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 last year 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. D.03-12-062 addressed the utilities' short-term procurement plans for 2004.
4. Implementation of SB 1078 and SB 1038 legislation on the RPS has occurred through a separate workshop process.
5. The three service territories of the respondent utilities account for approximately 80% of California's electricity usage.
6. 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.
7. Additional workshops on a variety of issues are necessary, including development of additional forecast scenarios, accounting for resources, deliverability of resources, other reserve and resource adequacy questions, and confidentiality issues.
8. Given state accountability for resource adequacy, it is preferable that California, rather than federal regulators, shape the the necessary procurement policy framework.
9. A poorly designed resource adequacy framework could needlessly limit the Commission's flexibility to provide direction to the utilities' on procurement matters as well as eviscerate 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.
10. The ISO has recognized that resource procurement is primarily a state function, and adopted a resolution at its November 21, 2002 Board meeting to defer consideration of its resource adequacy proposal and directed ISO staff to actively participate in this proceeding.
11. 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.
12. There is a broad range of resource applications and technologies that California can rely on to meet its reserve levels.
13. 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.
14. The development, timing, and calculation of a reserve level can have a significant effect in promoting development of these new resources.
15. 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.
16. While no party advocates extensive reliance on spot markets, most parties believe that it may be both reasonable and prudent to allow for some portion of resource needs to be met through spot markets, a practice that some utilities responsibly engaged in under pre-AB1890 resource procurement.
17. Resource adequacy is affected by 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.
18. 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 and possibly 2008.
19. Ample resources in the West through at least 2007 allow the utilities to refine their long-term plans in 2004, albeit on an aggressive schedule, for adoption by the end of the year.
20. 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).
21. A 15% reserve level 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.
22. A four year phase-in period for a 15% reserve requirement is a prudent timeline for action that will ensure reliability for California while not upending capacity markets or creating potential stranded costs if community choice aggregation is widely adopted or direct access is reinstated.
23. It is reasonable to adopt a 90% level of forward contracting for each utility's peak summer needs one year in advance and it is appropriate to defer implementation of this requirement until 2005.
24. A 5% limit on spot purchases as a means of meeting resource adequacy needs provides a balance between flexibility and reliability and it is reasonable to continue to require the utilities to justify any higher level of reliance.
25. When the utility has met its resource adequacy requirements and there is sufficient capacity in the market and under contract to ensure reliability but can dispatch its resources in a least-cost manner by going beyond the 5% spot purchase limit for energy, this is reasonable and rational behavior.
26. The preferred approach is for California to address the resource adequacy at the state level.
27. Additional workshops are necessary in order to determine which entity should enforce resource adequacy provisions with ESPs and community aggregators.
28. As a result of the tight energy supplies and market manipulation of the California energy crisis, many ESPs were unable to provide reliable service to their customers. ESPs failed to honor their contractual obligations to customers, and direct access loads plummeted from 15% to 2%.
29. 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.
30. Deliverability and locating of resources need further study and consideration.
31. 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.
32. 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.
33. 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.
34. There is a need for the utilities to commit to new or refurbished generation capacity in the next few years but not immediately.
35. Since the long-term plans were filed, SCE and SDG&E have made proposals to purchase and own new generation resources.
36. 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.
37. 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.
38. Situations may arise where competitive bids do not produce adequate response.
39. The presumption that utilities may favor their own capacity at the expense of third-party generators in a competitive solicitation is not unreasonable.
40. Use of a least-cost dispatch standard is an important means for addressing the potential for utility bias in system operations.
41. A mix of contract lengths, sufficient to allow for new construction of power plants or transmission projects, is best.
42. 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.
43. The most direct and effective means to avoid any potential conflict of interest is to simply prohibit affiliate transactions.
44. Grandfathering already existing contractual relationships with affiliates for the life of the existing plant ensures that these resources continue to be available to serve California.
45. 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.
46. Today, the three utilities have all successfully resumed full procurement and the financial prognosis for PG&E and SCE is much improved.
47. 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. The risk factor assigned by a credit analyst can account for 0% to 100% of a PPA's fixed payments, depending on the type of PPA structure.
48. Rating agencies use qualitative or subjective approaches for assessing debt equivalency. The methodology and risk factor applied varies according to the particular credit rating agency.
49. The credit rating process is not transparent.
50. In the Commission's procurement proceeding, we address issues of economic value by taking into consideration the relative costs of alternative procurement options.
51. The appropriate forum to address debt equivalency is in the Cost of Capital proceeding.
52. 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.
53. 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.
54. As part of its long-term plan, the utilities should identify which procurement proposals will require environmental review, special permits, separate applications, or other regulatory procedures or proceedings.
55. The utilities should include the CEC's IEPR "information and analyses" in their plans but should make their own assessment as to whether the IEPR information should be used as the base case for any resource planning assessments, demand forecast and fuel analyses that examine more than two years into the future. If CEC's IEPR is not the base case, the utilities should report in their long-term plans how and why the assumptions underlying their forecasts differ from those of the CEC forecasts.
56. The utilities should supply a range of forecasts of load in their revised long-term plans due to the potential instability of the customer base due, in part, to the uncertain status of community choice aggregation and direct access.
57. 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.
58. Future long-term procurement plans should reflect fully the expected range of fuel prices at least up to the 95th percentile of the expected distribution.
59. 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.
60. Future long-term plans should explicitly address the benefits of specific locations for resources and actively integrate location of resources into the long-term planning process, as well as deliverability.
61. Non-unit contingent contracts should be the subject of further workshops to ensure that California can take advantage of seasonal power exchanges.
62. Non-unit contingent contracts, such as the Sempra contract, that do not specify a delivery point are not beneficial to providing reliable electricity to California.
63. 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 is not prejudged.
64. 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.
65. We should refer future issues related to program duration and program cycles to R.01-08-028 for disposition in that rulemaking.
66. We should refer the issue of administration of energy efficiency programs authorized in this proceeding to R.01-08-028.
67. In future procurement proceedings, we intend to open the process for application for procurement energy efficiency programs to non-utility parties as well as utilities.
68. 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 and 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.
69. One goal of the RPS program is to foster a long-term market for renewable energy by providing contracts of 10 or more years.
70. It is difficult to compare and extrapolate the distributed generation forecasts from the utilities long-term procurement plans.
71. 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.
72. 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.
73. 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.
74. By 2008, expired QF contract capacity is expected to exceed 1,000 MW and approach 1,800 MW by 2010.
75. We encourage both the QF community and the IOUs to be creative and flexible in negotiating the terms of renewed contracts for existing QF facilities.
76. The manner in which each utility identifies and manages price risk, in a manner that optimizes the value of its overall supply portfolio for the benefit of its bundled service customers, is the risk management function.
77. We do not find that there is a need for 300 MW of additional peaker capacity to be operational by 2005, either in the service area of PG&E or in the service area of SCE.
78. We direct the utilities 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.
79. Based on FERC's August 12, 2003 decision, all parties agree that 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.
1. The motions of Ratepayers for Affordable Green Energy and Constellation NewEnergy, Inc., to intervene in this proceeding should be granted.
2. 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.
3. AB 57 and SB 1976, codified in Pub. Util. Code § 454.5, provides a regulatory procurement framework for the Commission.
4. 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.
5. A 15% 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.
6. The utilities should meet this 15% requirement by no later than the end of 2008, with interim benchmarks established.
7. We should require the utilities to procure (under Commission jurisdiction) sufficient reserves to provide reliable service to all utility load located within their respective service territories.
8. Deferring to the ISO on resource adequacy (and thus to the FERC) is inconsistent with both the FERC's and the ISO's stated policies of defering to states, and thus California, on 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. A reserve surcharge would be consistent with other charges the Commission has recently adopted to ensure that all customers pay their share of ensuring the reliability of the electric system.
13. ESPs, as well as other LSEs, should be able to opt-out of any reserve charge if they can prove that they have acquired adequate reserves.
14. We should seek another round of comments, as part of this proceeding, as to how to assess and develop workable deliverability standards.
15. We do not have an adequate record upon which to adopt an energy efficiency incentive.
16. AB 57 takes a neutral position on whether the utilities should own additional generation capacity.
17. 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.
18. D.03-06-076 also sustained Standard of Behavior 1.
19. 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.
20. 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.
21. 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.
22. 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.
23. 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.
24. 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.
25. 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.
26. 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) Already existing contractual relationships with affiliates (e.g., QF contracts) are grandfathered for the life of the existing plant in order to ensure that existing resources with such relationships can continue to serve California.
27. 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.
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 the Commission is disinclined to approve additional long-term commitments until the long-term plans are complete and approved.
30. The utilities should file in March of 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. Interested parties may file comments on the outlines in mid April 2004.
31. We should direct utilities in their future demand forecasts to include expected energy savings from non-utility programs that operate in their service territories.
32. IOUs will file separate renewable procurement plans pursuant to Pub. Util. Code § 399.14(a)(3), and thus the long-term procurement plans currently under consideration do not constitute a filing of the required renewables plans.
33. PG&E's position that "unmet long-term resource needs" means a specific utility's resource needs, as defined and identified by that utility, is inconsistent with the statewide focus and purpose of the RPS legislation.
34. SCE's modeling of renewables as a "generic" block of energy, irrespective of resource type is inconsistent with Pub. Util. Code § 454.5(b)(2), which requires procurement plans to include "[a] definition of each electricity product, electricity-related product, and procurement related financial product, including support and justification for the product type and amount to be procured under the plan."
35. 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.
36. The utilities shall also update their long-term plans to include interim procurement activity from 2003.
37. 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.
38. 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.
39. A minimum requirement for the revised 2004 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.
40. The PURPA purchase obligation is neither as broad or as absolute as the QF parties assert.
41. We should balance the PURPA mandate that utilities are to purchase energy and capacity from QFs with the overarching requirement that electric utilities may only charge just and reasonable rates for the power they supply to their customers.
42. Renewal of existing QF contracts should be encouraged, so long as they are priced within the range of comparable replacement power, to the extent that they can meet the IOUs' need for power.
43. The PURPA purchase obligation originates out of a utility's need for power, either the need for energy or the need for capacity.
44. Thus, as to existing QFs with expired, or soon-to-be expired, utility contracts, we conclude that the potential anomaly between the nature of the power offered by a QF and the actual system needs of an IOU can be resolved in any one of three ways: (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; and (iii) appropriate revisions by the Commission to the SRAC methodology that will assure that existing QFs entering into renewed contracts on standard terms only receive payment for power that the IOU actually needs and can use. Compliance with any one of these three alternatives should assure fairness both to the QF community and to the IOUs and their ratepayers.
45. A utility must make a determination of need prior to offering a contract to a new QF.
46. For 2004, the utilities should continue to use the interim CRT.
47. 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.
48. Since direct access transactions have been suspended, there is currently no means for customers to serve their own loads with remotely sited generation.
49. 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.
50. SCE's proposal to not apply a risk screening criteria to transactions of less than a certain length in contravenes the requirements of AB 57.
51. Negotiated bilateral transactions should be separately reported in the utilities' quarterly compliance filings.
52. Where there are five or fewer counterparties in the relevant market, we should authorize the use of negotiated bilaterals for standard products for two categories of gas products cited by SCE: gas storage and pipeline capacity.
53. Commission approval of the utilities' Procurement Plans does not preclude the need for DWR to conduct after-the-fact reasonableness reviews.
54. SCE should amend its plan to comply with the pro-rata cost allocation method of DWR contracts that the Commission adopted in D.02-09-053.
55. The utilities should file their compliance reports by advice letter within 30 days of the end of the quarter.
56. Energy Division should, in consultation with each utility, select an outside auditor to review and verify the quarterly compliance filings, and the audit expenses should be paid by the utilities and recorded in a memorandum account. A resolution for the Commission's agenda should only be prepared if Energy Division or the outside auditor find transactions or procurement practices that are not in compliance with the adopted plans.
57. We revise the ERRA filings dates as set forth in this decision.
IT IS ORDERED that:
1. The motions of Ratepayers for Affordable Green Energy and Constellation NewEnergy, Inc., to intervene in this proceeding are granted.
2. The Commission shall hold a series of workshops in the first quarter of 2004, as described herein.
3. 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. Interested parties may file comments on the outlines in mid April 2004, with the exact dates to be determined in a subsequent ALJ ruling.
4. 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 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.
5. The utilities should 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.
6. We revise the ERRA filings dates as set forth in this decision.
This order is effective today.
Dated , at San Francisco, California.
CERTIFICATE OF SERVICE
I certify that I have by electronic mail, mailed to the parties of which an electronic mail address has been provided; this day served a true copy of the original attached Revised Alternate Proposed Decision of Commissioner Loretta Lynch on the Proposed Decision of ALJ Christine Walwyn on all parties of record for proceeding R.01-10-024 or their attorneys of record.
Dated January 12, 2004, at San Francisco, California.
/s/ EVELYN P. GONZALES |
Evelyn P. Gonzales |
NOTICE
Parties should notify the Process Office, Public Utilities Commission, 505 Van Ness Avenue, Room 2000, San Francisco, CA 94102, of any change of address to insure that they continue to receive documents. You must indicate the proceeding number on the service list on which your name appears.
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