X. Assignment of Proceeding
Michael R. Peevey is the Assigned Commissioner and Christine M. Walwyn is the assigned Administrative Law Judge in this proceeding.
1. PG&E, SDG&E, and SCE are the respondent utilities.
2. This decision addresses the procurement planning issues set for further hearing in Section X.B. of D.02-10-062 and further delineated at the PHCs on February 18, 2003, March 7, 2003, and July 16, 2003.
3. Implementation of SB 1078 and SB 1038 legislation on the RPS has occurred through a separate workshop process.
4. The three service territories of the respondent utilities account for approximately 80% of California's electricity usage.
5. An Assigned Commissioner/ALJ Ruling issued in this proceeding on September 25, 2003, directed the convening of workshops to address the issue of standardizing, to the greatest extent possible, the load forecasts and methodologies used by the utilities to value and count resources.
6. Given the strong interaction between resource procurement and resource adequacy it is desirable that California rather than federal regulators make the necessary decisions.
7. A poorly designed resource adequacy framework could needlessly limit the Commission's flexibility as well as usurp the Commission's statutory responsibilities. Therefore, the Commission has routinely advocated, in a variety of forums, that it should address resource adequacy and procurement issues.
8. The ISO has recognized that resource procurement is primarily a state function, adopting at its November 21, 2002 Board meeting a resolution to defer consideration of its resource adequacy proposal and directing ISO staff to actively participate in this proceeding.
9. There is a trade-off between reliability and least-cost service given the cost to acquire and retain reserves. As SDG&E calculated, each additional 1% increase in reserve level adds $2.8 million to its costs. Adjusting for SDG&E's smaller size, costs for SCE and PG&E would be significantly higher.
10. There is a broad range of resource applications and technologies that California can rely on to meet its reserve levels.
11. The Energy Action Plan, as well as the guidance given for this proceeding, established a "loading order" for new resource additions emphasizing increased energy efficiency, demand response/dynamic pricing, and renewable energy.
12. The development, timing, and calculation of a reserve level can have a significant effect in promoting (or deterring) development of these new resources.
13. An appropriate balance should be achieved between meeting reserve requirements expeditiously while seeking to optimize the resource mix/portfolio. Paradoxically, rushing to implement a reserve requirement might further increase California's reliance on natural-gas fired resources, posing a different set of reliability concerns if there are supply constraints and price risks for the fuel input.
14. While no party advocates extensive reliance on the spot market, most parties believe that it may be both reasonable and prudent to allow for some portion of resource needs to be met through the spot market, a practice that some utilities responsibly engaged in under pre-AB1890 resource procurement.
15. A key factor that needs to be considered in evaluating resource adequacy is the current state of the wholesale energy market in the West, and the degree to which California's utilities have obtained or can access these resources to meet their energy needs.
16. We find that there are ample resources for California to meet demand for 2004 as well as adequate resources available for California to meet peak demand through 2007.
17. The Joint Recommendation proposes a 15% planning reserve, phased in beginning 2005 through 2008 based on equal percentage increments (i.e., 2% per annum increase).
18. A 15-17% reserve level, to be phased in by no later than January 1, 2008, strikes an appropriate balance for ensuring reliable service by providing incentives to encourage the retention of existing resources, whereas setting reserves at a higher level could require the utilities to make short-term investment decisions inconsistent with the Energy Action Plan's preferred "loading order" of new resources.
19. It is reasonable to adopt a 90% level of forward contracting for summer (May through September) peaking needs for each utility at one year in advance. We should allow the utilities the flexibility to justify to the Commission, on a case-by-case basis, excursions below this level. It is appropriate to defer implementation of this requirement to 2007.
20. A 5% target limitation on spot purchase provide a balance between flexibility and reliability and it is reasonable to continue to require the utilities to justify any higher level.
21. The preferred approach is for California to address the resource adequacy at the state level.
22. California should receive full credit and value for the long-term contracts entered into by the DWR to help California meet its energy needs during the crisis.
23. The issue of deliverability is an issue that needs further study.
24. Utility contracts without specified delivery points should not be permitted.
25. The utilities should prioritize resource additions consistent with our direction in D.02-10-062 and the loading order of resources stated in the Energy Action Plan.
26. We prefer that generation assets be sited in California and that they minimize the overall economic and environmental impact, including the costs of transmission and power losses.
27. To the extent it is cost-effective, utilities should be looking to new generation capacity that is not powered by natural gas, currently the prime mover for 42 percent of the electric energy consumed in this state.
28. There is a need for the utilities to commit to new or refurbished generation capacity in the next few years.
29. Since the long-term plans were filed, SCE and SDG&E have made proposals to purchase and own new generation resources.
30. There is an opportunity today to acquire additional generation cheaply and, therefore, we should not delay in setting out clear market structure rules.
31. California has a long history of reliable service being provided by utility-owned and operated generation plant and a recent painful history of rolling blackouts and high price spikes from reliance on third-party generators in a poorly designed competitive market.
32. Third-party generating capacity, if contracted properly, holds a number of advantages for California ratepayers.
33. We find that a portfolio mix of short-term transactions, new utility-owned plant, and long-term PPAs is optimal, combining the security of generation assets under the full regulatory oversight of the Commission with the flexibility of ten-year contracts, and the potential benefits of operating efficiencies and lower costs from a competitive market.
34. Utilities may face challenges when trying to construct new plant as it has been twenty to thirty years since they built fossil-fuel plants.
35. The presumption that utilities may favor their own capacity at the expense of third-party generators is well founded.
36. Careful design and monitoring of a competitive solicitation process and use of a least-cost dispatch standard are important means for addressing the potential for bias.
37. The utilities should rely on the formal RFP process to secure future long-term generating capacity resources.
38. Utilities may always propose utility-owned and/or utility-built generation at any time if they feel that it can be competitive, but should be required to justify the reasonableness of such proposals, as well as proposals for cost containment.
39. We should allow the utilities the authority and opportunity to bid in solicitations conducted by generators offering capacity and/or energy.
40. A mix of contract lengths, sufficient to allow for new construction of power plants or transmission projects, is best.
41. Exhibits from last year's hearings show that there were only a limited number of disallowance decisions from 1980-1996, and that the majority of these decisions and dollar adjustments involved affiliate transactions.
42. The most direct and effective means to avoid any potential conflict of interest is to simply prohibit affiliate transactions. However, we will grandfather already existing contractual relationships with affiliates (e.g., QF contracts) for the life of the existing plant in order to ensure that existing resources with such relationships can continue to serve California. The holding companies and affiliates of each utility should plan for future generation investment to be made outside of the utility's service territory and sold to other load serving entities. Two exceptions we need to address are the gas storage and transportation transactions that SDG&E needs to conduct with SoCalGas and that PG&E may need to conduct with separate company departments and unregulated affiliates.
43. In D.02-10-062, we addressed the utilities' capability to meet their obligation to serve, and found that PG&E and SCE did not need to obtain an investment grade credit rating prior to resuming the procurement role.
44. Today, the three utilities have all successfully resumed full procurement and the financial prognosis for PG&E and SCE is much improved.
45. Debt equivalency is a term used by credit analysts for treating long-term non-debt obligations - such as PPAs, leases, or other contracts - as if they were debt in assessing an entity's debt capacity. The risk factor can be 0% to 100% of these contractual payments, depending on the type of obligation.
46. The Commission should address the impact of debt equivalency on the utilities' financial condition. The appropriate forum to address debt equivalency is in the Cost of Capital proceeding for each utility.
47. During 2004, the utilities need to begin the normal cycle for procuring short-term products for 2005. Purchases for 2005 should be limited to contracts of one year or less in duration.
48. A ten-year procurement planning horizon is appropriate and should provide relatively long notice to all industry players of the state's anticipated needs and allow them to respond appropriately.
49. Long-term plans should include expected load and energy requirements, not only at their expected, or median, levels, but also at the 95th percentile (that is, the one-in-twenty years case) of expected need levels. We also expect the utilities to continue to consider a core/non-core scenario in their forecasts. The utilities should also supply a range of forecasts of load in their revised 2004 long-term plans in order to account for potential changes in community choice aggregation and direct access.
50. As part of their long-term plans, the utilities should identify which procurement proposals will require environmental review, special permits, separate applications, or other regulatory procedures or proceedings.
51. The CEC's IEPR "information and analyses" should form the base case. If a utility does not find it appropriate to use that as its base case, it should include the IEPR case along with its preferred base case. The utility should report how and why the assumptions underlying its forecasts differ from those of the CEC forecasts.
52. The long-term plans should reflect the outcome of the workshops on reserve requirements. If that process is not concluded, the utilities should make their best estimate of the outcome of that process and estimate accordingly.
53. Long-term plans should reflect the most recent fuel-price forecasts available at the time of the plans' preparation and should include fuel-price variation as an element of the plans.
54. Future long-term procurement plans should reflect fully the expected range of fuel prices and purchased power costs at least up to the 95th percentile of the expected distribution.
55. SCE's revised long-term plan should contain scenarios both including and excluding the Mohave power plant to ensure that the future of this plant and A.02-05-046 are not prejudged.
56. Long-term plans should include not only the utilities' preferred portfolio choice for how to meet their needs, but also other portfolio alternatives/ variations to meet those needs. The utilities should present estimated ratepayer costs associated with each method of meeting their needs, and should include some metric of the variability of those costs.
57. In D.02-10-062, we expressed our preference to adopt a uniform incentive mechanism to provide an opportunity for utilities to balance risk and reward in the long-term procurement process.
58. We should refer future issues related to program duration and program cycles to R.01-08-028 for disposition in that Rulemaking.
59. We should refer the issue of administration of energy efficiency programs authorized in this proceeding to R.01-08-028.
60. We should refer the issue of the role of non-utilities in the delivery of the procurement-related energy efficiency programs authorized in this proceeding to R.01-08-028.
61. We should refer the question of potential financial risks associated with carbon dioxide emissions to R.01-08-028, to be considered in the context of the avoided cost methodology -- as part of the overall question of valuing the environmental benefits and risks associated with utility current or future investments in generation plants that pose future financial regulatory risk of this type to customers.
62. Demand response, like energy efficiency, is a demand-side resource for the utilities. While energy efficiency resources can often meet baseload procurement needs, demand response can fill on-peak requirements.
63. In D.02-10-062, we directed that the demand response targets adopted in R.02-06-001 should be integrated into the utilities long-term plans.
64. In D.03-06-032, the Commission adopted demand response goals for each utility and directed that the IOUs include the MW targets for calendar years 2003 through 2007 in their procurement plans, specifically stating the filings in this proceeding should include: numeric targets coinciding with the findings in this decision; documentation of the amount of demand response (price-triggered) to be achieved by July 1 of each calendar year (with the exception of 2003, where the goals shall be met by the end of the calendar year); which programs and/or tariffs the IOU will rely upon to achieve the targets; and a contingency plan for covering capacity needs should the utility fall short of meeting the demand response goals.
65. Funding for price-responsive demand response programs is also addressed in D.03-06-032.
66. It is difficult to compare and extrapolate the distributed generation forecasts from the utilities long-term procurement plans.
67. In guiding the utilities' long term planning process, we focus on developing an integrated resource approach, one that recognizes our policy priority for demand-side resource additions, and that optimizes generation and transmission resources.
68. There are about 600 Qualifying Facilities (QFs) under contract to PG&E, SCE, and SDG&E. These QFs supply power used to serve about one-fourth of the combined retail load for the three utilities.
69. The QF industry marked its beginning with the passage of the Public Utility Regulatory Policies Act (PURPA) of 1978 which required utilities to purchase QF power under certain terms and conditions.
70. By 2008, expired QF contract capacity is expected to exceed 1,000 MW and approach 1,800 MW by 2010.
71. QF power provides numerous benefits to California, including environmental attributes, local power production, and economic development.
72. We encourage both the QF community and the IOUs to be creative and flexible in negotiating renewed contracts for existing QF facilities and new contracts for new facilities.
73. In D.03-12-062, we committed to reevaluating the pricing methodologies for QF power in the future.
74. In compliance with PURPA and recent FERC decisions, we should provide an opportunity for existing QFs to continue to provide power to the utilities in a manner that encourages facility maintenance and upgrade.
75. We find that there is a potential need for at least some of the 300 MW of additional peaker capacity proposed by the CPA to be operational by 2005, either in the service area of PG&E or in the service area of SCE.
76. We find that the long-term peaking contracts proposed by the CPA potentially represent cheaper peaking alternatives and should be considered fairly by the utilities.
77. We find that the CPA engaged in an objective and reasonable process for soliciting peaking projects, with the intent of providing the results to the utilities in good faith.
78. We should direct the utilities to present an assessment of their peaking needs in their long-term plans and to work cooperatively with CPA in areas where the utilities see a need to finance projects and the CPA can provide a favorable financing source.
1. The Commission's legislative mandate is to ensure that all utility customers receive reliable service at just and reasonable rates, as specifically stated in Pub. Util. Code § 451 with § 701 giving the Commission power to undertake all necessary actions to properly regulate and supervise California's investor-owned utilities.
2. The Commission has authority to impose reserve requirements on non-utility load serving entities (such as Energy Service Providers) under Pub. Util. Code 394.
3. AB 57 and SB 1976, codified in Pub. Util. Code § 454.5, provides a regulatory procurement framework for the Commission.
4. In order to provide reliable service, each Load Serving Entity within PG&E's, SCE's, and SDG&E's service territories should have an obligation to acquire sufficient resources for their customers load.
5. In D.02-12-074, the Commission provisionally adopted a 15% reserve level subject to further revision in this proceeding. Based on the record developed in this proceeding, we should reaffirm and make permanent the 15 % reserve level, as well as allow for a range up to 17% to account for the lumpiness of investment.
6. A 15-17% reserve level also strikes an appropriate balance for ensuring reliable service by providing incentives to encourage the retention of existing resources, whereas setting reserves at a higher level could require the utilities to make short-term investment decisions inconsistent with the Energy Action Plan's preferred "loading order" of new resources.
7. The utilities should meet this 15-17% requirement by no later than January 1, 2008. In their procurement filings, the utilities should justify reserve levels above 15%, although we recognize that given the inherent "lumpiness" of resource additions, the utilities may acquire reserves above 15%, depending on the timing of the resource additions to meet demand.
8. Deferring to the ISO is inconsistent with both FERC and the ISO's stated policies of giving deference to the State to address resource adequacy issues.
9. Although the Commission chose to narrowly limit the exercise of its jurisdiction in implementing Pub. Util. Code § 394, it would be appropriate if the Commission were to decide that additional safeguards should be imposed upon ESPs under the requirements of Pub. Util. Code § 394.
10. Requiring ESPs to meet a reliability obligation, as allowed under Pub. Util. Code § 394, would not conflict with the "terms and conditions" under which direct access customers receive service.
11. Under existing law, the utilities remain both the default provider, and provider of last resort for all load within their service territories.
12. We should seek another round of comments, as part of this proceeding, as to how to assess and develop workable deliverability standards.
13. We do not have an adequate record on which to adopt an energy efficiency incentive.
14. AB 57 takes a neutral position on whether the utilities should own additional generation capacity.
15. We adopt these contract guidelines:
(a) For contracts for existing resources, the utility would have dispatch rights to specified resources. Contract language should state that only specific plants could provide the power, and perhaps ancillary services, with no allowance for substitution from the market; and
(b) There should be contractual arrangements such as step-in-rights and take-over type rights to address longer term issues of supplier nonperformance.
16. In D.03-06-076, the Commission found that the ban on affiliate transactions was properly noticed, jurisdictional, constitutional, violated no federal laws, and the record supported the need for a moratorium on utility procurement from its own affiliates until adequate safeguards are fashioned.
17. D.03-06-076 also sustained Standard of Behavior 1.
18. In allowing the utilities to directly participate in owning new generation facilities, we recognize that we will need to be vigilant in overseeing that no bias occurs in selecting, or dispatching the resources.
19. We do not have the same level of oversight and authority over affiliate transactions that we do over direct utility operations. We recognize that cross-subsidies and anti-competitive conduct has occurred in the past in affiliate procurement transactions and that it could occur in the future under the market structure we adopt here.
20. The holding companies and affiliates of each utility should plan for future generation investment to be made outside of the utility's service territory and sold to other load serving entities.
21. SD&E should file a revised Exhibit 70 to reflect that the risk management committee(s) overseeing SDG&E's electric procurement operations and DWR-related gas procurement operations are comprised solely of SDG&E management. This filing should be by Advice Letter within 30 days of the effective date of this decision.
22. A management audit to review whether negotiated transactions with SoCalGas should be subject to special transaction rules and reporting should be undertaken. The management audit should be narrowly focused on two issues: SEU's participation in the risk management committee structure for SDG&E procurement operations; and any rules or reporting needed for SDG&E's energy procurement transactions with SoCalGas. The Commission's Energy Division should draft the scope of work required, select an independent auditor, and oversee the analysis. At the conclusion of the analysis, an audit report should be filed with the Commission and served on all parties to this proceeding. The auditor should remain available to explain the report's findings, and testify in evidentiary hearings at the Commission on the findings included in the report. SDG&E should place the audit costs in a memorandum account.
23. In Res. E-3838, we apply the affiliate transaction rules to all procurement transactions between SDG&E and SoCalGas, and set an interim standard for transactions SDG&E enters on behalf of DWR with either itself or an affiliate for services which are paid on a negotiated basis. We should adopt this standard on an interim basis for all SDG&E's procurement transactions.
24. We should direct a management audit of PG&E's transactions for electric procurement for its customers and gas procurement for DWR contracts with other departments and affiliates.
25. We adopt here a permanent ban on affiliate transactions for procurement with the following exceptions:
(1) "Anonymous" transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa.
(2) Transactions for natural gas services between SDG&E and SoCalGas and between PG&E and affiliates and operating divisions that are found necessary and beneficial for ratepayer interests. These transactions should be subject to the rules adopted in Res. E-3838 and Res. E-3825 pending receipt and review of the management audits ordered here.
(3) Grandfathering of already existing contractual relationships with affiliates (e.g., QF contracts) for the life of the plant.
26. Each utility should make the investments necessary to meet their obligation to serve their customers at just and reasonable rates. Care should be taken not to make commitments that could later result in stranded costs.
27. We should authorize the utilities to procure for 2005 under the same operational authority contained in the adopted 2004 short-term plans, except that authority for 2005 should be limited to the first three quarters, with contracting authority of up to one year in duration.
28. For their next long-term plan filings, all three utilities should include an appropriate level of long-term commitment to additional power plants or plant-specific purchase power contracts.
29. Revised long-term plans should be submitted and approved in 2004 and any long-term commitments brought to the Commission in the interim should meet a "no regrets" criteria.
30. The utilities should file by the end of March 2004, a working outline of their long-term plans that includes the level of detail and specific scenarios addressed in this decision, the means by which they will incorporate the resource adequacy framework developed through workshops, and a showing that the material provided in the public filing will allow for meaningful participation by all parties. Such plans shall meet all the requirements set forth in this decision.
31. In the revised 2004 long-term plans, the utilities should also provide a forecast of the percentage of retail sales met each year by renewables, indicating the projected year for achieving the 20 percent RPS target, and maintaining or increasing that percentage in future years. Each IOU should also modify its plan to include an accelerated RPS target renewables procurement scenario that evaluates any resulting changes to its overall energy procurement portfolio.
32. The utilities should include in their updated long-term plans several forecasting scenarios, including widespread formation of community choice aggregators, as well as a core/noncore scenario.
33. The utilities shall also update their 2004 and long-term plans to include interim procurement activity from 2003.
34. The utilities' 2004 revised long-term procurement plans should include a more robust discussion of distributed generation to include: (1) a line item entry clearly identifying distributed generation separate and apart from other entries such as energy efficiency and departing load; (2) the energy (GWh) and demand (MW) reduction attributed to distributed generation; and (3) a description of the technologies the utility includes in its definition of distributed generation as well as a statement noting whether its forecast includes utility-side distributed generation, such as QFs.
35. We should not adopt the Joint Parties recommended approach for a set-aside because it could predetermine the outcome of a new rulemaking on distributed generation.
36. A minimum requirement for the 2004 revised long-term plans is that the IOUs work with the ISO on defining conceptual scenarios for resources imported into the ISO control area and deliverable to the individual IOU's load.
37. Renewal of existing QF contracts should be required for a minimum of five years, using the SO1 contract structure at existing SRAC prices. Such renewed contracts should include a provision that the pricing methodology may be modified by subsequent Commission action.
38. New QFs may seek to negotiate contracts with utilities under the following circumstances: (i) voluntary QF participation in IOU competitive bidding processes; (ii) renegotiation by the QF and the IOU on a case-by-case basis of contract terms that explicitly take into account the IOU's actual power needs and that do not require the IOU to take or pay for power that it does not need.
39. Changes to net metering tariffs such as City of San Diego's should be considered in the distributed generation rulemaking, where those changes may be considered in the context of broader distributed generation policy, including ratesetting and cost allocation issues.
40. Since direct access transactions have been suspended, there is currently no means for customers to serve their own loads with remotely sited generation.
41. The use of the "net" approach is appropriate for those QF and other on-site generation resources that contract with the utility for stand-by service.
42. Each utility should meet and confer with its PRG on a quarterly basis.
43. Commission approval of the utilities' Procurement Plans does not preclude the need for DWR to conduct after-the-fact reasonableness reviews.
IT IS ORDERED that:
1. The utilities shall file by the end of March 2004 a working outline of their long-term plans that includes the level of detail and specific scenarios addressed in this decision, the means by which they will incorporate the resource adequacy framework developed through workshops, and a showing that the material provided in the public filing will allow for meaningful participation by all parties. Such plans should meet all of the requirements set forth in the text of this decision. A schedule will be addressed in the new Order Instituting Rulemaking.
2. In order to provide reliable service, each Load Serving Entity within Pacific Gas and Electric Company's, Southern California Edison's, and San Diego Gas & Electric Company's service territories should have an obligation to acquire sufficient resources for their customer load.
3. In the revised 2004 long-term plans, the utilities shall also provide a forecast of the percentage of retail sales met each year by renewables, indicating the projected year for achieving the 20 percent Renewable Portfolio Standard (RPS) target, and maintaining or increasing that percentage in future years. Each IOU shall also modify its plan to include an accelerated RPS target renewables procurement scenario that evaluates any resulting changes to its overall energy procurement portfolio.
4. For Qualifying Facilities (QF)s with existing contracts expiring before December 31, 2005, the utilities shall offer five-year Standard Offer 1 (SO1) contracts at short-run avoided cost (SRAC) prices. The contracts shall include the provision that the pricing terms may change if the Commission subsequently modifies its policy on QF pricing methodology.
5. We revise the ERRA filings dates as set forth in the text of this decision.
6. The utilities shall present an assessment of their peaking needs and alternatives for meeting those needs, including analysis of the CPA Peaker Initiative, in their long-term plans, and work cooperatively with the CPA in areas where they see a need to finance projects where the CPA can provide a favorable financing source.
7. We direct utilities to submit programmatic energy efficiency proposals in Rulemaking (R.) 01-08-028 with energy savings and demand reductions goals equal to or greater than the energy savings and demand reductions forecasted in utility long-term plan forecasts.
8. We require utilities to present to the Commission in this rulemaking within twenty-days of this decision the methodologies they will use to ensure that forecasted measured savings of energy efficiency savings and demand reductions in utility long-term plans in this rulemaking are equivalent to the savings calculated for measures used in utility savings assumptions for procurement related energy efficiency programs submitted in R.01-08-028.
9. For purposes of meeting load requirements of 2005 in a seamless manner, the utilities are directed to provide updated forecasts of 2005 open positions by compliance advice letter within 30 days of the effective date of this order, and are authorized to procure for the first three quarters of 2005 under the same operational authority contained in the 2004 short-term plans adopted in D.03-12-062, except that contracts for 2005 need shall not extend beyond one year.
10. The utilities are permitted to participate in RFPs and/or open seasons conducted by generators offering capacity and/or energy.
11. Within thirty days of the effective date of this decision, interested parties should file comments addressing the confidentiality issues set forth in this decision.
This order is effective today.
Dated January 22, 2004, at San Francisco, California.
MICHAEL R. PEEVEY
President
CARL W. WOOD
LORETTA M. LYNCH
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
I will file a concurrence.
/s/ MICHAEL R. PEEVEY
President
