V. Resource Options

In modifying their procurement plans, the utilities should undertake a resource planning effort to include procurement from a mixture of different sources with various environmental, cost, and risk characteristics. Utilities fully responsible for meeting their customers' resource needs should plan among all of the following options: conventional generation sources (with a variety of types of ownership structures), renewable generation (including renewable self-generation), distributed and self-generation, demand-side resources, and transmission. In addition, utilities should plan to meet a reserve requirement. Each of these elements is discussed briefly below.

In addition, we encourage the utilities to work cooperatively with the CEC and the Power Authority on planning for all of the resources discussed below. The CEC can streamline regulatory oversight of some aspects of the resource planning portfolio, as well as assist with renewable resource procurement through their PGC funding authorized in SB 1038. The Power Authority can also assist in providing financing and programmatic support to a number of the resources described below. The utilities should recognize and take advantage of the complementary roles of these agencies, as well as DWR, in the procurement process.

In making plans to procure a mixture of resources, the utilities should take into account the Commission's longstanding procurement policy priorities - reliability, least cost, and environmental sensitivity. While each of these priorities is important individually, they are also strongly interrelated. Increased reliability may increase procurement costs. Diversifying the resource mix may meet environmental priorities, but may also increase costs. Thus, the utilities should explicitly address these tradeoffs in their long-term procurement plans.

To assist with that process, we provide the following general guidance:

· Reliability now includes not just traditional concepts like adequacy of reserves, but also a recognition that it should include strategies to:

¬ Diversify the generation mix, and reduce reliance on fossil fuels

¬ Rebalance the IOU portfolio mix

¬ Address the reliability threat posed by aging power plants

¬ Address infrastructure security

· Least cost includes mitigating against an over-dependence on fossil fuels whose price is uncertain and can unexpectedly escalate, pulling electricity costs upward. Least cost also includes non-monetary attributes, as well as the time-differentiated production costs of power. Thus, flexible and reliable resource programs with relatively short development lead times (i.e., energy efficiency) can compete with traditional generation options for a place in the IOU resource portfolio. Capturing the time-differentiated costs of power also allows customers that place a higher value on low energy bills than on reliability to have programs available to them that also benefit the system (i.e., demand response programs).

· Environmental sensitivity encompasses not just traditional concerns over air quality impacts and aesthetic aspects of resource development, but a broader recognition that repowering or rebuilding on brownfields should be considered as substitutes to development of greenfields. In addition to the use of

renewable technologies that must be included in the IOU plans consistent with the law and our mandate, the utilities should also include the environmental effects of repowering or rebuilding.

A. Conventional Generation

In their resource planning, the utilities should consider both utility owned/retained and merchant generation sources. While in the short-term the sources of such procurement may be limited, for the longer-term utilities should assess costs and benefits of various contracting and ownership strategies. In addition, a discussion of fuel risk should be explicitly incorporated into the procurement planning process.

B. Renewable Resources

Before giving specific direction on renewable procurement, it is important to have a clear definition of what constitutes "renewable generation." SB1078 defines "renewable generation" as electricity produced by the following technologies: biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts (MW) or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current, and any additions or enhancements to the facility using that technology.

The output of a small hydroelectric generation facility of 30 MW or less procured or owned by an electrical corporation as of the date of enactment of this article shall be eligible only for purposes of establishing the baseline of an electrical corporation pursuant to paragraph (3) of subdivision (a) of Pub Util. Code § 399.15. A new hydroelectric facility is not an eligible renewable energy resource if it will require a new or increased appropriation or diversion of water under Part 2 (commending with Section 1200) of Division 2 of the Water Code.

A geothermal generation facility originally commencing operation prior to September 26, 1996, shall be eligible for purposes of adjusting a retail seller's baseline quantity of eligible renewable energy resources except for output certified as incremental geothermal production by the Energy Commission, provided that the incremental output was not sold to an electrical corporation under contract entered into prior to September 26, 1996. For each facility seeking certification, the Energy Commission shall determine historical production trends and establish criteria for measuring incremental geothermal production that recognizes the declining output of existing steamfields and the contribution of capital investment in the facility or wellfield. Facilities must also be located in the state or near the border of the state with the first point of connection to the Western Electricity Coordinating Council (WECC) transmission system located within the state. TURN contends that we have misconstrued the definition of "in-state renewable electricity generation technology." Specifically, "TURN believes that the PD's cited eligibility definitions are modified by Section 383.5(d)(2)(B) of the Public Utilities Code, which allows the Energy Commission to waive the in-state requirement if the facility is located within the WECC transmission system and sells its generation to end-use customers of a California IOU." (Comments of TURN, pp.7-8.) Taking the law of its face, we are not inclined to agree. Pub. Util. Code § 383.5(d)(2)(B) allows for the Energy Commission to award, provided certain criteria are met, Public Goods Charge funds to out-of-state renewable facilities. The code section does not, however, alter the definition of "in-state renewable electricity generation technology." The definition found in Section 383.5(b)(1) remains the binding language for purposes of RPS eligibility. However, we recognize the potential ambiguity of the situation, as well as the potential benefits of allowing out-of-state facilities to contribute to the cost-effective implementation of the RPS program. Therefore,

we request that parties, in particular the CEC, provide briefs on this subject, as indicated below. For the purposes of transitional procurement, production from existing out-of-state renewable generation facilities previously selling power to a utility shall be considered part of the utility's baseline only.

In addition to these provisions in SB 1078, we include in our definition of renewable generation, for purposes of compliance with both D.02-08-071 and SB 1078, renewable distributed generation (DG) on the customer side of the meter. Customer-side distributed generation that utilizes the technologies listed in the first paragraph of this Section of the decision is eligible for RPA participation. Including renewable DG as part of our definition will serve to encourage its installation, regardless of whether the utility purchases the output or whether it serves to meet on-site load. The full output of renewable DG should be credited to meeting the RPS or D.02-08-071 requirements, but only new renewable DG installations are to be credited (existing renewable DG does not count toward the utility's RPS baseline calculation).

1. Renewable Procurement Prior to Full RPS Implementation

Throughout this proceeding, we have demonstrated our commitment to renewable resource procurement. In the period since the issuance of our transitional procurement decision, the Legislature has passed, and Governor Davis has signed, two pieces of legislation with significant implications for the renewable generation aspects of this proceeding. These bills


are SB 1078 and SB 1038.¹² Under these statutes, California is embarking on a multi-year RPS program, supported by the subsidies and research of the Energy Commission's Renewable Energy Program (REP). This Commission has been given several important tasks in pursuit of the goals of the RPS, and we must start now if the effort is to succeed.

We also must be certain that the direction provided in the transitional procurement decision is implemented in the coming months. Full implementation of the RPS program will be constrained to some degree by SB 1078's statutory requirements regarding the credit ratings of the utilities. It is, therefore, more important than ever that the partnerships authorized for the purpose of transitional procurement result in substantial procurement of renewable generation. We note, moreover, that our mandate to develop renewable generation resources under Section 701.3 remains a guiding principle in this proceeding, and we restate our commitment to that goal.

We direct the utilities to submit, with their short-term procurement plan on November 12, 2002, a report on the status of their procurement under the renewable generation mandate of our previous order. Utilities should document their plan for meeting the 1% procurement required in D.02-08-071, including what has been accomplished and what remains to be done. Commission staff is available to facilitate compliance with this direction.¹³

We also ask that parties with information regarding the contract status of existing renewable facilities provide the Commission with an update on negotiations with the utilities. Such parties should provide this information as soon as they so desire. Similarly, we ask that the CEC, to the extent it has information, provide an update on the status of those potential new facilities it has previously identified, and the extent to which those facilities are engaged in the transitional procurement process.

Our renewable requirement contained in D.02-08-071 remains in effect under Section 701.3 and should be adhered to, with or without DWR credit support.¹⁴

We also clarify, to the extent that D.02-08-071 may have been ambiguous, that procurement of 1% of the utility's retail sales in 2001 (including DWR quantities) is the overriding requirement for renewables in that decision. Utilities are required to contract for this amount of electricity from renewable sources by the end of 2002.

Utilities are not required to procure all resources that offer prices of less than 5.37 cents per kWh (the interim benchmark price). That benchmark was set for purposes of determining per se reasonableness for cost recovery purposes, but does not require that utilities acquire all resources at that price. D.02-08-071 in fact requires a competitive solicitation process for renewables that may produce bids either below or above the benchmark, with varying contract lengths. No other price benchmark generated by a utility for its own internal use alters in any way the per se reasonableness of the 5.37 cents per kWh price.

We also clarify that any renewable procurement conducted under the transitional authority will count towards the utilities' RPS requirements going forward.

2. Implementing the Renewable Portfolio Standard Program

We must also lay the groundwork for full RPS implementation, and much of what is needed exists in the record of this proceeding. SDG&E, as a creditworthy utility, must begin the RPS process immediately. Drawing from the existing record, we ask that parties brief what is required to implement the RPS legislation and relevant portions of the REP bill, with particular emphasis on the following:

Market Price Benchmarking. It is clear that this will be the first and most important task for the Commission in this process. We are directed by statute to consider long-term, fixed-energy prices for non-renewable generation, long-term ownership costs for new facilities, and the value of specific electrical products. Hence, there will be more than one benchmark price to set. We ask that parties, in particular the CEC, comment on appropriate methodologies to be employed in this process.

Least Cost/Best Fit. We are directed to provide the utilities with the criteria they are to use in selecting renewable bids, specifically including transmission and "ongoing utility" expenses. Least cost/best fit needs a fuller exposition if it is to provide any real procurement guidance in the future. Parties should provide a coherent definition of the least cost/best fit concept, and develop it in the context of transmission costs and other relevant considerations. We further request, as suggested by CalWEA, that parties provide guidance on the allocation of transmission costs that may arise in the process of RPS implementation. Last, we ask that parties provide briefing on the definition of utility "long-term needs" in Pub. Util. Code § 399.15(a).

Baselines and Targets. As stated above, we direct the utilities to calculate their 1% procurement targets in reference to total 2001 electrical sales, including DWR power. We also need to determine, for purposes of monitoring progress towards the 20% renewable goal, the composition of each utility's portfolio that is presently comprised of renewables. We ask that the utilities, and any other parties with the ability to comment, provide us with 2001 sales figures, the percentage of their present portfolio that is comprised of renewable generation, and their quantitative estimates of the 1% procurement target.

Flexible Compliance and Penalty Mechanisms. We are to allow utilities to catch up procurement shortfalls over as many as three years, and to allow excess procurement to be "banked" for credit in the future. Parties should comment on how this compliance system should be designed, including specifically addressing whether a three-year rolling average would be workable. Parties should also comment on whether the Commission should consider inter-utility trading of renewable energy credits (RECs). Similarly, we are to design penalty mechanisms to be employed in enforcing RPS compliance, and seek parties' comment, with particular reference to successful examples employed in other RPS programs.

Inter-Agency Collaboration. Parties should comment on how the tasks assigned to the Commission and the CEC intersect, and on how the two agencies can best collaborate to achieve the RPS goal.

Standard Contract Terms and Conditions. Utilities and parties representing renewable developers are particularly encouraged to provide guidance on how to structure standard contracts for renewable procurement.

Optimal Utilization of Public Goods Charge Funds. Procurement under the RPS program will be constrained by the availability of funds under the CEC PGC program. Parties should discuss, in detail, how far these funds will go towards meeting the RPS goal, and how best to coordinate their usage with the CEC.

Inclusion of Out-of-State Resources. Parties should provide guidance on the legality and potential benefits of allowing out-of-state renewable generation resources to participate in the RPS, particularly as such participation would influence the overall benefits accrued to California by the program, and the potential


difficulties in accurately accounting for such power that this participation may involve.

Developing a Balanced Renewable Portfolio. The legislature and Governor have expressed their intention that the RPS bill result in the development of a broad range of renewable technologies. Given the constraints imposed by the market-benchmark criteria and the relative scarcity of PGC funds, it is not clear that this will be the necessary result. Parties are asked to comment on strategies the Commission may employ to pursue a diversified renewable portfolio.

Role of the Procurement Entity. SB 1078 allows for the deployment of third-party contractors in procuring renewable power for sale to utility customers under the RPS. We ask that parties provide guidance on how such entities can best be incorporated, and the extent to which their participation can shield the utilities from risks to their credit ratings, noting that the legislation places such a third-party relationship at the discretion of the utility.

Pursuing Other Commission Mandates. Since the inception of this proceeding we have signaled our intention to pursue the mandate of Section 701.3. We ask that parties comment on the relationship of this mandate to the direction provided in SB 1078, and on any actions the Commission should take to comply with Section 701.3 and make it compatible with the RPS program. Specifically, we are interested to receive comments on the incorporation of renewable DG into the RPS purchases of the utilities.

We request parties through comments on January 6, 2003 and reply comments on January 13, 2003 to provide briefs on the above topics as well as a proposed procedural process and schedule for implementing SB 1078. A procedural schedule shall be set by Assigned Commissioner's Ruling. The Commission will submit an implementation report to the Legislature by June 30, 2003, as required by SB 1078.

We fully intend to secure an increase in renewable generation for the state as a result of the transitional procurement process authorized previously, and will see to it that the RPS program is implemented effectively and with an eye to

the necessary detail. It will be an iterative process, but there can be no doubt as to the direction we are heading. The RPS Program is law, and we will do our part to implement it.

C. Distributed and Self-Generation

The utilities should explicitly include provision for distributed generation and self-generation resources in their procurement plans. In this definition, we also include on-site cogeneration resources, including QFs. Utilities should explicitly describe their plans for offering QF contracts in their long-term procurement plans. Distributed and self-generation resources encompass a broad and diverse set of technologies to fit a variety of procurement needs. In addition to providing capacity and energy benefits, they can offer transmission and grid-support benefits that should be included in the utilities' procurement plans.

In their November 12, 2002 short-term procurement plans, utilities should also provide an update on the status of the required standard offer contracts for QFs required in D.02-08-071.

D. Demand-Side Resources

As we mention several times in this decision, we expect the utilities to include demand-side resources as part of their procurement portfolio. These resources can take two primary forms: energy efficiency and demand response. We discuss each in turn below.

3. Energy Efficiency

Utilities should include in their plans procurement of baseload and intermediate load energy reductions in the form of energy efficiency. Utilities should consider investment in all cost-effective energy efficiency, regardless of the limitations of funding through the public goods charge (PGC) mechanism. The commission may authorize additional energy efficiency expenditures beyond the PGC as part of this overall procurement process, and may eventually want to move toward consideration of an energy efficiency portfolio standard similar to the RPS for renewables that is now state law. We will consider this concept in a later phase of this proceeding. In addition, we are considering other policy issues related to energy efficiency policy, programs, and implementation in R.01-08-028.

4. Demand Response

While energy efficiency resources can often meet baseload procurement needs, demand response can fill on-peak requirements. As with energy efficiency, the utilities should consider all cost-effective investment in demand response that meets their procurement needs.

Several efforts currently underway should give the utilities a head-start in procuring additional demand response resources. The Power Authority currently has a Demand Reserves Partnership program, under contract to DWR, to provide demand response resources through the ISO ancillary services market. This DWR contract is assignable from DWR to the utilities to use as part of their procurement plan. While we do not direct immediate contract assignment in this decision, we require the utilities to include the available resources in their long-term procurement plan, as well as a transition plan for eventual assignment of the contract if Commission approval occurs in the future.

In addition, the PUC, CEC, and Power Authority are cooperating in a joint rulemaking (PUC docket R.02-06-001), to design strategies, tariffs, and programs for additional demand response resources. In the course of that proceeding, we expect to identify quantitative targets for utilities to procure in demand response resources, to become part of their long-term procurement plans.

E. Transmission

To the extent that transmission investment can meet or offset procurement needs, utilities should explicitly include transmission in their resource plans. The Commission already has an investigation (I. 00-11-001) addressing transmission resource needs, and the results of that planning process should be included in utility resource assessment in this proceeding.

F. Reserves

We also make explicit, in this decision, that the IOUs are responsible for procuring reserves on behalf of their customers' needs, as part of their continuing obligation to serve in order to ensure a stable, reliable power system. The ultimate goal is to safeguard the electric system by accounting for forced outages, operating reserves, and regulating reserves, as well as other contingencies. We are aware that the Power Authority is addressing the issue of the appropriate reserve margin in its rulemaking, but will not have a final advisory opinion for the Commission to consider in time for this decision.

In their previous compliance filings in this proceeding, each of the three utilities addressed, albeit without using consistent methodologies, the need to incorporate reserves into their procurement needs. In the interim, however, it is important that the IOUs be responsible for procuring reserves to ensure system reliability. Historically, installed reserves have been 15-18% of system peak load. Therefore, on a provisional basis, we set the reserve level at 15%, subject to consideration of utility specific requirements and reexamination once the Power Authority proceeding comes to a final recommendation. In the November 12,





2002 short-term procurement plans, the utilities should identify and justify a
utility-specific reserve level and explain how it will be met and measured.¹⁵

In addition, we strongly encourage the utilities to meet as much of this reserve requirement as is cost-effective through investments in demand response resources and energy efficiency. We expect to set more specific targets on the level of demand responsive resources required in our demand response rulemaking proceeding (R.02-06-001). Finally, we note that the Demand Reserves Partnership program under contract to DWR may be counted towards the utilities' reserve requirements if approved by the Commission in the future.