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. 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. It is for this reason that the Commission believes that it should be responsible for addressing resource adequacy for all customers within the utilities' service territory; these customers constitute roughly 90% of the ISO load.
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% 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.
19. It is reasonable to adopt a 90% level of forward contracting 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 2005.
20. A 5% limit 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. 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%.
23. 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.
24. The issue of deliverability is an issue that needs further study.
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 are not well suited to actually construct new plant as it has been twenty to thirty years since they built fossil-fuel plants.
35. Situations may arise where competitive bids do not produce adequate response and the utility then needs to take on construction.
36. The presumption that utilities may favor their own capacity at the expense of third-party generators is well founded.
37. 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.
38. The utilities should rely on the formal RFP process to secure future long-term generating capacity resources.
39. A mix of contract lengths, sufficient to allow for new construction of power plants or transmission projects, is best.
40. 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.
41. The most direct and effective means to avoid any potential conflict of interest is to simply prohibit affiliate transactions.
42. 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.
43. Today, the three utilities have all successfully resumed full procurement and the financial prognosis for PG&E and SCE is much improved.
44. 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.
45. The methodology for determining debt equivalency is an accounting treatment, with little implication for cashflow.
46. Rating agencies use qualitative (i.e. subjective) approaches for assessing debt equivalency. The methodology and risk factor applied varies according to the particular credit rating agency.
47. In the Commission's procurement proceeding, we address issues of economic value, not accounting value, by taking into consideration the relative costs of alternative procurement options.
48. The rating process is not transparent.
49. The appropriate forum to address debt equivalency is in the Cost of Capital proceeding.
50. 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
51. 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.
52. 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.
53. 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.
54. 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.
55. 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.
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 this decision we authorize only the overall funding levels for procurement energy efficiency programs. We refer program specific review and approval, including required programmatic or budgetary modifications to utility procurement program proposals, to the Energy Efficiency Rulemaking 01-08-028 where the Commission will select a balanced portfolio of utility and non-utility energy efficiency programs for 2004 and 2005.
58. SDG&E's proposed non-bypassable charge approach for funding procurement energy efficiency provides a simple to understand, fair, and expeditious mechanism for providing utilities cost-recovery for procurement related energy efficiency activities.
59. 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.
60. We should refer the issue of energy efficiency incentives to R.01-08-028 for disposition in that rulemaking.
61. We should refer future issues related to program duration and program cycles to R.01-08-028 for disposition in that Rulemaking.
62. We should refer the issue of administration of energy efficiency programs authorized in this proceeding to R.01-08-028.
63. 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.
64. 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.
65. 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.
66. 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.
67. 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.
68. Funding for price-responsive demand response programs is also addressed in D.03-06-032.
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. We do not find that PG&E's proposed short-term solicitation adheres to this principle.
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 price for new capacity that results from a competitive all-source bidding process is the best way for an IOU to identify the basis for establishing the capacity payment that an existing QF seeking to renew a QF contract should receive.
77. The SRAC energy pricing formula is now out-of-date and inequitable.
78. It is important that the current methodologies to establish SRAC be modified.
79. 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.
80. 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.
81. 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.
82. 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.
83. The utilities short-term focus in the planning and procurement process should be on measuring the price risk exposure of its open portfolio position and managing that position, within a specified consumer risk tolerance level, in a manner that ultimately leads to the procurement and dispatch of power in a least-cost manner.
84. Portfolio risk should be reported using TeVar.
85. The Commission recognizes the importance of standardized risk reporting. By establishing a common benchmark, the Commission can assure itself that California's ratepayers, regardless of utility, are equally protected from adverse risk, and thereby can reap the benefits of reliable energy at low and stable rates.
86. We find a 99th percentile reporting will provide additional price volatility protection and should not be burdensome to the IOUs.
87. We find PG&E's and SDG&E's volumetric limits and length of contracts are reasonable.
88. We find that it is beneficial to continue the PRG process.
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. AB 57 and SB 1976, codified in Pub. Util. Code § 454.5, provides a regulatory procurement framework for the Commission.
3. 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.
4. 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.
5. The utilities should meet this 15% requirement by no later than the end of 2006, with interim benchmarks established. These are minimum standards. If cost-effective, the utilities may choose to meet this level sooner than 2006.
6. We should require the utilities to procure (under Commission jurisdiction) sufficient reserves to provide reliable service to all load located within their respective service territories. The utilities should be compensated for this service by a non-bypassable customer charge.
7. 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.
8. 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.
9. 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.
10. Under existing law, the utilities remain both the default provider, and provider of last resort for all load within their service territories.
11. The 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.
12. ESPs, as well as other LSEs, should be able to opt-out of this reserve charge if they can prove that they have acquired adequate reserves.
13. We should seek another round of comments, as part of this proceeding, as to how to assess and develop workable deliverability standards.
14. We do not have an adequate record on which to adopt an energy efficiency incentive.
15. AB 57 takes a neutral position on whether the utilities should own additional generation capacity.
16. We adopt these contract guidelines:
(a) For non-unit contingent contracts (i.e., contracts with unspecified resources) with existing resources, contracts should be authorized only for less than one-year in term and executed no more than one-year forward;
(b) 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
(c) There should be contractual arrangements such as step-in-rights and take-over type rights to address longer term issues of supplier nonperformance.
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 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.
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.
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 any long-term commitments brought to the Commission in the interim should meet a "no regrets" criteria.
30. The utilities should file on April 23, 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 on May 3, 2004.
31. Consistent with the July 3, 2003 Assigned Commissioner's Ruling in R.01-08-028, we authorize utility procurement energy efficiency budgets for the two-year period 2004 and 2005.
32. We should authorize procurement energy efficiency budget levels for the utilities for 2004 and 2005 as follows: PG&E - $25 million for 2004 and $50 million for 2005; SCE - $60 million for 2004 and $60 million for 2005; SDG&E - $25 million for 2004 and $25 million for 2005.
33. Consistent with our desire to proffer a uniform energy efficiency portfolio, the Commission should evaluate and select utility 2004 and 2005 procurement energy efficiency proposals using both the selection process and primary and secondary selection criteria adopted in D.03-08-067.
34. Respondent utilities should establish a one-way Procurement Energy Efficiency and Balancing Account (PEEBA) to track the costs and revenues associated with authorized programs in this proceeding. Costs associated with these accounts should be submitted simultaneously with utility monthly ERRA filings to the Energy Division for review on a monthly basis.
35. We should direct utilities in their future demand forecasts to include expected energy savings from non-utility programs that operate in their service territories.
36. We should adopt PG&E's demand reduction proposal.
37. SCE's new ACCP programs and its funding request needs to be reviewed in R.02-06-001 or its successor demand response rulemaking.
38. IOUs will file separate renewable procurement plans pursuant to Pub. Util. Code § 399.14(a)(3), thus the 2004 and long-term procurement plans currently under consideration do not constitute a filing of the required renewables plans.
39. Our approval of the 2004 procurement plans today does not "trigger" an RPS solicitation as detailed in D.03-06-071.
40. We should decline to adopt PG&E's request for an interim all-in benchmark of 5.37 cents per kWh for renewables.
41. We should deny PG&E's request for one-year renewables contracts, and focus attention instead on progress towards a full RPS solicitation in early 2004.
42. All renewables contracts must be filed for approval by the Commission by Advice Letter filing as required by D.03-06-071 and the ACR.
43. 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.
44. 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."
45. 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.
46. The utilities shall also update their 2004 and long-term plans to include interim procurement activity from 2003.
47. 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.
48. 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.
49. 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.
50. The PURPA purchase obligation is neither as broad or as absolute as the QF parties assert.
51. 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.
52. 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.
53. The PURPA purchase obligation originates out of a utility's need for power, either the need for energy or the need for capacity.
54. 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.
55. A utility must make a determination of need prior to offering a contract to a new QF.
56. The Commission should carefully consider how to modify the SRAC methodology and whether to seek legislative changes to Section 390.
57. Under Section 454.5, the Commission is required to (1) assess the price risk associated with each utility's portfolio; (2) ensure the utility has moderated its price risk; and (3) ensure the adopted procurement plan provides for just and reasonable rates, with an appropriate balancing of price stability and price level.
58. For 2004, the utilities should continue to use the interim CRT.
59. 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.
60. Since direct access transactions have been suspended, there is currently no means for customers to serve their own loads with remotely sited generation.
61. 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.
62. We should adopt the following portfolio risk notification:
(1) If between quarterly updates, a utility's estimated risk is over 125% of the CRT, the utility will promptly meet and confer with its PRG and discuss specific hedging strategies and plan modifications so that the value of the utility's open position will stay within the CRT.
(2) Within 10 days of the PRG meeting, the utility will file plan modifications in the form of an expedited application.
(3) Until the application is approved, the utility may purchase from spot markets, enter into bilateral trades, broker-assisted trades, or execute trades through an exchange.
63. We should adopt risk reporting using a by-product of VaR (TeVaR), measured on a 12-month rolling basis, at a 99% confidence level.
64. We should retain the existing modification of TURN's earlier 50% recommendation we adopted in D.02-12-074 for SCE's five-year requested authority.
65. We should adopt 73% limit on hedging for QF price risk.
66. 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.
67. Negotiated bilateral transactions should be separately reported in the utilities' quarterly compliance filings.
68. 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.
69. Each utility should update its fuel and power forecasts within 15 days from the effective date of this decision.
70. Each utility should meet and confer with its PRG on a quarterly basis.
71. Commission approval of the utilities' Procurement Plans does not preclude the need for DWR to conduct after-the-fact reasonableness reviews.
72. 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.
73. We should extend the disallowance cap we adopted in D.03-06-067 to the 2004 short-term plans.
74. Each utility should file by advice letter within 15 days a revised short-term plan that conforms to this decision.
75. The utilities should file their compliance reports by advice letter within 30 days of the end of the quarter.
76. Energy Division should, in consultation with each utility and its PRG, 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.
77. We revise the ERRA filings dates as set forth in Section VII C. of this decision.
78. For 2004, the utilities should only update the forecasts in their 2004 adopted short-term procurement plans, all other parts of their short-term procurement plans will be operational for 2005, unless modifications are ordered based on our review of revised 2004 long-term plans.
INTERIM ORDER
IT IS ORDERED that:
1. Respondent utilities shall establish a one-way Procurement Energy Efficiency and Balancing Account (PEEBA) to track the costs and revenues associated with authorized programs in this proceeding. Costs associated with these accounts shall be submitted simultaneously with utility monthly ERRA filings to the Energy Division for review on a monthly basis. Within 20 days of the effective date of this decision, utilities shall file advice letters establishing the methodology and surcharge rate for incremental procurement energy efficiency programs for PY 2004 and 2005.
2. The utilities shall file on April 23, 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 on May 3, 2004.
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 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. Each utility should file by advice letter within 15 days a revised short-term plan that conforms to this decision.
5. We revise the ERRA filings dates as set forth in Section VII C. of this decision.
This order is effective today.
Dated , at San Francisco, California.
