDG&E's 500 kV transmission line here, we do acknowledge the lengthy process needed to plan, license and construct transmission, and thus encourage SDG&E to continue its planning efforts and move forward with evaluating these transmission alternatives for meeting a local resource deficiency by 2010.
10. To ensure that gas price forecasts submitted in future LTPPs remain robust, we will require that the utilities provide updated gas price forecasts using the same criteria set forth in D.04-01-050 and the June 4, 2004 ACR when subsequent long term procurement plans are filed with the Commission.
11. While we recognize that the potential CCAs want to limit the amount of cost responsibility surcharge applied to departing CCA customers for utility liabilities incurred on their behalf when the CCA customers leave utility service, Pub. Util. Code Section 366.2(h) requires that the Commission authorize community choice aggregation only if the Commission imposes a cost recovery mechanism in accordance with the law.
12. We anticipate that our decision regarding CCA will implement a program whereby cities and counties can procure energy on behalf of their communities, and will also protect those bundled ratepayers who do not have the option of transferring to a CCA from the possible cost impacts resulting from the departing customers. We expect that our CCA decision will adopt a methodology for estimating the CRS that will allow bundled customers to be indifferent to the CCA program, including a methodology for CCA customers to pay their share of the costs of DWR bonds and contracts, utility procurement contracts and other items.
13. Ensuring that utilities be allowed to recover their net stranded costs from all customers meets the Commission's goals of providing "the need for reasonable certainty of rate recovery" (as required under AB 57 and noted in the June 4th ACR) as well as best ensuring that California meets its energy needs.
14. Requiring departing customers to assume a fair share of their costs is also consistent with the Commission's policy of holding captive ratepayers harmless as required by state law.
15. Allowing the utilities to recover stranded costs from all customers who benefited is consistent with recent Commission policy with regards to new resource additions. In both the SDG&E Reliability RFP (D.04-06-011) and in the Edison Mountainview Decision (D.03-12-059) the Commission required that all existing customers of the utility were responsible for any potential stranded costs for a period of ten-years.
16. The utilities should be allowed to recover stranded costs for their non-RPS resource commitments from departing load over either the life of the contract or 10 years, whichever is less. The ten-year recovery period should also apply to any utility-owned generation acquired as a result of the procurement process, commencing once the resource begins commercial operation. Stranded costs arising from RPS procurement activities should be collected from all customers, including departing load, over the life of the contract. The utilities should be allowed the opportunity to justify in their applications, on a case-by-case basis, the desirability of adopting a cost recovery period of longer than ten years for their non-RPS resource commitments. Cost recovery for that portion of a resource acquired by the utilities to meet local reliability needs should be recovered from all customers.
17. The Commission recognizes that by keeping demand response MW goals at their current levels there may not be, at some point, any program that is cost-effective relative to alternative supply resources. As stated above, we believe it is premature to make that judgment today. Because demand response programs are currently voluntary, the challenge of designing cost-effective programs while in pursuit of greater amounts of demand response MWs each year may very well prove to be an impossible task. If and when that point becomes evident, the Commission will need to either reduce its demand response MW goals or begin consideration of mandatory demand response programs and tariffs.
18. We find that the utilities' treatment of DG as a component of the load forecast is appropriate.
19. Consistent with D.04-09-060, PG&E, SCE and SDG&E should meet or exceed the Commission's EE goals over the next ten years and specifically over the next EE funding cycle (2006-2008) and revise and update their plans to be in alignment with these goals. PG&E, SCE and SDG&E are to incorporate the goals from the EE decision in their LTPPs, and as these energy savings goals are updated and amended by subsequent decisions, the IOUs are to incorporate the most recently adopted energy savings goals into their plans.
20. It is reasonable to require the utilities to provide information about the energy efficiency programs in a consistent format in the utilities' future LTPP filings, which will facilitate the Commission and parties' analysis of the proposals.
21. Given that the RPS program is operational, it is reasonable to terminate the interim renewable procurement authority granted on August 8th, 2003, in R.01-10-024.
22. Allowing an IOU to meet its RPS Annual Procurement Target via an all-source RFO, as well as via an RPS-specific solicitation, is consistent with the Legislature's clear intent that renewable procurement be integrated as closely as possible with general IOU procurement practices. To further this effort, we will be working over the course of the next LTPP cycle to fully imbed the RPS into long-term planning, placing renewable energy development where it belongs - central to the IOUs' resource planning efforts. Implementation of the RPS program will continue as a high priority for this Commission, and we will continue to direct the IOUs to procure new renewables via the RPS program.
23. To further California's goal of promoting environmentally responsible energy generation and to protect customers from the financial risk associated with likely future regulation of GHG, it is reasonable to adopt a policy that reflects and attempts to mitigate the impact of GHG emissions in influencing global climate patterns and to direct the IOUs to employ a GHG adder when evaluating fossil generation bids and in future LTPPs. This method, which will be refined in future proceedings, will serve to internalize the significant and under-recognized cost of GHG emissions; help protect customers from the financial risk of future GHG regulation; and will continue California's leadership in addressing this important problem.
24. The coordination agreement between the CEC's IEPR and the CAISO's annual grid planning process, and outlined in the attachment to the September 16, 2004 ACR also emphasizes the need for coordination between transmission planning and resource planning.
25. Once the local procurement and deliverability criteria are established we expect that the criteria may also be useful in guiding the long-term plans going forward. We recognize the importance of the CAISO in helping to establish these criteria and so that they can be applied to the utilities' planning practices. The CAISO core expertise in the area of transmission planning and grid operations is critical to inform the CEC's planning decisions and this Commission's procurement decisions. This approach will assure that the long-term resource procurement meets the CAISO short-term grid requirements. It will also assure that the resources the utilities procure pursuant to their resource adequacy requirements meet the CAISO operational needs.
26. Since the RA phase is designed to handle the reserve margin issues we will not rewrite D.04-01-050 in this decision. If parties want further clarification on the interpretation of the 15-17% requirement they should bring it up in Phase II of the RA portion of this docket. This LTPP decision is not intended to change or modify any aspect of D.04-10-035. Any clarifications, alterations or augmentations to D.04-10-035 will be deferred to Phase II of the RA aspect and not addressed here.
27. Pursuant to DWR's request, nothing in this decision makes changes to prior Commission decisions regarding DWR contracts, particularly D.02-12-074, the IOU-DWR Servicing Agreements, or makes any changes in ratemaking treatment of the DWR contracts.
28. D.04-01-050 continued the ban on affiliate transactions, however, our position on this issue warrants re-examination at this time.
29. Given our desire to consider all competitive options, instead of continuing the ban, and carving out exceptions for unique resources from time to time, we now find that it is in the best interest of the ratepayers and consumers to allow for a full vetting of all available resources in a RFP. We will institute appropriate safeguards for the solicitations for long-term transactions, in part through continuation of utility PRGs and through the use of independent third-party evaluators. Such safeguards can protect consumers from any anti-competitive conduct between utilities and their affiliates.
30. We should adopt a methodology for debt equivalence for IOUs to employ when evaluating competitive bids from independent providers and utilities in an all-source solicitation.
31. We should adjust the S&P methodology for debt equivalence downward to a 20% risk factor to account for the fact that the California regulatory climate is improving, and we do not wish to disadvantage PPAs unduly over utility-owned generation, particularly when it comes to renewable generation.
32. It is reasonable to not allow the IOUs to recover initial capital costs in excess of its final bid price for utility-owned resources.
33. We should adopt a policy that 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 (i.e., IOU-built, turnkeys, buyouts, and PPAs do not need to participate in every all-source and RPS solicitation).
34. It is reasonable to have all-source and RPS solicitation bids reflect total cost (generation and transmission) of delivery to load. In addition, bids from utility-owned generation (IOU-build, turnkey, and buyouts) will be capped at initial capital costs. If actual costs come in under the capped bid, then there should be a 50/50 sharing of savings between ratepayers and utilities.
35. It is reasonable for utility-owned resources, which are selected in a solicitation, to be eligible for Cost-of-Service ratemaking (future plant additions, annual O&M expenses etc.).
36. It is reasonable to direct utility-built resources, which are selected in a solicitation, to file a CPCN with the Commission.
37. It is reasonable to allow an IOU, which considers the bids from a particular solicitation too high, to terminate the solicitation. However, the IOU will need to reissue another solicitation if they want to file a CPCN with the Commission. They will not be allowed to file a CPCN for a project unless it was selected in a solicitation.
38. It is reasonable to direct the IOUs to consider the use of brownfields and take full advantage of brownfield sites before they consider building new generation on greenfield sites. If IOUs decide not to use brownfield, they must make a showing as to why they prefer greenfield sites.
39. It is reasonable to extend the IOUs' procurement on a rolling 10-year basis, given that the long-term procurement plans cover a ten-year period and they will be updated and reviewed every two years.
40. It is reasonable to require certification of SCE's proprietary risk model and to require an independent third-party verification of the internal validity of the model, aimed at ensuring that all the features of the model work as advertised, that the model is mathematically sound, and that the assumptions utilized by the model are reasonable.
41. With regard to the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges, this is a reasonable upfront standard, consistent with AB 57. The use of transparent exchanges is one reasonable check on the competitiveness of a portion of SCE's procurement activity. We direct SCE to consult with its PRG regarding the specific implementation options that are available.
42. D.04-01-050 determined that in future cycles of the procurement process, we would link our timing to that of the CEC's Integrated Energy Policy Report. Since that proceeding operates on a biennial calendar, by statute, that means that the next long-term procurement proceeding will be in 2006. D.04-01-050 also linked the substance of the analyses we direct IOUs to file with the results of the CEC's IEPR information and analyses. In the past two years, the CEC and this Commission are collaborating to a much greater degree than ever before, and as evidence the CEC is not a party to this proceeding and its staff is assisting our own in review of IOU LTPPs and in developing resource adequacy procedures.
43. Since this OIR issued, the Legislature passed, and the Governor signed, Senate Bill (SB) 1488 that directs the Commission to "initiate a proceeding to examine its current confidentiality rules under Pub. Util. Code §§ 454.5 and 583 and the California Public Records Act to ensure that the Commission's practices under these laws provide for meaningful public participation and open decision making."
44. We will soon initiate a proceeding to fulfill our obligations under SB 1488. In that proceeding we will review the effectiveness of the PRGs. For purposes of this decision and our review of the IOUs LTPPs, we believe intervenors, including MPs, had sufficient access to the IOUs' background data and assumptions, if they chose to follow the guidelines of the January 14, 2004 Amended Protective Order to allow for a robust development of the record to satisfy us that there was a full vetting of the important issues.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), and San Diego Gas & Electric Company (SDG&E) shall, by no later than March 25, 2005, submit a compliance filing updating their procurement plans to reflect the changes and modifications adopted in today's decision. This compliance filing, shall include, but not be limited to the following:
a. Annual energy and capacity resource accounting tables, consistent with directions on baseline load forecasts adopted in this decision;
b. Procurement activities undertaken by the utilities subsequent to their initial filings in this proceeding;
c. Revised energy efficiency targets as adopted in Decision (D.) 04-09-060;
d. Demand response programs proposed for 2005 implementation in Rulemaking (R.) 02-06-011;
e. The effect of resource adequacy and local reliability requirements adopted respectively in D.04-10-035 and D.04-07-028;
f. Changes occurring as a result of Commission decisions implementing Community Choice Aggregation (CCA) in R.03-10-033;
g. Revised forecasts for the price of natural gas, if necessary;
h. Status of qualifying facilities (QFs) with soon to be expiring contracts; and
i. Any other material information that affects the utilities' procurement activities.
2. The Long-Term Procurement Plans (LTPPs) filed on July 9, 2004 by PG&E, SCE, and SDG&E are approved as modified in this decision.
3. When executing procurement plans in response to this decision, PG&E, SCE, and SDG&E shall:
a. Procure the maximum amount of cost-effective energy efficiency and demand-side resources;
b. For further resource needs, procure the maximum amount of renewable generation resources via all-source Request for Offer (RFO), and be prepared to defend any selection of fossil over renewable resources; and
c. Employ the greenhouse gas (GHG) adder, described herein, when evaluating fossil generation bids.
4. 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.
5. 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.
6. We find that SDG&E's resource plan is reasonable, subject to the modifications required for the compliance filing described herein. SDG&E is essentially fully resourced through 2009, other than needed investments in renewable resources to meet RPS targets.
7. Utilities shall use the criteria set forth in D.04-01-050 and the June 4, 2004 ACR to develop gas price forecasts for future LTPPs.
8. The Commission's decision in Resource Adequacy (RA), D.04-10-035, issued October 28, 2004, among other things, established that all Load Serving Entities (LSE), including the Investor-Owned Utilities (IOUs), must have reserve margins of 15-17% by June 1, 2006. As part of meeting this reserve margin requirement, each LSE must have 90% of its next summer's requirement [May through September] fully resourced by September 30 of the year before. The decision also established a 100% forward commitment obligation for a month-ahead horizon for the entire year. The IOUs are to plan to meet all RA requirements as set forth in D.04-10-035 as they go forward with their LTPPs.
9. In future procurement plans, the IOUs shall incorporate reasonable anticipated CCA departing load. The assumption of the Commission is that the IOUs shall acknowledge potential CCA departing load and identify which city and/or county has expressed intent to pursue aggregation, including MW estimates of this departing load, in future procurement plans.
10. We adopt the 15-year standard for new fossil-fueled resources acquired by the utilities. For all other contracts, including contracts for renewable generation, the utilities should be allowed recovery over the life of the contract.
11. The utilities shall continue to adhere to the directives for reflecting DG estimates in load forecasting consistent with D.01-04-050 and D.04-10-035. We also encourage SCE to move forward with its planned DG RFO, the results of which will be monitored by the Commission for guidance in both the DG rulemaking and this docket.
12. Consistent with D.04-09-060, PG&E, SCE and SDG&E shall meet or exceed the Commission's energy efficiency (EE) goals over the next ten years and specifically over the next EE funding cycle (2006-2008) and to revise and update their plans to be in alignment with these goals. PG&E, SCE and SDG&E are to incorporate the goals from the EE decision in their LTPPs, and as these energy savings goals are updated and amended by subsequent decisions, the IOUs are to incorporate the most recently adopted energy savings goals into their plans. As discussed in this decision, the Commission will address all EE program planning and funding level issues in the energy efficiency rulemaking R.01-08-028, or its successor proceeding.
13. At a minimum, the utilities must provide the following data on their energy efficiency programs in the 2006 LTTPs, and concurrently file and serve this data in R.01-08-028 or its successor proceeding:
a. Total Commission-authorized funding levels in energy efficiency every year over the next decade, broken out into the PGC and procurement component (in real and nominal dollars). If Commission authorization is pending for some or all years of the period, the utilities shall provide estimates of investment levels that are designed to meet the Commission's adopted energy savings goals.
b. New annual and cumulative energy savings as a result of the programs every year over the next decade, broken out into the PGC and procurement components (in GWh);
c. New annual and cumulative peak savings every year over the next decade, broken out into the public goods funds (PGC) and procurement components (both coincident-peak and non-coincident-peak, in MW);
d. The total resource cost (TRC) net benefits of the proposed investments;
e. The average levelized cost of the energy efficiency resources;
f. Comparison of cumulative energy and peak savings to the Commission's adopted goals;
g. The projected percent of demand growth reduced by the programs; and the per capita electricity consumption for the service territory over the next decade after factoring in the energy savings from the programs.
14. We authorize the utilities to enter into short-term, mid-term, and long-term contracts, with contract delivery start date through 2014, provided that the IOUs submit the necessary compliance filings. We adopt The Utility Reform Network's (TURN) proposal that contracts with duration five years or longer be submitted to the Commission for preapproval.
15. We grant PG&E's Petition To Modify D.03-12-062, and clarify that D.03-12-062 authorized IOUs to conduct procurement using negotiated bilateral agreements for transactions of up to three calendar months, or one quarter, forward; and that utilities will consult with their PRGs for transactions with delivery periods of greater than three calendar months, or one quarter. We further clarify that D.03-12-062 authorized IOUs to conduct procurement using an electronic auction format for execution of competitive solicitations, among other transactional methods. The authorized products are good for short-, medium-, and long-term procurement.
16. We grant ten of SCE's twelve requested modifications, as requested in its Petition to Modify, with the exception of modifications seven and nine, as discussed in this decision.
17. The utilities are directed to employ a value to explicitly account for the financial risk associated with greenhouse gas emissions (which we call a "greenhouse gas (GHG) adder"), in the range of $8 to $25 per ton of CO2, to be used in the evaluation of generation bids, in order to select new long-term resource investments that minimize financial risk to ratepayers, as described herein. Each IOU will select a value within the adopted range and respond to party comment on the value, before employing the adder in analyzing RFO responses. Once the Commission adopts a fixed value for GHG emissions (not simply a range) in approximately March 2005 in the Avoided Cost Rulemaking (R.04-04-025), the IOUs will use that value when analyzing bids. Other GHGs, in addition to carbon, will also be included. Additionally, the IOUs will use the value adopted in R.04-04-025 in their next LTPPs when modeling alternative resource portfolios and selecting a preferred portfolio.
18. In addition to the GHG adder, the IOUs are directed to employ, when finalized and approved by the Commission, the additional environmental avoided cost values under development in the Avoided Cost Rulemaking (R.04-04-025). All procurement commenced subsequent to this decision should employ the GHG adder adopted in this decision, until replaced with a decision in R.04-04-025, when analyzing bids.
19. The Assigned Administrative Law Judge (ALJ) and/or Assigned Commissioner (ACR) may direct Commission staff to perform additional studies or analyses on "carbon caps," as needed, in coordination with our consideration of a procurement incentive framework modeled after the cap-and-trade principles of the Sky Trust in a subsequent phase of this proceeding.
20. In soliciting resources in response to these plans, the IOUs are to procure the maximum feasible amount of renewable generation, consistent with the loading order, as described herein. Renewable resources must provide the electricity product sought by the IOU, and, in light of the GHG adder, must be cost-competitive with fossil alternatives.
21. IOUs should file any outstanding proposed renewable energy contracts that rely upon the August 8th, 2003 ACR in R.01-10-024 before February 8th, 2005. Authority granted under the ACR will expire on February 8th, 2005.
22. The IOUs shall employ the Standard and Poor's (S&P) methodology for debt equivalence, except they shall use only a 20% risk factor instead of S&P's 30% risk factor, when evaluating bids in an all-source solicitation.
23. The IOUs shall justify the debt equivalence factors for PPAs on a case-by-case basis in their cost of capital proceedings.
24. The utilities shall refresh the annual capacity and energy tables provided in July in consultation with the Energy Division and the California Energy Commission staff.
25. We continue the required Monthly ERRA Report and Monthly Portfolio Risk Report. The objective of the report is to show that the transactions entered into are in compliance with the upfront standards identified by the Commission. In regards to the Quarterly Transaction Report, the IOUs are ordered to file a joint proposal to reformat the report in a way that will provide the Commission concise and coherent information, thereby streamlining the review process. The objective of the report is to show that the transactions entered into are in compliance with the upfront standards identified by the Commission. These reports will be reviewed by the Energy Division staff. If there are no protests and the staff concludes that the transactions entered into in that quarter comply with the utility's procurement plan, then by the Commission's Expressed Delegation of Authority, the Energy Division Director can approve the reports. However, if there are substantive protests and the staff takes issue with certain transactions, the staff will issue a draft resolution for the Commission's approval.
26. We adopt the following requirements for an All-Source Solicitations:
a. All-source open solicitations need to be transparent and competitive, and in addition, need to be open to all resources (conventional/renewable - turnkeys, buyouts, and PPAs).
b. Following the "loading order" contained in the Joint Agency Energy Action Plan is the first priority for IOU resource procurement, meaning that cost-effective energy efficiency and demand-side resources should be employed first. When these opportunities are captured, renewable generation is to be procured to the fullest extent possible - whenever an IOU issues an RFO for generation resources, it must justify its selection of fossil generation over renewable generation offers.
c. IOUs are directed to procure the maximum feasible amount of renewable energy in the general solicitations authorized by this decision, and will be allowed to credit this procurement towards their Renewables Portfolio Standards (RPS) targets. If an IOU succeeds in procuring sufficient renewable resources to meet its RPS Annual Procurement Target (APT) via an all-source RFO, it will not be required to undertake an RPS-specific solicitation.
d. The IOUs will employ the Least-Cost Best-Fit methodology when evaluating PPAs and utility-owned bids in an all-source open RFO, taking into account the qualitative and quantitative attributes associated with each bid.
e. GHG adders are to be used for bids in all-source open RFOs.
f. Debt equivalency will be considered when evaluating individual PPA bids, regardless of whether the bids are from a fossil, renewable, or an existing QF resource. IOUs are not to consider resource-specific debt equivalency risk factors.
g. When seeking Commission approval for PPA contracts, the IOUs will need to demonstrate, on a case-by-case basis, that the imputed debt equivalency was material. The IOUs will also need to provide the methodology used to calculate the debt equivalency adder applied to each PPA bid.
h. IOUs will not be allowed to recover costs in excess of its final bid price for utility-owned resources, but Cost Savings will be shared 50/50 between ratepayers and shareholders.
i. Mandate the use of 3rd party evaluators in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders.
27. By this decision we lift the ban on long-term affiliate transactions for transactions entered into through an open and transparent solicitation process. However, we maintain the ban on short-term transactions because the short-term market moves too fast and there is too great of a potential for abusive self-dealing, with little or no possibility for Commission oversight of these types of transactions. The utilities, and in particular their respective risk management committees, must maintain complete procurement planning independence from their affiliates.
28. The IOUs may contract directly with IEs, in consultation with their respective PRGs. The IOUs shall allow periodic oversight by the Commission's Energy Division. Alternatively, Energy Division can contract with IEs directly, but we will not require this given that this may result in unacceptable delays in the procurement process. Independent evaluators shall coordinate to a reasonable degree with assigned Energy Division management and staff as a check on the process.
29. With regard to consultants that assume the role of an IE, they shall abide by clear conflict of interest standards. We note that Federal Energy Regulatory Commission has provided guidance on this issue. We require that consultants abide by the appropriate Fair Political Practices Commission guidelines, in order to avoid the types of conflict of interest problems encountered by consultants working on behalf of the State of California and DWR during the 2000-2001 energy crisis. We must ensure the integrity of the third party evaluator process to provide firm assurances to the power market. We are open to comment from parties on specific conflict of interest standards.
This order is effective today.
Dated , at San Francisco, California.
167 Qualitative and quantitative attributes such as performance risk, credit risk, price diversity (10 vs. 20 yr. price terms), and operational flexibility etc.
168 Calpine opening brief, pp. 12
