8. Assignment of Proceeding

Michael R. Peevey is the assigned Commissioner and Carol A. Brown is the assigned Administrative Law Judge in this proceeding.

1. The purpose of this decision is to review the long-term procurement plans submitted by PG&E, SCE and SDG&E on December 11, 2006, and approve the plans to the extent they comply with the directives given in the February 16, 2006 OIR and the September 25, 2006 ACR/Scoping Memo to give the utilities the authorization necessary to plan and procure to provide reliable service for the 2007 - 2016 planning period.

2. The primary principal guiding the Commission in its review of the plans is whether the IOUs are procuring preferred resources as set forth in the Energy Action Plan, in the order of energy efficiency, demand response, renewables, distributed generation and clean fossil-fuel resources.

3. The IOUs were directed to prepare different candidate plans and to provide for each plan the expected GHG emissions; the RPS percentages; the percentage of demand response as a percentage of RA; and the energy efficiency savings from committed and uncommitted programs.

4. The IOUs were further directed to weigh the different plans for ratepayer costs and reliability.

5. An overarching problem in all the IOUs' plans is the absence of any scenario analysis regarding the types of resources the IOUs should use to fill their net short positions to best transition to the forthcoming GHG-constrained world.

6. The IOUs plan on filling and projecting to fill their net short positions with conventional resources, without providing a highly developed analysis to support this conclusion.

7. We find that in general all three LTPPs do not fully reflect our goals in regards to addressing preferred resources and the EAP loading order and GHG reductions.

8. Preferred resources are those resources that are procured in accordance with the State's preferred loading order of energy efficiency, demand response, renewables and distributed generation in order to meet the State's environmental goals.

9. Going forward, the IOUs will be required to reflect in the design of their RFOs compliance with the preferred resource loading order and GHG reduction goals and to demonstrate how each application for fossil generation filed based on the procurement authority granted in this proceeding fits into each IOU's GHG reduction strategy.

10. This decision establishes a skeleton upon which future LTPP filings in the biennial cycle may build and grow and identifies key issues and areas of planning for the IOUs to address in their 2008 LTPP filings.

11. With our approval of the 2006 LTPPs, these plans supersede all previous procurement plan authority and the IOUs may no longer continue to conduct procurement under the short-term plans originally submitted in April/May 2003.

12. The IOUs were directed to use the CEC's IEPR load forecast in preparing their need assessments.

13. We based findings for the IOU need determination tables on the CEC's base case, 1 in 2 summer temperature demand forecast.

14. We established PG&E's need determination using the CEC's base case, and adjusted PG&E's preferred plan demand forecast.

15. We established SCE's need determination using the CEC's base case and adjusted SCE's recommended plan accordingly.

16. We established SDG&E's need determination using the CEC's base forecast and adjusted SDG&E's preferred plan accordingly.

17. We find that PG&E, SCE and SDG&E's assessment that system need is not impacted by possible future load shifting to DA and CCA is reasonable and that future DG and MDL is captured by the historical trends used to develop the forecast.

18. We do not intend to relitigate EE treatment in the CEC load forecast in this proceeding.

19. We concur with DRA's recommendation that the CEC and the IOUs need to come to a consensus on what proportion of the Commission's EE goals are embedded in the CEC load forecast, and with TURN's position that the IOUs accurately reflect their EE goals in their LTPPs.

20. We agree with the CEC's recommendation that the portion of IOU's EE goals not included in the forecast (i.e., the uncommitted EE that does not overlap with EE-induced reductions embedded in the CEC forecast in the years beyond the Commission EE programs' three-year program cycle) should be treated as a resource in the LTPPs. We conform to these principles in the following IOU-specific EE treatments.

21. It is important to clarify the definition of "uncommitted" EE in the context of the LTPPs.

22. In this Decision, we define "committed EE" as only those savings attributed to the IOUs' 2006-2008 and earlier EE programs, which meet or exceed Commission-adopted EE goals. We define "uncommitted" EE as the projected savings attributable to future EE program cycles (2009-2011 and beyond) that meet or exceed the Commission-adopted EE goals.

23. Due to the mechanics in the CEC's demand forecasting methodology discussed above, uncommitted EE (in this Commission's use of the term) is reflected in one of two places in the 2006 LTPPs: either: (1) embedded as a reduction in the load forecast (to the extent that uncommitted EE does overlap with the CEC's concept of committed effects); or (2) forecasted as an available resource (to the extent that uncommitted EE does not overlap with the CEC's concept of committed effects.

24. In its "California Energy Demand 2008-2018 Staff Revised Forecast (November 16, 2007), the CEC undertook additional analysis of this issue, developing quantifications explicitly for the 2006-2008 portfolios. Tables in Appendix A of the document provide quantifications of the direct program impacts (i.e., the portion of uncommitted EE goals not embedded in the forecast based on past and existing measures). Using the same methodology employed by the CEC to develop the 60% overlap, with the updated data included in the Staff Revised Forecast, results in overlap factors for PG&E and SCE of 85% and 95%, respectively.

25. Based on the CEC's analyses and our direction to the IOUs in D.07-10-032, there is evidence that suggests that the overlap factors may be in the range of 60% to 95%. Until a methodology is developed to more accurately estimate future EE savings in the CEC forecast, we will apply an 80% overlap factor to PG&E and SCE. This is a reasonable adjustment to properly balance between reliability concerns that could result from underestimating the overlap factor and over-procurement that could result from overestimating the overlap factor.

26. Based on the CEC's analyses and our direction to the IOUs in D.07-10-032, there is evidence that suggests that the overlap factors may be in the range of 60% to 95%. Until a methodology is developed to more accurately estimate future EE savings in the CEC forecast, we will apply an 80% overlap factor to PG&E and SCE. This is a reasonable adjustment to properly balance between reliability concerns that could result from underestimating the overlap factor and over-procurement that could result from overestimating the overlap factor.

27. SDG&E adds its uncommitted EE goals to the CEC forecast and then subtracts them back out as a resource. Although this approach is not consistent with the CEC's methodology for EE, the CEC acknowledges that this is an appropriate treatment of SDG&E's EE goals at this time.

28. We find the IOUs' projections on demand response forecasts and expectations based on enrollment and percentage of enrollment that is expected to actually participate to be an acceptable estimate of firm DR reductions for the purposes of seven-year forward planning for new supply-side resources.

29. We find the IOUs' LTPPs provide mostly sufficient information for us to check for compliance with the RPS program targets, including such issues as procurement, resource mix and resource potential. Despite the directives provided to the IOUs in the Scoping Memo, the IOUs did not adequately address rate impacts. In addition, the plans could have been strengthened by fully providing the timing and parameters of the expected RFOs or other means to fill identified renewable needs; addressing the possibility of contract failure; providing for assessments that are informed by general and resource-specific uncertainties and risks; and making other resource need determinations based on "reasonable expectations" of renewable supply.

30. We approve PG&E, SCE and SDG&E's treatment of renewables, with noted exceptions, because of recognized uncertainty in the scenario analyses and the fact that the renewable market in California is dynamic and the 2006 LTPPs do not capture developments in the past year. In addition, we direct the IOUs to work with ED staff to refine the long term planning methodology.

31. We do not require a margin of safety for the procurement of renewable energy sources because any non-compliance with renewable targets will result in sanctions as established in D.06-05-039.

32. The IOUs did not adequately address how to integrate long-range transmission planning beyond transmission already slated to come on-line into the long-term procurement process for all resource categories, including renewables, and we anticipate more discussion in subsequent LTPPs.

33. We anticipate that the statewide Renewable Energy Transmission Initiative will provide critical output for the IOUs to use in drafting their future renewable procurement plans.

34. We defer to existing or new proceedings related to RPS, transmission planning, or to consideration in other forums, many topics that impact the IOUs renewable portfolio including the following: whether there is a shortage of renewable sources; hurdles associated with the ISO queue process; the MPR methodology and the difficulty of properly assessing the value and costs of RPS procurement; utility-owned renewable generation; qualifying capacity of wind generation; rolling RPS procurement beyond 20% into an all-source RFO; and the development of Energy Parks.

35. We find that the IOUs followed the OIR and Scoping Memo directives and included forecasts for DG in their LTPPs that are consistent with existing Commission directives.

36. We find the IOUs treatment of QF resources for system reliability purposes to be reasonable given the information available to the IOUs at the time of their filing. However, on September 20, 2007, the Commission issued D.07-09-040 adopting pricing and policy mechanisms for the IOUs' purchase of energy and capacity from the QFs and we require each IOU to maintain its current level of QF capacity throughout the planning cycle. We anticipate that the IOUs will incorporate the new directives in subsequent LTPP filings.

37. We revised PG&E's anticipated retirement schedule to reflect a more gradual pace of retirements, but this adjustment does not impact our need determination for PG&E in the 2015 timeframe. We increase SCE's retirement assumptions by 500 MW annually, beginning in 2009, resulting in a total of 6,350 MW of retirement in the 2015 need determination timeframe. We made no revisions to SDG&E's retirement assumptions.

38. We do not adopt any system reliability reserve margin methodology at this time and do not make any changes to the existing 15%-17% PRM and in particular do not adopt the change requested by PG&E for its PRM.

39. We do not adopt the contingencies requested by PG&E for contracted resource uncertainty, anticipated revisions to the RA counting rules, additional backup or for RFO optionality since we find that PG&E did not provide an analysis for us to make an assessment that these additional resources will be needed during the 10-year planning cycle, or that they would be optimal for a future, GHG-constrained portfolio. We do not find that it would be prudent to grant this additional requested contingency amount at this time.

40. We must make need determinations today that will result in sufficient system resources to permit all jurisdictional LSEs to meet their PRM obligations in the seven-year new resource procurement timeframe. Seven years is a reasonable time to develop and carry out competitive RFOs and then finance, permit and construct new generation and to avoid "just-in-time" procurement.

41. A need determination is made for each IOU based on (1) the load, resource and PRM assessments discussed in this decision; (2) relevant information the IOUs and intervenors provided; and (3) the principle that each IOU should provide approximately the same level of system reliability to its customers.

42. Table PGE-1 provides a need determination for PG&E for the 10-year planning period using the assumptions and conclusions reached in this decision without any additional contingencies. Based on Table PG&E-1, our need determination analysis indicates that PG&E's service area shows a need of
800 - 1,200 MW by 2015.

43. To support the types of needs we anticipate in a GHG-constrained portfolio, we require PG&E to procure dispatchable ramping resources that can be adjusted for the morning and evening ramps created by the intermittent types if renewable resources.

44. SCE's service area need determination included POUs' contributions to system load or POU resources. We therefore, backed-out the POU resource data for SP-26 so SCE does not over-procure system resources.

45. Table SCE-1 calculates SCE's proportion of system resources based on its regional (bundled plus DA) forecast divided by the system forecast and provides SCE's service area need determination based on its recommended plan, with revisions addressed in this decision. Table SCE-1 also divides in half the DPV2 resource. SCE can update its next LTPP to reflect any updates in the DPV2 situation.

46. Based on Table SCE-1, our need determination analysis indicates that SCE's service area shows a need of 1,200 - 1,700 MW by 2015. We find this is in addition to the 305 MW remaining from SCE's standard-track RFO.

47. Table SDG&E-1 provides SDG&E's service area need determination which indicates that SDG&E does not have any new system capacity need by the 2015 timeframe. However, we note that SDG&E's need determination is constrained by local capacity requirements.

48. The need SDG&E identified is a physical local capacity need, and counting the 130 MW of peaking units recently approved, SDG&E requests approximately 530 MW of new local capacity procurement authority.

49. Because there is insufficient information at this time to determine if or when the Sunrise Powerlink project will be available to meet local capacity needs, we authorize 530 MW of additional procurement for SDG&E in the San Diego local area only if its Sunrise Powerlink application is denied.

50. SDG&E is also authorized to procure the equivalent quantity of local capacity associated with any retirements of local area resources that occur beyond the amount of retirements it forecasts in its LTPP.

51. To support the types of needs we anticipate in a GHG-constrained portfolio, we require SDG&E to procure dispatchable ramping resources that can be adjusted for the morning and evening ramps created by the intermittent types of renewable resources.

52. SDG&E is the only IOU that provides an explicit comparison of its bundled customers' need and its system need.

53. We continue to acknowledge the value of PRGs and direct that the utilities continue to use them as advisors for their procurement activities.

54. We find that a PRG calendar would be a useful process tool and direct the IOUs to individually set up and maintain a web-based PRG calendar that can be accessed and updated by a representative of each IOU. The calendar is to include dates of expected solicitation milestones and only contain non-confidential information. This will enable each IOU to efficiently schedule meetings with full knowledge of other IOU PRG meeting dates and times.

55. We find that it would aid PRG members in effectively organizing and focusing their participation if the IOUs provided PRG members with a PRG meeting agenda and materials a minimum of 48 hours in advance of the PRG meeting, unless there is an unusual, extenuating circumstance where an IOU notices a meeting on a tighter time schedule.

56. We adopt DRA's recommendation that IOUs provide (confidential) meeting summaries to PRG members that include a list of attending members, including the organizations represented, a summary of topics presented and discussed, and a list of information requested or offered to be supplied after the meeting, and the identity of the requesting party. We do not, however, require the IOUs to develop detailed PRG meeting minutes at this time and the meeting summaries are not admissible in hearings as evidence or to be cited in testimony.

57. We adopt the Transparency Working Group's information-sharing proposals designed to make the PRG process more transparent for the public and the IOUs may provide the following information to the public through a web-based forum: date, meeting time and duration of the meeting; the individuals participating in the meeting and organization represented by the individual; and a list of non-confidential items discussed.

58. We adopt the PRG Participation Working Group proposal to create a CAM Group for procurement for which IOUs recover costs from bundled and unbundled customers using the D.06-07-027 CAM. The CAM PRG shall include one member representing CCA customers, two members representing Direct Access customers. If a future definition of the CAM identifies non-bundled customers in addition to CCA customers and DA customers, they shall be represented by one member in the CAM Group.

59. We find it reasonable to continue the use of IE and we refine the existing process to have the IOUs, in conjunction with each respective PRG, develop a pool of at least three, but preferably more, IEs to be used beginning January 1, 2009. The particulars for development of the IE pool are set forth in the decision and we find it reasonable to adopt those provisions.

60. We adopt SCE's proposal that ED should be involved during the selection process, the development of the scope of work and the drafting of the terms of the contracts with the IE and have the right to final approval of such engagements.

61. We adopt DRA's recommendation, with modifications, that the name and information of the IE for each IOU, type of solicitation the IE was used for and the amount of money involved in the procurement solicitation be reported to the IOU's PRG before and after the solicitation takes place.

62. It is reasonable to find that an IE should continue to be contracted with and retained for all competitive solicitations that involve affiliate transactions or utility-owned or utility-turnkey bids, and for all competitive RFOs seeking products greater than three months in length regardless of the bidders. Competitive RFOs include RFOs issued to satisfy service area need and supply-side resources not including EE and DR. For solicitations of less than five years, the IE report shall be filed with the QCR.

63. We find it reasonable to require the IOUs, in consultation with the PRG and ED to develop comprehensive conflict of interest disclosure requirements for the IE. An IE may be disqualified from participating in an RFO process if there are particular egregious conflicts of interest that arise during the contract.

64. To address the fact that currently there is no consistency in the reports submitted by the IEs in support of applications for resources procured in competitive solicitations, we direct ED to develop a template for IEs to use when developing their reports, and the template will include the information and address the questions set forth in the decision.

65. We find it is reasonable to allow the IOUs to tailor their RFOs to address particular needs, such as system reliability needs or RA requirements, as ratepayers and competitors both benefit from this responsiveness. However, IOUs are not to create false barriers to participation or attempt to limit the competitive process by manipulating the RFO product descriptions.

66. We find that the RFO process would benefit from requiring the IOUs to hold a meeting with the IE, PRG and ED to outline their plans and solicit feedback prior to drafting RFO bid documents so that the RFO process is improved by the identification of data gaps, confirmation of the fairness of the confidential components of the RFO, and of the compliance with the letter and spirit of Commission policies on procurement practices.

67. Draft RFO bid documents are to be developed under the oversight of an IE, vetted through the PRGs and any differences resolved by ED staff in advance of the public issuance of the bid documents.

68. We find it reasonable to direct the IOUs that they may not initiate an RFO for new fossil resources that have not been formally authorized in a LTPP decision, unless the IOU makes a strong showing in advance, via an approved Advice Letter, that unusual or extreme circumstances warrant such an action.

69. We direct ED to develop a template that includes the information set forth in this decision, for IOUs to use when developing an application for approval of winning bid projects.

70. We find it reasonable to encourage SDG&E and the other IOUs to solicit renewable resource bids in their RFOs, as long as all resources within the RFO are compared against one another on a consistent, LCBF basis using the GHG adder to compare the bids of fossil resources relative to renewables and decisions regarding whether to continue conducting separate RPS solicitations are to be addressed in existing or new proceedings related to RPS.

71. We find that SCE's request to increase its collateral exposure limit to $2.0 billion is reasonable.

72. After reviewing the credit and collateral requirements used by the IOUs and utilizing the audit results from an audit contracted by the Commission, we determine that no other changes are warranted, at this time, on the subject of C&C.

73. When the Commission considered Debt Equivalence in the last procurement proceeding [R.04-04-003], it authorized the utilities to "take into account the impact of DE when evaluating individual bids . . ." and directed the utilities to use a 20% "risk factor" for all PPAs, based on a discount of the 30% risk factor developed by Standard and Poor's (S&P) for the California utilities. The Commission also acknowledged, however, that "(a)s the rating agencies' views on DE change or as we gain more experience with DE evaluation in the [cost of capital] proceedings, we may adjust the DE methodology used in [the] future."

74. Since the issuance of D.04-12-048, the Commission has gained more experience with debt equivalence.

75. We find that DE in and of itself, is not a real cost that the utilities directly incur by entering into a PPA.

76. In order to further encourage fair, head-to-head competition between PPAs and utility-owned projects, as it stated in D.04-12-048 and numerous times throughout this decision, the bid adder for PPAs should be eliminated.

77. We do not make any findings at this time on how a utility should weigh the FIN 46(R) impacts of a PPA when evaluating competing bids.

78. We do not make any findings or orders at this time on how transmission costs and benefits are to be evaluated for specific generation projects in the RFO process.

79. We adopt the following ED recommendations for revisions to contract pre-approval guidelines: Provided the procurement complies with a procurement limit methodology developed by the IOU and approved by the Commission, an IOU may execute a contract of under five years without pre-approval for which deliveries end at any point within the 10-year LTPP procurement cycle. Absent a Commission-approved procurement limit methodology, the five-year duration clock begins either at the time the contracted resources begin delivery, if delivery begins within one year of contract execution; or at the time of contract execution if delivery does not begin within one year of contract execution. Calendar days are used for calculating contract duration.

80. We find that PG&E and SCE's descriptions of how they calculate TEVaR and make use of it conforms to the Commission's directives to use a rolling 12-month TEVaR and make appropriate comparisons for purposes of determining whether to take steps to level price volatility within the CRT threshold. SDG&E's approach should be modified as set forth in this decision.

81. We adopt a TEVaR 95% as a more robust metric for risk than TEVaR 99% for guiding hedging decisions. We do not change the CRT level or the 125% threshold metric and maintain the looking forward up to five years reporting requirement.

82. We adopt the recommendation to coordinate the updates for the portfolios for the scheduling of gas supply and hedging plans by the IOUs, and direct that the updates be made annually at the time of the ERRA filings. The IOUs are also authorized to update their gas supply and hedge plans with the Commission for their DWR portfolios annually, instead of twice a year. This does not affect the IOUs obligations to DWR.

83. The nuclear and coal fuel plans proposed by the IOUs are adopted as presented.

84. The gas supply procurement proposals of the IOUs are not adopted because the Commission must address and review proposals by the IOUs more thoroughly than we have in this current proceeding and asses the proposals in conjunction with other rulemaking proceedings.

85. While we agree in principle with a number of PG&E and SCE's proposed changed to their respective gas and electricity product risk management approaches we determine that more analysis is necessary before they can be adopted by the Commission.

86. Until revised risk management approaches are formally adopted by the Commission, we require the IOU's to continue operating under their existing Commission approved risk management practices.

87. Outside of the IOUs' LTPPs and their initial briefs, the Commission received virtually no input regarding how and to what extent the Commission could improve and/or streamline the reporting requirements. We will rely on the record available and the Commission's own experience and expertise to make incremental changes to the compliance rules.

88. Having a tariff-like numbering system in place combined with a redline strikeout method of proposing updates to the LTPP will improve the compliance review. We direct the IOUs to develop a common numbering system, similar to the one used to track tariff revisions, to track revisions to each Commission-approved LTPP.

89. All IOU updates or modifications to their procurement plans proposed between the biennial procurement plan filings, via the Advice Letter process, are to include redlined pages of the existing procurement plan as well as "cleaned up" replacement pages which include the tariff-like numbering ordered above.

90. Currently, we require Commission staff to review the IOU's QCRs for compliance with the Commission-approved procurement plan and its upfront and achievable standards and criteria within 30 days of their receipt. It is reasonable to increase the timeframe for approving the QCRs from the current 30-day requirement to 60 days.

91. We find the results of the review and approval process for the QCRs completely unacceptable and amend the QCR process as follows. We direct the ED, in conjunction with the external auditors and the IOUs to continue the collaborative effort formed earlier this year and develop a reformatted QCR. We delegate authority to ED to authorize the implementation of the reformatted and streamlined QCRs and to make ministerial changes to the content and format of the report as needs arise.

92. We clarify our decision, D.07-04-020, on SCE and PG&E's Petition to Modify D.02-12-074 and D.04-12-048 to reiterate that while we denied the request to change the monthly ERRA filing to quarterly filings, we granted the request that the utilities only supply a breakdown of costs with their ERRA monthly filings and make all supporting documentation available to Commission Staff and interested parties upon request.

93. In order to capture all the modifications we made to the proposed LTPPs of the IOUs, we require conformed 2006 LTPPs via a compliance filing no later than 90 days from the date of this decision. The conformed 2006 LTPPs shall incorporate all of our directives contained in the body of this decision as well as any updates filed through the Commission's Advice Letter process between the issuance of this decision and the due date of the compliance filing. In the interim, the 2006 LTPPs are adopted with the requirements stipulated in this decision and summarized in the Ordering Paragraphs and the Compliance Table provided as Appendix E. The IOUs are directed to modify their hedging plans to conform to our TeVaR 95% metric and to include those modifications in their 2006 LTPP compliance filings.

94. We do not prohibit UOG in this decision, but we find it reasonable to no longer allow head-to-head competition between IPP and Utility build bids until we develop a fair, publicly-vetted comparison methodology.

95. We prohibit IOUs from recouping from ratepayers any bid development costs associated with losing PSA or EPC bids, in the event that any such costs are incurred.

96. UOG applications by the IOUs must fit into a unique circumstance, such as market power mitigation, reliability, preferred resources, expansion of existing facilities, or be a unique opportunity, as described in the decision, and each application will be considered on a case-by-case basis. If a competitive solicitation for a PSA or EPC contract to build the UOG is not appropriate, the application must explain why a utility-build approach is required.

97. We find that allowing the IOUs to require or include as an option in their competitive PPA RFOs the option of transfer of the fully depreciated resource underlying a PPA to the IOUs distorts the market and we will no longer allow the IOUs to consider such an option in competitive PPA RFOs.

98. We find it reasonable to prohibit communications of competitively sensitive information to the utility project development group from other utility departments if the utility is potentially bidding in an RFO.

99. We find it reasonable to require a functional separation between the individuals performing the bid evaluation and the individuals preparing the bids for UOG and prohibit the utility employees developing the bids for utility-owned projects from having access to evaluation protocols, input assumptions, or bid information that is not made available to outside bidders.

100. If an IOU proposes a UOG project outside of a competitive RFO, it is reasonable to require the IOU to make a showing that holding a competitive RFO is infeasible.

101. We find it reasonable to eliminate the "50/50 cost cap" directed in D.04-12-048 and will consider cost- and saving-sharing ratemaking mechanisms, such as proposed by PG&E and SCE, on a case-by-case basis and the requested treatment must be justified by unique circumstances.

102. We do not adopt SCE's Rulebook at this time, but endorse the concept in principle and direct ED staff to continue to work with the IOUs and other interested parties to create a Commission-endorsed "AB 57 Procurement Plan Implementation Manual" for each IOU that includes the comprehensive set of procurement rules, including any IOU-specific requirements, that can be accessed by all interested market participants to determine each IOU's compliance with its AB 57 Procurement Plan.

103. We are not making any new findings in regards to AB 1576 repowering projects, but reiterate our order from D.04-12-048 that the IOUs are ". . . to consider the use of Brownfield sites first and take full advantage of their location before they consider building new generation on Greenfield sites. If IOUs decide not to use Brownfield, they must make a showing that justifies their decision." All the benefits and impacts of AB 1576 projects should be properly considered and evaluated in an RFO - including quantifiable economic benefits and impacts, and non-quantifiable social and environmental benefits and impacts. This direction applies to repowered or replacement options presented in a RFO, not just UOG projects.

104. We find that all three IOUs' LTPPs could have been strengthened by building into their calculations of future need for electric resources a methodology for analyzing the GHG implications of the different resources the IOUs can utilize to fill that net short position. While the implementation details are still under consideration in R.06-04-009, it appears improbable that the IOUs can reduce their carbon emissions from electric generation resources back to 1990 levels without a focused reliance on preferred resources. We further find that the LTPPs rely heavily on fossil-fuel generation for expected needed resources and the IOUs did not explain how these resources fit into a GHG reduction strategy.

105. We find that procurement of zero- or low-GHG resources should be given preference over other resources since these are the types of resources that AB 32 regulations will favor.

106. We adopt NRDC's suggestion that all three IOUs be required to provide absolute GHG emissions, with cost implications of those emissions levels at various price points for CO2 allowances, under various scenarios in their future LTPP filings. Subsequent LTPPs should also include a thorough evaluation and analysis of the costs and risk of GHG emissions reductions.

107. We find it reasonable to approve the three IOUs' 2006 treatment of the 33% renewables target since the target has yet to be adopted and full implementation details will be addressed in existing or new RPS proceedings. However, we note that all three LTPPs could have provided more detailed information such that the Commission could more accurately assess how or if the IOUs could achieve a 33% renewables target by 2020. To ensure that the goal is incorporated into subsequent LTPPs, IOUs will work with ED staff to address refinements to the methodology for resource planning and analysis to adequately address the issue of a 33% renewables target by 2020.

108. In late 2001, the CAISO instituted a program of comprehensive market redesign called "MRTU" intended to enhance performance of the CAISO's core functions (reliable, nondiscriminatory transmission). Under MRTU, there will be a day-ahead market, which will be an integrated CAISO market for energy and ancillary services, as well as congestion management, and, if necessary, Residual Unit Commitment (RUC); an hour-ahead scheduling process (HASP), which is an opportunity to make scheduling adjustments (but is not a full-settlement market); and a real-time imbalance market with optimized economic dispatch.

109. We anticipate that the MRTU will be in place in Spring 2008 and that it will greatly impact the CAISO's markets, and the procurement practices and costs of the IOUs, and we will closely monitor the implementation of MRTU and make any appropriate and necessary changes to our procurement rules.

110. We find it reasonable to adopt PG&E's proposed modifications to the definitions of "Financial Swap" and "Electricity Transmission Products," but PG&E is to include details regarding transactions that involve these products in its QCR.

111. A key goal of this proceeding is to review the procurement process of the RFOs to consider whether any refinements are necessary to further the goal of open, transparent and competitive procurements.

112. An open, transparent and competitive procurement process is the king-pin to a successful hybrid market and we will provide guidance and procedures to effectuate this market.

113. We find it reasonable that an IOU must publicly reveal the names of winning bidders, a description of the product, and the contract term, within thirty days of when the IOU files an application for approval of the contract. The IOU may keep the identity of the winning bidder confidential until key commercial terms have been finalized and if that does not occur within the thirty day time frame, the IOU should withdraw the application and re-file once it can release the bidder's identity and other required information. The IOU does not have to publicly reveal the actual contract.

1. Pursuant to Pub. Util. Code § 454.5 the Commission reviewed the LTPPs filed by PG&E, SCE and SDG&E. We direct the IOUs to make a compliance filing conforming their 2006 LTPPs with the directives contained in this decision. The LTPPs filed by the IOUs on December 11, 2006, when conformed, are approved, subject to the exceptions and modifications set forth in this decision.

2. The EAP contains explicit direction regarding the state's preference for meeting identified resource needs and we reviewed the LTPPs for compliance with the EAP and found some deficiencies that must be corrected as directed in the decision.

3. The IOUs were directed to provide different candidate plans and to provide for each plan the expected GHG emissions; the RPS percentages; the percentage of demand response as a percentage of RA; and the energy savings from committed and uncommitted programs. Each plan was to be weighed for ratepayer costs and reliability.

4. We find that the LTPPs in general were inadequate in regards to addressing preferred resources, the EAP loading order and GHG reductions, in that the IOUs planned to fill their net short positions with conventional resources without a highly developed analysis to support this conclusion.

5. It is reasonable to direct the IOUs to correct their LTPPs to indicate how they should fill their net short positions to transition to a forthcoming GHG-constrained world in light of the absence of any scenario analysis in this regard.

6. Going forward, the IOUs will be required to reflect in the design of their RFOs compliance with the preferred resource loading order and GHG reduction goals and to demonstrate how each application for fossil generation filed based on the procurement authority granted in this proceeding fits into each IOU's GHG reduction strategy.

7. Based on our analysis of the CEC's IEPR load forecast, as updated, and the preferred/recommended plans of the IOUs, we make the following need determinations:

8. System need is not impacted by possible future load shifting to DA and CCA, and future DG and MDL is captured by the historical trends used to develop the IOUs' forecasts.

9. EE and DR targets and goals are set in separate proceedings and the IOUs projections of meeting EE and DR targets are not reviewed for compliance purposes in this proceeding.

10. We do not intend to relitigate EE treatment in the CEC load forecast in this proceeding.

11. We concur with DRA's recommendation that the CEC and the IOUs need to come to a consensus on what proportion of the Commission's EE goals are embedded in the CEC load forecast, and with TURN's position that the IOUs accurately reflect their EE goals in their LTPPs.

12. We agree with the CEC's recommendation that the portion of IOU's EE goals not included in the forecast (i.e., the uncommitted EE that does not overlap with EE-induced reductions embedded in the CEC forecast in the years beyond the Commission EE programs' three-year program cycle) should be treated as a resource in the LTPPs. We conform to these principles in the following IOU-specific EE treatments.

13. It is important to clarify the definition of "uncommitted" in the context of the LTPPs.

14. In this Decision, we define "committed EE" as only those savings attributed to the IOUs' 2006-2008 and earlier EE programs, which meet or exceed Commission-adopted EE goals. We define "uncommitted" EE as the projected savings attributable to future EE program cycles (2009-2011 and beyond) that meet or exceed the Commission-adopted EE goals.

15. Due to the mechanics in the CEC's demand forecasting methodology discussed above, uncommitted EE (in this Commission's use of the term) is reflected in one of two places in the 2006 LTPPs: either: (1) embedded as a reduction in the load forecast (to the extent that uncommitted EE does overlap with the CEC's concept of committed effects); or (2) forecasted as an available resource (to the extent that uncommitted EE does not overlap with the CEC's concept of committed effects.

16. In its "California Energy Demand 2008-2018 Staff Revised Forecast (November 16, 2007), the CEC undertook additional analysis of this issue, developing quantifications explicitly for the 2006-2008 portfolios. Tables in Appendix A of the document provide quantifications of the direct program impacts (i.e., the portion of uncommitted EE goals not embedded in the forecast based on past and existing measures). Using the same methodology employed by the CEC to develop the 60% overlap, with the updated data included in the Staff Revised Forecast, results in overlap factors for PG&E and SCE of 85% and 95%, respectively.

17. Based on the CEC's analyses and our direction to the IOUs in D.07-10-032, there is evidence that suggests that the overlap factors may be in the range of 60% to 95%. Until a methodology is developed to more accurately estimate future EE savings in the CEC forecast, we will apply an 80% overlap factor to PG&E and SCE. This is a reasonable adjustment to properly balance between reliability concerns that could result from underestimating the overlap factor and over-procurement that could result from overestimating the overlap factor.

18. Renewable targets and goals are established in a separate proceeding and the LTPPs were reviewed to determine if the IOUs had accounted for renewables in their portfolios, but we did not review RPS-eligible deliveries for compliance purposes.

19. DG treatment by the IOUs in their LTPPs was reasonable and followed Commission directives.

20. Treatment of QFs by the IOUs in their LTPPs was reasonable in light of the information available to the IOUs at the time of their filings, but QF policy and pricing issues are now established by D.07-09-040. To be consistent with the QF policies now established by D. 07-09-040, the IOUs shall modify their LTPPs to include maintenance of the current level of QF capacity.

21. Some IOU retirement assumptions were revised.

22. We do not make any changes to the PRM currently authorized by the IOUs.

23. PRGs are valuable for the IOUs' procurement process and we direct the IOUs to continue to use them in an advisory capacity for their procurement activities, including for procurement when an IOU is considering recovering costs from bundled and unbundled customers using the D.06-07-029 CAM.

24. IEs are valuable to the procurement process and we direct the IOUs to utilize IEs according to the parameters established in this decision and in D.04-12-048.

25. IOUs may tailor their RFOs to address particular procurement needs but are prohibited from creating false barriers to participation or attempting to limit or manipulate the competitive process.

26. IOUs are to utilize IEs, the PRG and ED as early as practicable in the procurement cycle, including prior to drafting RFO documents.

27. No IOU may initiate a RFO for new fossil resources that have not been formally authorized in a LTPP decision, unless the IOU makes a strong showing to ED in an Advice Letter that unusual or extreme circumstances warrant such action.

28. The IOUs, and in particular SDG&E, may solicit renewable bids in their RFOs, as long as resources within the RFO are compared against one another on a consistent LCBF basis using the GHG adder to compare the bids of fossil resources relative to renewables and decisions regarding whether to continue conducting separate RPS solicitations are to be addressed in the RPS proceeding.

29. SCE's request to increase its collateral exposure limit to $2.0 billion is approved.

30. IOUs may no longer apply a 20% DE "bid adder" as a bid evaluation tool when for PPAs.

31. We revise the contract pre-approval guidelines: Provided the procurement complies with a procurement limit methodology developed by the IOU and approved by the Commission, an IOU may execute a contract of under five years without preapproval for which deliveries end at any point within the 10-year LTPP procurement cycle. Absent a Commission-approved procurement limit methodology, the five-year duration clock begins either at the time the contracted resources begin delivery, if delivery begins within one year of contract execution; or at the time of contract execution if delivery does not begin within one year of contract execution. Calendar days are used for calculating contract duration.

32. IOUs are to use a rolling 12-month TEVaR and then make appropriate comparisons for purposes of determining whether to take steps to level price volatility within the CRT threshold.

33. We revise the TEVaR from 99% to 95%, but make no changes to the CRT level or 125% threshold metric.

34. IOUs are to coordinate the updates for their portfolios for scheduling gas supply and hedging plans which updates are to be made annually at the time of the ERRA filings.

35. IOUs are authorized to update their gas supply and hedge plans with the Commission for their DWR portfolios annually, instead of twice a year.

36. While we agree in principle with a number of PG&E and SCE's proposed changed to their respective gas and electricity product risk management approaches we determine that more analysis is necessary before they can be adopted by the Commission.

37. Until revised risk management approaches are formally adopted by the Commission, we require the IOU's to continue operating under their existing Commission approved risk management practices.

38. The nuclear and coal fuel plans proposed by the IOUs are adopted as presented.

39. The gas supply procurement proposals of the IOUs are not adopted because the Commission must address and review proposals by the IOUs more thoroughly than we have in this current proceeding and asses the proposals in conjunction with other rulemaking proceedings.

40. In order for the IOUs to continue necessary gas supply procurement for their electric generation requirements, the Commission authorizes the IOUs to continue operation under existing gas supply plans approved in the 2004 LTPP and 2005 Short-Term Procurement Plans until new supply plans are approved by the Commission.

41. If an IOU needs to propose specific gas supply procurement contract(s) that are not authorized by their existing gas supply plans beforehand, an IOU can file an application with the Commission to receive such authorization.

42. ED, in conjunction with the external auditors and the IOUs are to continue their collaborative effort to reformat and streamline the QCR process.

43. It is reasonable for ED to implement the reformatted and streamlined QCRs and to make ministerial changes to the content and format of the report as needs arise.

44. It is reasonable to increase the timeframe for approving the QCRs from the current 30-day requirement to 60 days.

45. Conformed 2006 LTPPs are due no later than 90 days from the date of this decision.

46. Head-to-head competition between IPP and Utility build bids is not allowed unless procedures are established and implemented that provide a more transparent comparison between the bids.

47. We prohibit IOUs from recouping from ratepayers any bid development costs associated with losing PSA or EPC bids, in the event that any such costs are incurred.

48. Each application for UOG will be reviewed on a case-by-case basis pursuant to the criteria set forth in the decision.

49. IOUs may no longer consider in a RFO an option of the transfer of the fully depreciated resource underlying a PPA to the IOU.

50. We prohibit IOUs from sharing competitively sensitive information between the utility project development group and other utility departments if the utility is potentially bidding in an RFO.

51. We require a functional separation between the individuals performing the bid evaluation and the individuals preparing the bids for UOG and prohibit the utility employees developing the bids for utility-owned projects from having access to evaluation protocols, input assumptions, or bid information that is not made available to outside bidders.

52. An IOU proposing a UOG project outside of a competitive RFO must make a showing that holding a competitive RFO is infeasible.

53. We eliminate the 50/50 cost cap directed in D.04-12-048 and will consider cost-and saving-sharing ratemaking mechanisms on a case-by-case basis.

54. We do not adopt a Rulebook at this time, but encourage ED, IOUs and other parties to work towards a Commission endorsed "AB 57 Procurement Plan Implementation Manual" for each IOU.

55. We do not adopt any new rules regarding implementation of AB 1576 repowering projects, but reiterate our order from D.04-12-148 ". . . to consider the use of Brownfield sites first and take full advantage of their location before they consider building new generation on Greenfield sites. If IOUs decide not to use Brownfield, they must make a showing that justifies their decision." All the benefits and impacts of AB 1576 projects should be properly considered and evaluated in an RFO - including quantifiable economic benefits and impacts, and non-quantifiable social and environmental benefits and impacts. This direction applies to re-powered or replacement options presented in a RFO, not just UOG projects.

56. All three LTPPs could have been strengthened by the inclusion of a methodology for analyzing the GHG implications of the different resources the IOUs can use to fill their net-short positions.

57. Zero-or low-GHG resources are to receive priority over other procurement options.

58. IOUs are to provide absolute GHG emissions, with cost implications, under various scenarios in their future LTPP filings.

59. Given that a 33% renewables target has not been adopted, it is reasonable to approve the IOUs' treatment of this target in their 2006 LTPPs.

60. Given that MRTU is anticipated to be in place in Spring 2008, we will monitor its implementation and make any appropriate and necessary changes to our procurement rules.

61. It is reasonable to adopt PG&E's proposed modifications to the definitions of Financial Swaps" and "Electricity Transmission Products," but PG&E is to include details regarding transactions that involve these products in its QCR.

62. We find it reasonable that an IOU must publicly reveal the names of winning bidders, a description of the product, and the contract term, within thirty days of when the IOU files an application for approval of the contract. The IOU may keep the identity of the winning bidder confidential until key commercial terms have been finalized and if that does not occur within the ninety day time frame, the IOU should withdraw the application and re-file once it can release the bidder's identity and other required information. The IOU does not have to publicly reveal the actual contract.

63. The utilities propose a number of policies, some of which we specifically address in this decision. We express no opinion on the merit of the policies and positions presented in the LTPPs which we have not specifically addressed in this decision, and we do not adopt, modify or reject any of them.

ORDER

IT IS ORDERED that:

1. Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE) and San Diego Gas & Electric Company (SDG&E) shall make a compliance filing conforming their 2006 long-term procurement plans (LTPP) no later than 90 days from the date of this decision. The conformed 2006 LTPPs shall incorporate all of our directives contained in the body of this decision as well as any updates filed through the Commission's Advice Letter process between the issuance of this decision and the due date of the compliance filing. We direct each IOU to separately file a Tier 3 Advice Letter when it submits its Compliance Filing for approval.

2. In the interim, the 2006 LTPPs are adopted with the requirements stipulated in this decision and summarized in the Ordering Paragraphs and the Compliance Table provided as Appendix E.

3. When executing procurement plans in response to this decision, PG&E, SCE and SDG&E shall reflect in the design of their requests for offers (RFO) compliance with the Energy Action Plan (EAP) preferred resource loading order and with greenhouse gas (GHG) reductions goals. Any application for fossil generation filed in response to this decision, shall demonstrate how the resource fits into the investor owned utility's (IOU) GHG reduction strategy.

4. PG&E is authorized to procure 800 - 1,200 MW of new resources (including fossil fuel resources) by 2015.

5. SCE is authorized to procure 1,200 - 1,700 MW of new resources (including fossil fuel resources), in addition to the 305 MW remaining from its standard-track RFO, by 2015.

6. SDG&E is authorized to procure 530 MW of new resources (including fossil fuel resources) by 2015 in its local area if its application for the Sunrise Powerlink is denied. This authorization includes the 130 MW of local peakers already approved by the Commission. SDG&E is also authorized to procure the equivalent quantity of local capacity associated with any retirements of local area resources that occur beyond the amount of retirements it forecasts in its LTPP.

7. PG&E, SCE and SDG&E are directed to continue utilizing procurement review groups (PRG) as advisors for their procurement activities and to implement the following:

8. For any procurement for which an IOU seeks to recover costs from bundled and unbundled customers using the Cost Allocation Method (CAM) from Decision (D.) 06-07-029, the PRG shall include one member representing community choice aggregator (CCA) customers and two members representing direct access (DA) customers. If future Commission definition of the CAM identifies non-bundled customers in addition to CCA customers and DA customers, they shall be represented by one member in the CAM Group.

9. PG&E, SCE and SDG&E are directed to continue using an Independent Evaluators (IE), subject to the modifications and revisions adopted in this decision to the process initiated in D.04-12-048. IEs are to be used for all long-term solicitations that involve affiliate transactions or utility-owned or utility-turnkey bids and for all competitive RFOs seeking products greater than three months in length regardless of the bidders. Competitive RFOs include RFOs issues to satisfy service area need and supply-side resources not including EE and DR.

10. PG&E, SCE and SDG&E shall do the following regarding the IEs:

11. These directives regarding IEs shall continue until further Commission order.

12. ED is directed to develop a template for IEs to use when developing their reports. This template is to be developed through a public process and is to be submitted for public comment no later than 30 days after this decision is issued.

13. The Executive Director may hire and manage one or more contractors to perform tasks described in this order for the purpose of advancing the goals of the Commission's Long-Term Procurement Planning Process. Such costs, if any, shall not exceed a total annual amount of $400,000, and the total shall be paid by PG&E, SCE and SDG&E on a proportional basis in relation to procurement related costs as reported in the Annual Energy Resource Recovery Account (ERRA) reports.  SCE, PG&E and SDG&E are authorized to establish an LTPP Technical Assistance Memorandum Account (LTAMA) for the purpose of recording such payments. PG&E, SCE, SDG&E are authorized to record these LTPP technical contractor costs into the LTAMA. These costs shall be recorded when paid, and each company may later apply for recovery in rates.

14. The IOUs are not to create any false barriers to participation in RFOs or to attempt to limit the competitive process by manipulating RFO product descriptions.

15. The IOUs are to hold a meeting with the IE, PRG and ED to outline their plans and solicit feedback prior to drafting RFO bid documents so that the RFO process is improved by the identification of data gaps, confirmation of the fairness of the confidential components of the RFO, and of the compliance with the letter and spirit of Commission policies on procurement practices.

16. Draft RFO bid documents are to be developed under the oversight of an IE, vetted through the PRGs and any differences resolved by ED staff in advance of the public issuance of the bid documents.

17. IOUs may not initiate an RFO for new fossil resources that have not been formally authorized in a LTPP decision, unless the IOU makes a strong showing in advance, via an approved Advice Letter, that unusual or extreme circumstances warrant such an action.

18. ED is to develop a template that includes the information set forth in this decision, for IOUs to use when developing an application for approval of winning bid projects. This template is to be developed through a public process and is to be submitted for public comment no later than 30 days after this decision is issued.

19. Provided the procurement complies with a procurement limit methodology developed by the IOU and approved by the Commission, an IOU may execute a contract of under five years without preapproval for which deliveries end at any point within the 10-year LTPP procurement cycle. Absent an approved procurement limit methodology, the five-year duration clock begins either at the time the contracted resources begin delivery, if delivery begins within one year of contract execution; or at the time of contract execution if delivery does not begin within one year of contract execution. Calendar days are used for calculating contract duration.

20. The IOUs are to use a rolling 12-month to calculate TEVaR and make appropriate comparisons for purposes of determining whether to take steps to level price volatility within the CRT threshold.

21. IOUs are to use a TEVaR 95% rather than TEVaR 99% for guiding hedging decisions. We do not change the CRT level or the 125% threshold metric and maintain the looking forward up to five years reporting requirement.

22. The IOUs are authorized to coordinate the updates for the portfolios for the scheduling of gas supply and hedging plans and the updates are to be made annually at the time of the ERRA filings. The IOUs are also authorized to update their gas supply and hedge plans with the Commission for their Department of Water Resources (DWR) portfolios annually, instead of twice a year. This does not affect the IOUs obligations to DWR.

23. While we agree in principle with a number of PG&E and SCE's proposed changed to their respective gas and electricity product risk management approaches we determine that more analysis is necessary before they can be adopted by the Commission. Until revised risk management approaches are formally adopted by the Commission, we require the IOU's to continue operating under their existing Commission approved risk management practices.

24. The nuclear and coal fuel plans proposed by the IOUs are adopted as presented. We do not adopt the gas supply procurement proposals of the IOUs because the Commission must address and review proposals by the IOUs more thoroughly than we have in this current proceeding and asses the proposals in conjunction with other rulemaking proceedings. In order for the IOUs to continue necessary gas supply procurement for their electric generation requirements, the Commission authorizes the IOUs to continue operation under existing gas supply plans approved in the 2004 LTPP and 2005 Short-Term Procurement Plans until new supply plans are approved by the Commission.

25. We direct the IOUs to develop a common numbering system, with a redline strikeout method, similar to the one used to track tariff revisions (General Order 96-B 8.4.2.), to track revisions to each Commission-approved LTPP.

26. All IOU updates or modifications to their procurement plans proposed between the biennial procurement plan filings, via the Advice Letter process, are to include redlined pages of the existing procurement plan as well as "cleaned up" replacement pages which include the tariff-like numbering ordered above.

27. We direct the ED, in conjunction with the external auditors and the IOUs to continue the collaborative effort formed earlier this year and develop a reformatted QCR. We delegate authority to ED to authorize the implementation of the reformatted and streamlined QCRs and to make ministerial changes to the content and format of the report as needs arise.

28. We increase the timeframe for approving the QCRs from the current 30-day requirement to 60 days.

29. D.07-04-020 allows that the utilities only supply a breakdown of costs with their ERRA monthly filings and make all supporting documentation available to Commission Staff and interested parties upon request.

30. IOUs can not issue RFOs that seek both Power Purchase Agreements (PPAs) and Utility build bids.

31. UOG applications by the IOUs outside of an RFO must fit into a unique circumstance, which are limited to market power mitigation, reliability, preferred resources, expansion of existing facilities, or be a unique opportunity, as described in the decision, and each application will be considered on a case-by-case basis. The IOU is required to make a showing that holding a competitive RFO is infeasible.

32. IOUs will no longer be allowed to consider as an option in their competitive PPA RFOs the transfer of the fully depreciated resource underlying a PPA to the IOUs.

33. We eliminate the "50/50 cost cap" directed in D.04-12-048 and will consider cost- and saving-sharing ratemaking mechanisms on a case-by-case basis and the requested treatment must be justified by unique circumstances.

34. ED staff is to continue to work with the IOUs and other interested parties to create a Commission-endorsed "AB 57 Procurement Plan Implementation Manual" for each IOU that includes the comprehensive set of procurement rules, including any IOU-specific requirements, that can be accessed by all interested market participants to determine each IOU's compliance with its AB 57 Procurement Plan.

35. IOUs are to consider the use of Brownfield sites first and take full advantage of their location before they consider building new generation on Greenfield sites. If IOUs decide not to use Brownfield, they must make a showing that justifies their decision. All the benefits and impacts of AB 1576 projects should be properly considered and evaluated in an RFO - including quantifiable economic benefits and impacts, and non-quantifiable social and environmental benefits and impacts. This direction applies to re-powered or replacement options presented in a RFO, not just UOG projects.

36. IOUs may no longer apply a 20% DE "bid adder" as a bid evaluation tool when evaluating PPAs.

37. We find it reasonable to adopt PG&E's proposed modifications to the definitions of "Financial Swaps" and "Electricity Transmission Products" but PG&E is to include details regarding transactions that involve these products in its QCR.

38. An IOU must publicly reveal the names of winning bidders, a description of the product, and the contract term, within 30 days of when the IOU files an application for approval of the contract. The IOU may keep the identity of the winning bidder confidential until key commercial terms have been finalized and if that does not occur within the 30-day time frame, the IOU should withdraw the application and re-file once it can release the bidder's identity and other required information. The IOU does not have to publicly reveal the actual contract.

39. The utilities propose a number of policies, some of which we specifically address in this decision. We express no opinion on the merit of the policies and positions presented in the LTPPs which we have not specifically addressed in this decision, and we do not adopt, modify or reject any of them.

This order is effective today.

Dated December 20, 2007, at San Francisco, California.

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