V. Long-Term Planning Assumptions and Policy Guidance

A. Utilities' Current Filings

1. Parties Positions

On April 15, 2003, the respondent utilities filed long-term resource plans presenting their estimates of resource needs and how they plan to fill those needs over the years out to 2023. The plans provide basic information about the expected load growth in the utilities' service areas and the resources that will be required to meet that load. Each utility reminded the Commission of the policy issues it considers outstanding that make long-term resource planning difficult.

The utilities' plans are different from one another in style and substance, but on one point they all agree: It is difficult to make long-term plans in the absence of certainty, particularly certainty regarding future Commission policy on such issues as Direct Access. The utilities raised other issues that inhibit their ability to contract or to make long term commitments, including the lack of creditworthiness.

ORA conducted a comprehensive review of the utilities plans, including employing a consultant, Electric Power Group, to analyze and report on the resource plans. ORA states that the long-term plans represent the first significant effort in over a decade for the Commission to review the utilities' forecasts of demand and supply in a statewide planning context. It finds that the plans are voluminous, complex, and should be viewed as works-in-progress.

ORA testifies that the utilities present primarily broad generalities of their need assessments and generic options for meeting them; further, the utilities do not present specific objectives for meeting their long-term resource needs. A procurement planning proceeding, ORA asserts, should set concrete goals based on specific assumptions that can generally be relied on to evaluate the utilities anticipated procurement filing applications for resource needs and addition. ORA also notes that the utilities' fuel price forecasts were out of date, and that actual gas prices were higher than expected. Through its expert witnesses, ORA provides a number of specific criticisms of individual utility long-term plans.

TURN's position is that the utilities should submit updated long-term plans early next year and that the plans should be approved before they are implemented. TURN makes a number of comments about the utilities' long-term plans, including a statement that they are inadequate to serve as a basis for long-term resource adequacy planning. TURN argues that the utilities should be required to use standardized load forecasting methodologies, and, in the future the CEC should take charge of developing load forecasts for the state. TURN notes that the utilities' fuel and price forecasts were already outdated by the time of their submittal and recommends that the utilities should be ordered to consider specific high-price gas scenarios.

Similar to the utilities' stated position, TURN is concerned that there are certain planning variables the utilities and the Commission must face before they can plan for the future with full confidence. TURN notes a significant increase or decrease in DA customers or market distortions causing DA load to return to bundled service; the potential creation of core and non-core classes; and progress in Community Aggregation. Any one of these scenarios, TURN notes, may cause a utility's long-term plans to become sub-optimal for ratepayers.

The CEC's testimony focuses on strengthening the integration of transmission and generation planning, creating and adopting a resource adequacy framework, and placing the CEC's Integrated Energy Policy Report (IEPR) process at the center of the utilities' procurement planning. CEC states that pursuant to Public Resources Code 25302(f), the Commission is to use the CEC's IEPR "information and analyses" in its own proceedings, unless it has a "reasonable objection" to justify an alternative. CEC proposes that the IEPR information should be used as the base case for all resource planning assessments, demand forecasts and fuel analyses that project more than two years into the future, and for any identification of residual net short (RNS) positions motivating contractual and market purchase activities.65

WPTF proposes a common framework or standard template for utility procurement plans to facilitate plan comparison and to evaluate the assumptions across the utilities even if the details remain confidential. This framework, it asserts, would result in a clearer understanding of resource adequacy and system reliability. WPTF agrees with other parties that policy uncertainties, including the future of DA customers and load, contribute to the difficulty of utilities (and LSEs) in planning.

The utilities, ORA, TURN, and CEC also, as part of their Joint Recommendation, propose to revise the long-term procurement plans in 2004 and for the IOUs to submit their revised plans for approval by the Commission by the end of 2004. Parties to the Joint Recommendation agree that any specific long-term commitments made before this process is complete should satisfy the "no regrets" criteria proposed by the CEC or be a resource needed for local grid reliability.

2. Discussion

As stated in D.02-10-062, we intend that the long-term plans of the utilities be the primary vehicles for their decision-making, planning, and procurement. AB 1890's over-reliance on the short-term PX market is a failed system. To ensure reliable service at just and reasonable rates, the Commission must ensure that the IOUs develop and implement sound long- term procurement plans and longer term resource acquisitions. Long-term plans that provide solid information in appropriate detail, and that are reviewed and approved by this Commission, can provide the basis for confidence on the part of consumers, of utility managers, of investors, and of the financial community upon which the utilities depend for capital.

We agree with the utilities, ORA, TURN, and CEC that revised long term plans should be submitted and approved in 2004 and that any long-term commitments brought to the Commission in the interim should meet a "no regrets" criteria. We have addressed the resource adequacy framework these plans should reflect in an earlier section and here we will discuss other refinements needed and set a procedural schedule for 2004.

The CEC's testimony states:

"...while the process focused on the long term continues, the CEC recommends that the Utility Distribution Companies (UDCs) be authorized to continue procurement using 2003 rules as modified by a decision pertaining to the 2004 short-term procurement plans filed in May.

"In addition, to the extent that a `no regrets' perspective can lead to selective long-term commitments, some long-term commitments may be acceptable. In this context a `no regrets' perspective might mean allowing some resource additions that are highly cost-effective under any circumstance; requiring that specific resource additions be more flexible than would otherwise be required; contract terms that allow the UDC to void the agreement under various predefined triggering conditions; etc. What is unfortunate is that it will be very difficult to avoid ad hoc decisions that a particular proposed resource is `good enough' when a thorough review of the options and the risks they mitigate or exacerbate will be impossible. Without the criteria of a framework, there is no basis for evaluating alternatives." (Exhibit 49, pp. 9-10.)

Any long-term commitments brought to the Commission prior to adoption of the revised 2004 long-term plans should be reviewed within the context of the April filed plans and should make the "no regrets" showing required above. We share the concerns of the utilities, ratepayer interest groups, and market generators and retailers that with current legislation pending on Direct Access and a Core/Noncore market structure, the utilities should be careful to avoid the possibility of making long-term commitments that could become "stranded costs."

The primary focus in this decision is to guide the utilities in what we expect from them in their revised long-term plans. The first issue is the planning horizon. Several parties discuss the ISO's transmission planning process, which has a ten-year horizon. TURN recommends a ten-year planning horizon here based on estimates to allow a four-year lead time to build a power plant in California and have it in-service, and then to provide the Commission and others adequate time to evaluate resource needs and the best means to meet them.

We agree with TURN that 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.

Next, we address the level of specificity the plans should contain. ORA's concern that the utilities were overly broad and general in their long-term plans and without specific information is well taken. Though it is not appropriate for utilities to specify in detail the placement of new generation facilities that they may not need to contract for until years pass, or the specific beginning and endpoints for new transmission facilities, it is appropriate that they be more specific than they were in the submitted plans.

The 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. The long-term procurement plans should include a mix of all of the resources and products authorized in this decision, with a policy priority given to specific resources, as discussed in the following section. 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.

We find that 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. CEC's demand forecast should always be one of the scenarios presented, and if it 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. We also encourage the utilities to consider a core/non-core scenario. The utilities themselves are the ones responsible and accountable for meeting the loads and energy requirements of the customers in their service areas. Therefore, regulatory clarity and appropriate placement of responsibility requires that the utilities should have the responsibility of estimating their own future needs.

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. ORA and TURN raise an important issue regarding the use of forecast prices in long-term plans. Fuel prices are notoriously volatile, especially on a short-term basis. They vary with changes in the economy, changes in hydro conditions, changes in drilling and pipeline conditions. They vary for other reasons that are sometimes understandable only in retrospect if at all. We are not convinced that the actual degree of potential variation in fuel costs was reflected in the cost scenarios presented in the long-term plans. Therefore, we caution the utilities to consider seriously the degree of volatility that should be expected in fuel prices when developing high percentile scenarios for procurement costs particularly. We direct that 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.

The 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. We found SDG&E's plan, supplemented by confidential work papers, to be the most helpful in this regard. SDG&E presented its preferred "balanced" plan along with three others reflecting differing expectations about the desirability of in-service-area generation, new transmission, and different fuel types. SCE presented two "what-if" scenarios based on increased gas reliance and reduced gas reliance in addition to its preferred resource plan. PG&E presented several levels of need, but did not propose different ways to meet the need. 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. SDG&E presented potential costs at the mean and at several different percentile cut-offs in the total distribution, up to the 98th percentile. We find this to be very helpful and request that the utilities include at least the 90th and 95th percentile projections in their reports.

It should be understood that filing a long-term plan and having it approved by this Commission does not supplant the requirements for the individual authorizations and traditional procedures for actions that would normally require such procedures. For example, all long-term acquisitions of generating resources should be filed by application and, in the case of utility ownership of a new plant, the utility must apply for a Certificate of Public convenience and Necessity (CPC&N). Likewise, our approval of a plan that calls for the construction or upgrade of transmission capacity does not authorize the construction or upgrade itself. As discussed in a following section, while the Commission is moving to streamline its transmission review procedures, the utility must still apply for a CPC&N.

We plan to review the revised long-term procurement plans through a full evidentiary process that will conclude with a final Commission decision by end of 2004. To achieve this undertaking, we should schedule a May 7, 2004 PHC as an early status check. In preparation for the PHC, 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. Following is a procedural schedule through early May 2004. The revised 2004 long-term plans will be billed and reviewed in a new OIR.

B. Integrated Approach

We address here the policy each utility should follow in integrating specific types of resources into their procurement plans. Guiding our discussion is the "loading order" set forth in our Energy Action Plan:

"The Action Plan envisions a `loading order' of energy resources that will guide decisions made by the agencies jointly and singly. First, the agencies want to optimize all strategies for increasing conservation and energy efficiency to minimize increases in electricity and natural gas demand. Second, recognizing that new generation is both necessary and desirable, the agencies would like to see these needs met first by renewable energy resources and distributed generation. Third, because the preferred resources require both sufficient investment and adequate time to `get to scale,' the agencies also will support additional clean, fossil fuel, central-station generation. Simultaneously, the agencies intend to improve the bulk electricity transmission grid and distribution facility infrastructure to support growing demand centers and the interconnection of new generation."

1. Energy Efficiency

a) Procurement Energy Efficiency Funding Levels for 2004-05

In D.02-10-062, we established policy priorities for resource acquisition for utility long- and short-term procurement plans. In that decision we identified energy efficiency as a priority resource and ordered utilities to include all cost-effective energy efficiency in their portfolio proposals.

    "Utilities should include in their plans procurement of baseload 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."

In D.02-10-062, we also ordered utilities to submit long-term procurement plans, with estimates of energy efficiency savings projections for the first year, five years, and twenty years. PG&E, SCE, and SDG&E filed their long-term plans with the Commission on April 15, 2003. Each plan included estimates of energy efficiency resources they propose to acquire for these time periods.

The following table shows utility projected procurement costs for energy efficiency programs for the years 2004 through 2008.

Utility

2004

2005

2006

2007

2008

Total

PG&E

25

50

50

75

100

300

SCE66

60

60

60

60

60

300

SDG&E

25

25

25

25

25

125

Total

110

135

135

160

185

725

    (1) Parties' Positions

No parties opposed utility energy efficiency procurement proposals. In its long-term plan testimony, ORA analyzed the cost-effectiveness of the energy efficiency component of the three utilities' long-term procurement plans over the first five years of the plan, finding each utility's proposal cost-effective. CEC's long-term plan testimony supported the inclusion of energy efficiency program elements in the long-term plan that go beyond the limits of PGC funding levels and recommended acceptance of utility energy efficiency proposals in its opening brief (p. 13). The "Joint Parties" recommendation (CEC, ORA, TURN, SCE, SDG&E, PG&E) also supports the additional proposed energy efficiency programs. NRDC in its long-and short-term plan testimony supports Commission authorization of utility energy efficiency procurement proposals and urges the Commission to allow utilities the flexibility to capture additional cost-effective efficiency resources that have been identified in potential studies. Finally, TURN urges the Commission to authorize only funding levels for energy efficiency resource acquisition in this proceeding, with specific program selection to be accomplished in R.01-08-028.

    (2) Discussion

Utilities approach the energy efficiency component of their long-term plans in different fashions. Both SDG&E and SCE worked directly with a contractor, Kema-Xenergy, to determine the potential for energy efficiency in their service territories, focusing on the several options for capturing the energy efficiency resource available in their territories. PG&E developed its long-term proposal based on forecasts of its net-residual short needs, matching these to programs that deliver energy savings and peak demand reduction measures with load profiles that reduce demand and save energy at times of forecasted need. We agree with NRDC and the City of San Diego that these approaches result in utility plans that capture "some," but not "all" of the energy efficiency potential identified in the latest studies of the available potential of energy efficiency in the utility service territory.67 Nonetheless, each utility will need time to ramp-up enhanced existing and new energy efficiency programs. For this reason, we are inclined to accept utility long-term energy efficiency plan proposals as proposed.

The utilities' long-term plans identify procurement funded energy efficiency program activities for the five-year period 2004-2008. In this decision we authorize utility procurement energy efficiency budgets for the two-year period 2004 and 2005. We limit these initial procurement energy efficiency activities to this two-year period to ensure consistency across the Commission's entire portfolio of energy efficiency programs, with a specific goal of ensuring consistency with efficiency program activities authorized in this proceeding and those authorized in the Commission's Energy Efficiency Rulemaking 01-08-028. Consistent with the July 3 ACR, we choose this two-year program horizon as an interim-step to allow the Commission to review and address key issues identified in the ACR. Included among these are: long-term administration of Commission authorized energy efficiency programs; duration and cycle of these programs; energy efficiency goals; performance incentives and related issues. In this decision, we therefore maintain the status quo in term of program administration and other identified issues. By taking this approach, we balance the advantages of a multi-year (2-year) planning and budgeting cycles with the reality of the time needed by the Commission adequately deliberate on and resolve these questions. We refer parties to our discussion below of energy efficiency program administration and other key issues identified in the July 3 Assigned Commissioner's Ruling.

In summary, 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.

b) Program Selection Criteria

At the July 16, PHC, we asked parties to comment on program evaluation and selection criteria for energy efficiency activities funded here. At that time, we suggested parties comment on whether these programs should be evaluated using four specific criteria: long-term energy savings, cost-effectiveness, peak savings, and equity among rate classes, or utilizing other criteria for selection of procurement energy efficiency programs, such as those subsequently adopted in D.03-08-067 in R.01-08-028.

    (1) Parties' Positions

Parties commenting on program selection criteria proposed several different approaches. SDG&E supports use of three selection criteria for evaluation of procurement energy efficiency programs: long-term annual energy savings, cost-effectiveness, electric peak demand savings. In its testimony, NRDC notes that all programs must be "cost-effective," and recommends three criteria, including long-term annual energy savings, electric-peak demand savings, and the addition of "equity between customer classes." The ORA testimony focuses on the need to have a consistent Commission energy efficiency portfolio and recommends use of the same criteria for procurement programs as those used to evaluate PGC funded energy efficiency programs, including proposers' demonstrated success in implementing EE programs.

    (2) Discussion

Utility long-term plan forecasts project expected energy savings and demand reductions from both procurement funded and PGC funded efficiency programs. As such, these programs, whether PGC or procurement funded, are part of a comprehensive portfolio of energy efficiency resource acquisition programs to be authorized by the Commission. Consistent with our desire to proffer a uniform energy efficiency portfolio, we agree with ORA's comments that 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. These primary criteria include: cost-effectiveness, long-term savings, peak demand reductions, equity considerations, ability to overcome market barriers, innovation, and coordination with other programs.

c) Procurement EE Program Submissions, Evaluation and Selection

For 2004-2005 utilities submitted to the Commission a total of eighteen68 procurement energy efficiency program proposals totaling $244,586,000 million over the two-year period 2004-2005. Total projected energy savings and demand reduction from these programs are: 1,675,845 MWh and 336.5 MW. PG&E proposed a single program effort for a cost of $75 million over the two-year period. Projected two-year energy savings for PG&E are 466,883 MWh with projected demand reductions of 124.4 MW. SCE proposes 8 statewide procurement energy efficiency programs and 2 local programs at a two-year energy cost of $120 million with a two-year energy savings goal of 956,994 MWh and a demand reduction goal of 168.2 MW over the period. SDG&E proposes 2 statewide and 5 local programs for a total cost of $49,586 million over the two-year period. Projected energy savings over this period are 251,968 MWh and 43.9 MW in demand reductions.

The following table shows the projected incremental energy efficiency program costs, energy savings, and demand reductions from utility procurement programs in 2004 and 2005 as compared to estimated program costs, savings and demand reductions from proposed 2004-2005 PGC funded programs.69

    (1) Projected Utility Energy Efficiency Procurement and PGC Funded Cost, Energy Savings &Demand Reductions for Procurement and PGC Funded Programs

2004-2005

 

PGC Budget

( $million)

Procurement

Budget

($ million)

PGC

Energy Savings

(MWh)

Procurement

Energy Savings

(MWh)

PGC

Demand Reductions

(MW)

Procurement

Demand Reductions

(MW)

PG&E

257,932,300

    75.0

1,069,568

466,883

    196.9

124.4

SCE

182,692,272

    120.0

483,636

956,994

107.9

168.2

SDG&E

76,746,020

    49.6

259,015

251,968

48.5

    43.9

Total

517,370,592

    244.6

1,069,568

1,675,845

353.3

    336.5

Parties having a further interest in reviewing specific utility energy efficiency procurement proposals may view these on the Commission's website at http://www.cpuc.ca.gov.

To ensure consistent evaluation of the Commission's total energy efficiency portfolio being developed in both this proceeding and in R.01-08-028, the ALJ directed the utilities to submit in R.01-08-028 the 2004-2005 procurement energy efficiency proposals for evaluation at the time of Commission review and evaluation of Public Goods Charge (PGC) funded energy efficiency program proposals. The Commission reviewed these programs by using the process and criteria described above.

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. This Commission expects to authorize its portfolio of energy efficiency programs in R.01-08-028 before the end of 2003.

d) Cost-Recovery Mechanism for Procurement EE Activities

    (1) Parties' Positions

Each utility proposes somewhat different mechanisms for cost-recovery of procurement related energy efficiency activities. PG&E proposes the establishment of an Incremental Procurement Energy Efficiency Balancing Account (IPEEBA) to record the costs of authorized incremental energy efficiency programs as these costs are incurred.70 PG&E would request recovery of these costs in subsequent ERRA proceedings. SCE proposes to record expenses for procurement authorized energy efficiency programs directly in its ERRA, and request approval of these during its October annual ERRA filing.71 SCE testifies that such an approach is reasonable as such expenses directly benefit bundled service customers who take generation and procurement related services from SCE. SDG&E, in its testimony, proposes that incremental procurement energy efficiency costs be subject to recovery through a non-bypasssable charge to all customers and requests the Commission establish a balancing account for costs and revenues recorded in the balancing account.72

In its long- and short-term procurement plan testimony, NRDC supports utility cost-recovery for the actual costs incurred for procurement energy efficiency programs provided that these programs meet Commission rules for cost-effectiveness and rigorous evaluation, measurement and verification. The Joint Parties' recommendation also endorses utility cost-recovery for incremental procurement energy efficiency programs identified in their long- and short-term procurement plans.

    (2) Discussion

In deciding which of the proposed cost-recovery mechanisms best serve the needs of providing utilities cost-recovery in an expeditious and fair manner, we are cognizant of the fact the SCE's proposal, if adopted, holds the potential for increasing recorded costs in the ERRA account to a degree that could trigger the adjustment mechanisms within that account. Both PG&E and SDG&E propose the establishment of balancing accounts to record energy efficiency costs and revenues outside the ERRA. SDG&E also proposes that these costs be funded through a non-bypassable surcharge on all customers.

After reviewing the various proposals, we find that SDG&E's proposed approach to implement a non-bypassable surcharge on all customers to pay the costs of energy efficiency program funding authorized in this proceeding provides a simple to understand, fair, and expeditious mechanism for providing utilities cost-recovery for procurement related energy efficiency activities. Moreover, this approach provides symmetry to the current Commission approach for funding Public Goods Charge programs as enunciated in Public Utilities Code § 381. In authorizing a non-bypassable surcharge to pay the costs of procurement efficiency program, the Commission remains mindful of the need for continued coordination of procurement efforts related to cost-recovery with related issues that may arise in R.01-08028. We therefore order the respondent utilities to 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. Further, within twenty days of this decision, we order the utilities to file advice letters establishing the methodology and surcharge rate for incremental procurement energy efficiency programs for PY 2004 and 2005.

e) Performance Incentives for Procurement Efficiency Activities

    (1) Parties' Positions

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. We directed SDG&E to sponsor, in coordination with the other utilities, an all-party workshop to develop an incentive mechanism proposal for utility electric procurement, including the energy efficiency component. SDG&E held several workshops on the issue resulting in the identification of key principles for an incentive mechanism. No consensus was reached by the utilities on specific incentive proposals and no proposals have been filed for our review.

At the hearing, many parties testified on this issue. The CEC supports supports the Commission adoption of an "incentive mechanism that motivates utilities to pursue CPUC objectives at both the planning and operational stages of procurement." (Jaske, 6/23/03, p. 27.) SDG&E cites in its workshop status report statement that although no consensus for uniform incentives was reached, it will continue on to develop its own SDG&E proposals with several of the parties to the workshop process. SCE states that it has developed a DSM incentive mechanism that it is prepared to file in the new phase of this proceeding.73 PG&E proposes a specific incentive structure for energy efficiency programs only, urging the Commission to adopt it proposal. NRDC supports utility incentive mechanisms urging the Commission to adopt these in this procurement proceeding as apart of a universal procurement incentive program (LTP/STP testimony - p. 20), with a particular focus on rigorous measurement and verification of program impacts for energy efficiency activities. (ORA (LTP testimony, p. 59) and TURN (Opening Brief, p. 13) oppose utility incentives in the procurement proceeding and specifically urge the Commission to address incentives for energy efficiency in the energy efficiency Rulemaking 01-02-8-028. TURN further notes (Opening brief, p. 12) that "neither the issue of administration of energy efficiency programs, nor the issue of the appropriateness of any incentive payments, was adequately analyzed and debated in this proceeding."

    (2) Discussion

Incentive mechanisms for both supply- and demand-side options present the complex problems of a potential to design a "one-scheme-fits-all," mechanism that may not be appropriate to all parties. We laud SDG&E's efforts to identify principles and mechanism for comprehensive incentive mechanisms that cover both generation and non-generation resources. Nonetheless, the difficulty in finding consensus on this issue across a broad array of technologies and resource options leads us towards a more manageable approach that defers certain resource incentive mechanism development to specific resource proceedings where these can be presented and debated by parties in a focused manner. Further, we concur with TURN's comments that we do not have an adequate record on this issue with which to decide the issue.

By today's decision we refer the issue of energy efficiency incentives to R.01-08-028 for disposition in that rulemaking. We take this approach due to the complexity of the topic, the need to develop a more comprehensive record on this issue, and the need for a focused effort that encompasses the entire energy efficiency portfolio authorized by this Commission.

As discussed in this decision, we are also addressing in R.01-08-028 the issue of what administrative structure should be in place for energy efficiency development in the future. Therefore, the incentive mechanisms for energy efficiency proposed by parties in this proceeding, along with others that we will consider in R.01-08-028, must be evaluated in the broader context of what role the utilities will play in program administration in the near and long-term. Moreover, as the Assigned Commissioner in R.01-08-028 observes:

      "Once the Commission articulates program goals for reducing energy consumption, it will need rigorous measurement and evaluation activities in order to assess our progress towards meeting those goals. In addition, if the Commission decides to award incentives for superior performance in meeting or exceeding energy efficiency goals, the Commission will need assurance that the reported performance is accurate. In both instances, rigorous evaluation is necessary." (Assigned Commissioner's Ruling Proposing Direction and Scope for Further Rulemaking, R.01-08-028, July 3, 2003, p. 10.)

We intend to evaluate and update existing measurement protocols for this purpose in R.01-08-028. Today's referral of the incentives issue to our energy efficiency rulemaking recognizes that any development of energy efficiency incentive mechanisms is also linked to the measurement issues being addressed in that forum.

Accordingly, in recognition of the interrelationship among the various issues currently being considered in R.01-08-028, and the issue of energy efficiency incentives, we request that a further prehearing conference be held as soon as practicable in R.01-08-028, the purpose of which would be to address the scope and schedule of the issues identified in the July 3 ACR in light of today's decision to also refer the consideration of energy efficiency incentives to that proceeding.

f) Procedural Issues Related to Efficiency Rulemaking 01-08-028

Energy efficiency activities initiated in this procurement proceeding need to be closely coordinated with efforts underway in the commission's energy efficiency rulemaking, R.01-08-028. This is the case not only for this decision round, but also for future Commission deliberation on efficiency policy in both R.01-08-024 and R.01-10-028. Below we address a series of current "crossover" procedural issues and provide guidance concerning the future disposition of these issues.

    (1) Program Duration and Cycles

As we stated above, we seek consistency in the portfolio of energy efficiency programs authorized by the Commission. This consistency applies to the question of the duration and programs and future cycles of energy efficiency program efforts. In R.01-08-028, the Commission adopted a two-year interim cycle for energy efficiency programs funded through the PGC mechanism. In our proceeding, we have followed this model and order utilities to present procurement related incremental energy efficiency proposals to the Commission for the same two-year interim period. Many parties addressed the subject of multi-year planning horizons, with several favoring these (NRDC, SDG&E, SCE, PG&E, and several others opposed to planning horizons of more than a year or two (ORA and TURN). To ensure ongoing alignment of energy efficiency program activities in the procurement and energy efficiency Rulemakings, we refer future issues related to program duration and program cycles to R.01-08-028 for disposition in that Rulemaking.

    (2) Program Specific Evaluation

The Commission will continue the model established in this Rulemaking to require that all proposed program specific procurement related energy efficiency activities be evaluated and modified as necessary in R.01-08-028 as part of the overall Commission portfolio of program activities. Hence, in this Rulemaking we will continue the practice of authorizing specific levels of funding for energy efficiency procurement activities, but refer review of specific program offerings in the future to the Energy Efficiency Rulemaking.

    (3) Energy Efficiency Goals for the Commission's Portfolio of Programs

In our hearings we, took into our record testimony related to utility procurement program proposals related to the 1 percent per capita per year energy reduction goals identified in the July 3, 2003 Assigned Commissioner Ruling (R.01-08-028). Utilities provided information related to their procurement energy efficiency proposals and the per capita reduction goal. Since that time, CEC has issued a staff workpaper74 on this issue, and the CPUC has scheduled workshops on the issue. Continued discussion and resolution of what energy efficiency goals, if any, should be established is a continuing subject of review in R.01-08-028. We therefore refer future issues related to the per capita or other types of overarching energy efficiency goals to the EE Rulemaking for disposition.

    (4) Future Administration of Energy Efficiency Programs

SDG&E, SCE, and PG&E all urge the Commission in their long-term plan testimony to establish utilities as the lead organization for implementing energy efficiency programs funded through these Procurement proceedings. SCE, in particular, argue early-on in the proceeding that it could not guarantee the energy savings projections from its procurement "preferred plan" unless it was specifically charged with administering the plan, and therefore suggested that it might need to implement its "interim plan " with lower energy efficiency savings projections. SCE changes this position in its opening brief, requesting the Commission to adopt the energy efficiency and demand response budgets associated with their "preferred plan." Each of the utilities urge resolution of this issue as soon as possible in R.01-08-028.

Many parties comment on the issue of administration of energy efficiency programs. In its testimony, TURN took no explicit position on whether utilities should or should not administer energy efficiency programs but strongly urged the Commission to address this issue in the energy efficiency proceeding. ORA concurs with TURN, urging the Commission to "promptly" address this issue. NRDC urges the Commission as well to resolve the "unsettled issues" regarding the administration of energy efficiency programs. Utility long-term plans also support prompt resolution of this issue in R.01-08-028.

Both the initial Order Instituting Rulemaking and the July 3 ACR for R.01-08-028 identify administration of energy efficiency programs as one of the key issues to be addressed in that Rulemaking, with a goal of resolving this issue in 2004. As the Commission will authorize a uniform portfolio of energy efficiency, we believe it necessary that the Commission have in place a unified administrative structure to oversee all energy efficiency programs regardless of the source of funding in the years ahead. For this reason, we are referring the issue of administration of energy efficiency programs authorized in this proceeding to R.01-08-028.

g) Other Issues

    (1) Utility and Non-Utility Filings for Procurement Related Energy Efficiency Programs

During the course of this proceeding we have given attention exclusively to utility energy efficiency proposals in response to Commission direction in D.02-10-062 to integrate energy efficiency in utility plans for procurement of baseload energy reductions. We noted in that decision that utilities should consider investment in all cost-effective energy efficiency. In response utilities have filed procurement proposals as described above. We are confident that utilities will make every effort to meet projected energy savings goals. Nonetheless, in this proceeding we wish to broaden the base of those parties able to assist utilities in meeting their demand reduction and energy savings goals through the offering of innovative energy efficiency program proposals. Hence, in future procurement decisions, we intend to open the process for application for procurement energy efficiency programs to non-utility parties as well as utilities.

    (2) Valuing Potential Penalty Cost for CO2 Emissions

In its long-term plan testimony, NRDC requests that the Commission require PG&E, SDG&E and SCE explicitly analyze financial risks associated with any future regulation of carbon dioxide emissions and incorporate protections for their customers by shifting any risk to customers to the sponsor of the resource creating the risk. NRDC suggests that such risk may occur should utilities build in the future or own coal-fired plants or be involved in other ways with plants presenting a potential financial risk to customers from the C02 emissions. In reviewing this question, we note that the Commission is presently working with a contractor in R.01-08-028 for the explicit purpose of reviewing and updating its avoided-cost methodology for analyzing the costs and benefits of various resource options. For the energy efficiency component of that methodology the Commission has in the past taken into account the environmental benefits associated with energy efficiency by incorporating environmental "adders" to the calculation of the Societal Total Resource Cost Test (TRC). The Commission and its contractor are working with an advisory group to that process that includes representatives from CEC, NRDC, utility and other parties. In this decision, we 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.

    (3) Valuing Non-Utility Energy Savings in Procurement Forecasts

In the July 3, 2003 ACR (R.01-08-028), the Assigned Commissioner states,

      "I (also) see no distinction in the reliability of the resource between a utility-operated program and one delivered by a non-utility entity. Therefore, I propose to treat all energy efficiency programs as an integrated portfolio to be authorized in this proceeding."

TURN echoes this comment in its opening procurement brief when it suggests that "there is no reason why expected savings from energy efficiency programs conducted by other entities cannot be used as inputs to determine other resource needs, such as energy procurement on the spot market, which may be met by the utilities." We concur with this view. As more and more non-utility entities enter the energy efficiency program delivery field, more and more energy savings will be attributed to non-utility providers. Therefore, in this proceeding, in the next utility filing of their long- and short-term procurement plans, we order utilities in their demand forecasts for those filings to include expected energy savings from non-utility programs that operate in their service territories.

2. Demand Response

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. In D.02-10-062, we directed the utilities to consider all cost-effective investment in demand response that meets their procurement needs. We also stated that the Commission, CEC, and CPA are cooperating in a joint rulemaking, R.02-06-001, to design strategies, tariffs, and programs for additional demand response resources and, in the course of that proceeding, expect to identify quantitative targets for utilities to procure in demand response resources. Further, we directed that the targets adopted in R.02-06-001 should be integrated into the utilities long-term plans.

Our EAP places a top priority on energy efficiency and demand response programs in its "loading order" of energy resources. Specifically, the plan states:

In their filings, the utilities include various interruptible programs, the Commission's traditional, reliability-based demand response programs, and newer, price-triggered demand response programs such as the Critical Peak Pricing (CPP) tariff currently being implemented for larger customers, and tested for smaller customers in the Statewide Pricing Pilot (SPP).

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.

The MW targets for each utility are set forth in Table 1 of D.03-06-032:

Table 1. Demand response goals

Year

PG&E

SCE

SDG&E

2003

150 MW

150 MW

30 MW

2004

400 MW

400 MW

80 MW

2005

3% of the annual system peak demand

2006

4% of the annual system peak demand

2007

5% of the annual system peak demand

Funding for price-responsive demand response programs is also addressed in D.03-06-032. In Ordering paragraph 22, we state:

"The total cost expenditures authorized as a result of this decision are capped at $33.0 million over the two calendar years, exclusive of revenue shortfalls and costs related to "other incentives" which are part of the DWR revenue requirement. Each IOU shall use the cost recovery mechanisms previously adopted in D.03-03-036 as applicable to all Phase 1 programs."

PG&E's long-term plan includes its existing demand reduction programs and three new price-responsive programs. No additional funding is requested here. PG&E provides a conservative forecast, testifying on the difficulty of estimating demand reduction levels from new DR programs given various uncertainties. ORA testifies it reviewed the request and supports PG&E's filing on this issue. We adopt PG&E's demand reduction proposal.

SDG&E's plan reflects an aggressive demand response forecast and encourages the Commission to consider an incentive mechanism for all demand-side programs. SDG&E does not request any funding authorization here. ORA expresses concern with counting untested demand reduction programs for purposes of resource adequacy. We address this resource counting issue in our earlier Resource Adequacy and Reserve Requirements section.

In its "preferred plan," SCE requests $40 million in pre-approved funding for seven years and approval of a "new and improved" Airconditioning (A/C) Cycling Program (ACCP). Further, SCE states program review should not be subject to after-the-fact reasonableness review. ORA testifies the expected peak load reduction from this program seems unrealistic and does not support the funding request. CEC recommends this program be referred to R.02-06-001 for in-depth examination.

We agree with CEC and ORA's recommendation that new ACCP programs need to be reviewed in R.02-06-001 or its successor demand response rulemaking. This allows for program specifics to be carefully examined and for the necessary evaluation and measurement standards to be adopted. The Commission can then directly authorize funding that proceeding. SCE's proposed program is an emergency-demand response program, and the future of these programs, in relation to price-response programs, is a policy issue for R.02-06-001 or its successor. We do not approve SCE's request for funding.

3. Renewables

In general, we find that the utilities did not provide a robust analysis of future renewables supply growth in the renewables sections of their respective 2004 and long-term plans. This can be largely attributed to the fact that at the time the utilities prepared their filings, RPS program development was in progress and the Commission had yet to issue and adopt D.03-06-071. We note that the 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. Our approval of the 2004 procurement plans today does not "trigger" an RPS solicitation as detailed in D.03-06-071. That solicitation requires further development of RPS criteria, such as the Market Price Referent (MPR), additional least-cost and best-fit evaluation criteria, and standard contract terms and conditions. Interim solicitations will follow guidelines already established by the Commission, and are also addressed below.

a) RPS Requirements

Pub. Util. Code § 399.14(a)(2) requires the Commission to adopt, by rule, four key RPS elements:

    1. a process for determining market prices;

    2. a process that provides criteria for the rank ordering and selection of least-cost and best-fit renewable resources to comply with the RPS on a total cost basis;

    3. flexible rules for compliance;

    4. standard terms and conditions to be used in contracting for eligible renewable resources, including performance requirements for renewable generators.

D.03-06-071 adopts rules for these RPS elements, and addresses other issues such as creditworthiness and renewable energy credits. The Assigned Commissioner's Ruling Specifying Criteria for Interim Renewable Energy Solicitations (ACR) dated August 13, 2003, provides criteria for any interim renewables solicitations conducted by a utility prior to a full RPS solicitation implementing the utility's renewable procurement plan. While we strongly discourage pre-RPS solicitations, any renewables solicitations that do occur prior to a full RPS solicitation will follow the criteria set forth in the ACR.

We now discuss elements of the RPS that pertain to the 2004 and long-term plans.

    (1) Renewable Procurement Plan

One of the first actions of the forthcoming RPS OIR will direct the utilities to file renewable procurement plans pursuant to Pub. Util. Code § 399.14(a)(3). This section states:

      "Consistent with the goal of procuring the least-cost and best-fit eligible renewable energy resources, the renewable energy procurement plan submitted by an electrical corporation shall include, but is not limited to, all of the following:

Once the renewable procurement plans are approved by the Commission, a solicitation conforming to all the adopted parameters and rules of the RPS will commence pursuant to Section 399.14(a)(3)(C). As noted above, those elements necessary for a full solicitation are still being developed and refined. We anticipate that the first solicitation will take place in Q2 2004, and discourage renewable energy solicitations prior to that time. The RPS phase of this proceeding and the new forthcoming RPS OIR are the appropriate venues for new or revised rules pertaining to the RPS solicitations.

    (3) Market Price Referent and Interim Benchmarks

The ACR does not adopt an interim benchmark for determining the cost-effectiveness of renewables bids. Instead it allows the utilities to develop internal benchmarks for evaluation purposes, provided those benchmarks are provided to the PRG and submitted to the Commission as part of its Advice Letter filing requesting approval of contracts.

The purpose of the MPR is to establish a market price up to which utilities may purchase renewable energy. Costs above the MPR for selected contracts will be paid through Supplemental Energy Payments following CEC guidelines. Following Commission approval of the MPR methodology, the referent will be developed by Commission staff and made available to the utilities during the RPS solicitations after bidding has closed.

    (4) Contract Lengths

Pub. Util. Code § 399.14(a)(4) requires utilities to "offer contracts of no less than 10 years in duration, unless the commission approves of a contract of shorter duration." D.03-06-071 found that shorter contract terms were not desirable:

      "We do not see any good reason to permit the utilities to offer contracts of less than 10 years in duration..." (Decision at p. 57.)

The Decision specifies that "utilities should seek bids for 10, 15, and 20-year products."

    (5) Eligibility for Supplemental Energy Payments

No contracts entered into during the interim period prior to full RPS solicitations may be contingent upon receiving PGC funds for Supplemental Energy Payments (SEPs) pursuant to Pub. Util. Code § 399.15(a)(2). The ACR states:

      "Any renewable procurement in this interim period (regardless of whether it is conducted through an RFO or bilateral negotiation) must not anticipate the use of any Supplemental Energy Payments to be awarded by the CEC pursuant to Public Utilities Code Sec. 383.5(d)."

Bidders may, however, retain previous CEC awards, consistent with direction given in the ACR:

      "Projects that have previously won an award from an auction conducted by the CEC (public goods funds which were collected pursuant to SB 90) may bid or negotiate and still remain eligible to receive their award once the project begins producing electricity pursuant to a Power Purchase Agreement."

    (6) Creditworthiness

We determined in D.03-06-071 that utilities are not required to procure renewable energy under the RPS until they are creditworthy. However, utilities that are not creditworthy still have an annual procurement target (APT), and may be directed to prepare a renewable procurement plan prior to RPS solicitation, as this is not considered "procurement" under Pub. Util. Code § 399.14(g). Additionally, SB 67 provides a condition by which non-creditworthy utilities may be directed to undertake renewables procurement, as discussed below.

    (7) Standard Terms and Conditions

D.03-06-071 provided parties with guidance on further development of standard terms and conditions to be used in contracting for renewable energy. Specifically, Energy Division held two workshops to bring parties together and explore areas of agreement on which terms should be made standard and possible language for those terms. ALJ Allen issued a ruling on October 22 requesting briefs on which terms and conditions should be made standard. Briefs were submitted on November 12, with reply briefs due December 3. The Commission will issue an interim decision identifying which terms and conditions shall be adopted as standard. Subsequently, the parties will submit briefs with specific recommended language for each of those terms and conditions. Finally, the Commission will issue a decision adopting specific language for each standard term and condition. Any standard contract terms and conditions, upon adoption by the Commission, will be used in all subsequent solicitations for renewable products.

b) Short-Term Plan Issues

PG&E proposes that the Commission adopt an interim all-in benchmark of 5.37 cents per kWh, and subsequently review and update the benchmark. The Commission will develop the MPR to accomplish this goal. Additionally, the ACR provides guidance on use of interim benchmarks. Our attention is now focused on refining the methodology for the MPR, and as such we do not adopt an interim benchmarking process. We therefore decline to adopt PG&E's request for an interim all-in benchmark of 5.37 cents per kWh.

PG&E also proposes to conduct a renewables solicitation within 60 days of approval of its 2004 procurement plan. PG&E proposes to sign only one-year contracts, due to its credit status. In its testimony, ORA states that such short-term contracts will "increase the chances of a utility having greater difficulty in meeting its RPS in the future..."75 Although the term lengths addressed in D.03-06-071 should apply to RPS solicitations, 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. We address PG&E's credit status below, noting here that the Commission may determine that PG&E can undertake renewables procurement prior to creditworthiness subject to specific conditions. We deny PG&E's request for one-year renewables contracts, and focus attention instead on progress towards a full RPS solicitation in early 2004.

The IOUs recommend meeting their QF obligations under PURPA in various ways, including competitive solicitations (SCE proposal) and one-year SO1 contract extensions (PG&E proposal). SDG&E refers to holding an "auction" for QF contracts. While renewable bidders are welcome to participate in all-source solicitations outside the RPS bidding parameters, a unique MPR will not be developed for such solicitations. Therefore, bidders must not anticipate the use of SEPs, nor shall bids contain SEP contingencies. This is consistent with the August 13 ACR. Bidders may, however, retain previous CEC awards, as stated above. The utilities may receive and select cost-effective renewables bids under an all-source solicitation, and the bid evaluation process must not treat those bids unfairly when compared with non-renewable product offerings. Additionally, any contracts resulting from these solicitations will count toward an IOU's RPS targets, provided the facilities are deemed eligible renewable resources.

We reaffirm that 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. Approval of the 2004 plans does not constitute a waiver of this requirement.

c) Long-Term Plan Issues

While PG&E proposes to enter into renewables contracts prior to obtaining an investment-grade credit rating, it states in its 2004 and long-term plans that it is "not required to participate"76 in the RPS program, is "ineligible to participate,"77 and goes so far as to say it "will not participate in the RPS program until it is creditworthy."78 ,79 D.03-06-071 found that while "utilities that are not creditworthy are not required to procure under the RPS program," such a utility will still have an APT for a given year. SB 67, signed into law after the IOUs filed their plans, provides an optional means of renewables procurement prior to creditworthiness80. Thus, PG&E will accrue an APT prior to creditworthiness, and can utilize the adopted flexible compliance mechanisms to meet its APT once it either becomes creditworthy or is able to procure renewables subject to Pub. Util. Code § 399.14(a)(1)(A)(ii). As noted above, a non-creditworthy utility can also be directed by the Commission to prepare a renewable procurement plan under the provisions of Pub. Util. Code § 399.14(g).

PG&E also states at page 1-21 of its long-term plan that its "participation in the RPS is conditioned on it having a demonstrable need for resources and having first attained an investment grade rating..." D.03-06-071 addresses this issue:

    "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 legislation. `Unmet long-term resource needs' must be considered on a statewide basis, not a utility-by-utility basis, and the Legislature has already essentially found that there are statewide unmet long-term resource needs." (Decision at p. 41.)

Thus, the conditions PG&E attaches to its RPS participation are invalid.

SCE does not explain why its resource model assumes $100 per MWh for "new generic renewables" (Vol. 2, p. 52). This price exceeds any Commission-established benchmark to date. SCE must provide an explanation of the derivation of this value and its use. Additionally, we have stated that the plans must be modified to provide additional detail of expected renewable product types.

We are concerned that SCE modeled renewables as a "generic" block of energy, irrespective of resource type, in its portfolio model. This simplified approach also appears to be 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." The IOUs should project some amount or percentage allocation of baseload, peaking and intermittent resources, as each provides a different fit to a utility's resource needs. SDG&E estimates 20 percent wind and 80 percent baseload resources. PG&E estimates its five-year renewables needs will be primarily for peaking and reserve requirements (amounts not specified), with specific baseload needs in 2007 and 2008.

Given their existing base of renewables, and contracts signed under the transitional procurement period, the IOUs should be able to estimate renewable resource profiles with a greater degree of specificity. This amount of energy is substantial over the long-term planning horizon, and will undoubtedly affect the utilities' need for other procurement products in the future. The renewable procurement plans will require such an assessment,81 and it is feasible and prudent to perform this analysis now, on a preliminary basis, in the 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. The long-term plans should be modified accordingly.

The IOUs should also update their 2004 and long-term plans to include interim procurement activity from 2003. The Commission approved PG&E contracts for biomass energy in Res. E-3853. While SCE and SDG&E have renewables solicitations in progress, they should summarize the proposed bids (with publicly filed information) and describe how those products fit into their procurement portfolios. SCE should provide an update on its current RFOs for general renewables and wood waste renewables products. SDG&E should provide an update on its grid reliability solicitation, filed with the Commission on October 7.

The Energy Action Plan calls for the acceleration of the 20 percent RPS goal to year 2010. In its testimony, NRDC urges the IOUs to provide details on how they intend to respond to the Energy Action Plans' accelerated RPS target. The accelerated target will necessitate changes in the IOUs' overall portfolios. Each IOU should modify its plan to include an accelerated RPS target renewables procurement scenario that evaluates any resulting changes to its overall energy procurement portfolio.

Meeting the goals of the RPS on the accelerated schedule of the Energy Action Plan will require a thoroughgoing review of the total resource portfolios of the IOUs, and careful consideration of which nonrenewable resources, in the long run, can or should be displaced or shut down to accommodate renewable development at this scale. This task will be the principal point of interconnection between this docket and the new RPS OIR to be opened in early 2004. While the near-term need for generation in California must remain central to the resource planning and procurement process, the decisions we make today must not work at cross-purposes with the long-term goals we have embraced for renewable energy development. Without an assertive planning role in this regard it is unclear how the renewable energy goals of the EAP can be met.

We acknowledge that development of renewables to achieve the goals of the RPS will necessitate transmission upgrades and possible construction. The IOUs have separately filed conceptual transmission plans to this effect, and the Commission is preparing a report to the Legislature on these issues. These issues will most likely affect long-term planning and will be addressed in I.00-11-001, the RPS phase of this proceeding, and any relevant successor rulemakings.

4. Distributed Generation

In D.02-10-062, we ordered the utilities to explicitly include provision for distributed generation and self-generation resources in their long-term procurement plans. We stated that:

    "Distributed generation 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." (D.02-10-062, p. 27.)

The Energy Action plan adopted by the Commission, the CPA, and the CEC, provides additional support for distributed generation, placing it second in the loading order and enumerating a number of objectives for the state to achieve:

Based on its review of the utilities' long-term procurement plans, ORA testifies that:

    "It is difficult to compare, or, in some cases, even extrapolate, the self-generation projections by the different utilities.... Another problem arises when utilities lump self-generation with energy efficiency measures, since from the utilities' point of view, both are seen as load reductions. But from ORA's point of view, it is important to be able to separate these out."

In its direct testimony, the Joint Parties Interested in Distributed Generation/Distributed Energy Resources (Joint Parties) find that the utilities did not provide a sufficient level of detail in their respective procurement plans showing how they will incorporate distributed generation into their resource portfolios. The Joint Parties therefore conclude that the utilities did not comply with Commission directives on this issue. Additionally, the Joint Parties recommend that the Commission direct the utilities to undertake a study effort to analyze the cost-effectiveness of distributed energy resources and to assess the size of the potential distributed energy resources market in California. Lastly, the Joint Parties propose a set-aside for distributed energy resources while study work is being conducted.

    "The Joint Parties recommend that the Commission require that the utilities increase procurement from on-site DER projects 20 MW or less by a minimum of 1.5% per year (using 2003 as the baseline year), beginning in 2004, up to a minimum total of 7.5% in 2008. Only new contracts with the [IOUs] for output from the units 20 MW or under would count toward the Joint Parties' proposed DER procurement requirement." (Joint Parties Closing Brief, pp. 11-12.)

The Joint Parties also state:

    ". . . this percentage could be implemented as a placeholder for the first year, while the utilities perform studies of the potential DER market, similar to those that have been performed regarding the energy efficiency market, and develop for Commission approval specific goals and costs for the DER component of long-term procurement plan.

    "In any year the applicable requirement is not met, a utility should have to demonstrate why this is the case, and how it place to make up for the any DER procurement shortfall in the following years. In addition, the requirement could be subject to revision up or down on an annual basis, depending on resource adequacy and market conditions. The need for a formal DER procurement directive beyond 2008 would be evaluated during a procurement proceeding or a procurement update proceeding scheduled for completion prior to 2008." (Joint Parties' Direct Testimony, pp. 16-17.)

In lieu of setting a mandated set-aside, the Joint Parties propose an alternative approach whereby the Commission would establish a "procurement goal" for distributed energy resources. The goal would be quantified as set forth above and the utilities would be required to explain if they failed to meet the objective. If the Commission determines that the utilities are not making "reasonable efforts" to meet the goal, the Commission would then elevate the goal to a directive.

We find that beyond including forecasted levels of customer-side distributed generation, the utilities' procurement plans do not contain explicit proposals or strategies for promoting distributed generation within their respective service territories as a supply-side procurement resource. In the long-term procurement plans, the utilities' treat distributed generation as a demand-side program, netting out the effects of distributed generation as part of the load forecasting process. While not foreclosing the potential of using distribution generation as a supply-side option in the future, the utilities indicate that such efforts should await the results of cost/benefit studies.

We agree with ORA's findings that it is difficult to compare and extrapolate the distributed generation forecasts from the utilities long-term procurement plans. The utilities' next round of 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. We recognize that distributed generation encompasses many types of applications and technologies and different parties embrace different definitions of this resource category. It's important that each utility clearly define the resources it includes in its forecast of distributed generation.

As described in D.03-02-068, the Commission plans to institute a new rulemaking on distributed generation that will, among other things, address the various cost/benefit and market issues mandated by AB 970, SBX1-28, and the Energy Action Plan. We will refer the Joint Parties' proposal to the future rulemaking. At this time, we will not predetermine the outcome of these issues in advance of the rulemaking, and therefore do not adopt the Joint Parties recommended approach for a set-aside.

5. Transmission

In D.02-10-062, we found that to the extent transmission can meet or offset procurement needs, utilities should explicitly include transmission in their resource plans. We also made clear in the EAP that it is critical for the state to ensure there is adequate transmission to support California's needs, stating:

"Reliable and reasonably priced electricity and natural gas, as well as increasing electricity from renewable resources, are dependent on a well-maintained and sufficient transmission and distribution system. The state will reinvigorate its planning, permitting, and funding processes to assure that necessary improvements and expansions to the distribution system and the bulk electricity grid are made on a timely basis."

Each utility in its long-term plan included the transmission upgrades for reliability that had been reviewed and approved through the ISO's annual grid study. They also included a general assessment of whether additional transmission is needed to support power imports for future needs, based on production cost computer modeling. In its plan, SCE cites the need for additional transmission capability to the Southwest for economic reasons, to access surplus capacity and energy, and references its intention to file for a Certificate of Public Convenience and Necessity (CPCN) for Devers PaloVerde 2 line.

ORA and the ISO testify that the utilities' plans are not sufficiently detailed to fully assess the deliverability of power that each utility, particularly PG&E, relies on to meet future needs. In particular, PG&E relies on "generic" resources within the western grid. In hearings, the ISO testified that it could work with the utilities to identify conceptual scenarios for these generic units, i.e. general geographic regions, add scenarios for distribution within the state, and then combine the three utilities to test whether or not these scenarios are compatible with the transmission system and transmission system plans.82 In its brief, the ISO states this would be the minimum deliverability requirement needed. SCE supports a deliverability showing for resources imported into the ISO control area, but does not support going so far as to assess local deliverability.

We establish here a minimum requirement that the IOUs work with the ISO on defining conceptual scenarios for assessing resources imported into the ISO control area and deliverable to the individual IOU's load, so that after the June 2004 plans are filed, the ISO can timely run combined scenarios, serve testimony, and fully participate in our hearing process. We look to further refine a standard of deliverability through the comments we request in our earlier resource adequacy section.83

In its testimony, the CEC states that the Commission's focus in D.02-10-062 was generation-focused and we must expand the record to include transmission and demand-side or customer-oriented alternatives. Further, the CEC states its IEPR process will establish the integrated planning process that we should use in this proceeding to determine the combination of demand-side or customer-oriented and infrastructure investments (including generation and transmission) that best meet California's short- and long-term needs.84 While we welcome the CEC participation and expertise in our proceeding, we do not support requiring the utilities to adopt the forecasts and resource plans of the IEPR. We strongly believe that the utilities themselves must be responsible and accountable for providing their customers reliable service and just at reasonable rates; this is the utilities' statutory obligation.

In guiding the utilities' long term planning process, we focus on developing an integrated resource approach, one that recognizes the loading order of preferred resources in the EAP, and that optimizes generation and transmission resources.

SDG&E presents this approach in its plan. It places emphasis on the first 5 to 10 years of the plan, since these are the years for which policy and implementation decisions need to be made in the near term, and allows for a level of short-term and medium term resources that provide sufficient flexibility. SDG&E explained its planning approach as follows:

First, determined the level of cost-effective energy efficiency available to SDG&E;

Second, demand response programs were added to meet a challenge of reducing peak demand 5% by 2007;

Third, renewable resources were added to ensure 20% of the energy SDG&E provides to its customers will come from renewable sources by 2017 or sooner; and

Fourth, developed and tested four distinctly different candidate resource portfolios that could fill any remaining supply gap.

While we conceptually agree with this model, more refinement is necessary in specifying the cost/benefit analysis that should be performed in each step and the level of specific project analysis to include. ORA finds that SDG&E's plan failed to incorporate all anticipated new generation, and its demand response programs were untested, thereby undermining the reliability of the planning assumptions. We agree with both of these points.

Save Southwest Riverside County (SSRC) testifies that the transmission component of SDG&E's preferred proposal is not supported by substantial evidence. Specifically, it cites SDG&E's inclusion of a "Near-term Interconnection Project" that would be constructed and available to serve load by the summer of 2008. SSRC cites to SDG&E's testimony on cross-examination that this is not the Valley-Rainbow line, and states that since licensing and construction of another major new transmission line would take five to six years, SDG&E's plan is risky, and perhaps infeasible. This is a valid criticism that SDG&E should address in its re-filed long-term plan.

The City of Chula Vista states that SDG&E's proposal shows that existing transmission systems will be fully utilized by 2005, and that additional transmission capacity must be added by 2008. The City is concerned that future transmission lines be given early and active coordination with affected local jurisdictions, to include specific notice and a public involvement process. The City would like the Commission to consider: (1) requiring the removal of old, surplus, above-ground lines when new ones are added; (2) tying in local power sources and renewables in evaluating sites; (3) upgrading line capacity for growth; and (4) the consideration of growth in siting new or replacement lines. We give the City assurance that before a new transmission line could be authorized, a separate CPCN process would be required. Our CPCN process provides full public notice to all affected communities, a detailed environmental assessment under CEQA standards, and a specific finding of economic need.

SCE requests that the Commission (1) avoid duplicating the transmission project need assessments performed by the ISO with the assessment performed by the Commission under its General Order 131-D CPCN provisions; and (2) refrain from conducting transmission project need assessments in this proceeding unless the results of those assessments can and will be adopted in the project's separate General Order 131-D CPCN proceeding. The Commission intends to open shortly a new rulemaking to address this issue. Our commitment under the EAP is:

"The Public Utilities Commission will issue an Order Instituting Rulemaking to propose changes to its Certificate of Public Convenience and Necessity process, required under Pub. Util. Code § 1001 et seq., in recognition of industry, marketplace, and legislative changes, like the creation of the CAISO and the directives of SB 1389. The Rulemaking will, among other things, propose to use the results of the Energy Commission's collaborative transmission assessment process to guide and fund IOU-sponsored transmission expansion or upgrade projects without having the PUC revisit questions of need for individual projects in certifying transmission improvements."

6. Fuel Diversity in Non-Renewables

The California Energy Commission (CEC) notes that there are concerns about California's increasing dependence on natural gas. The latest version of the 2003 Integrated Energy Policy Report (IEPR), states:

"With demand for natural gas increasing to meet the needs of a growing electricity generation market, concerns have emerged among state policy makers about California's increasing dependence on natural gas. These concerns have become even more pronounced with increased price volatility."85

CEC's recommendation is to mitigate the risk of relying heavily on natural gas by reducing demand for natural gas for power generation through greater reliance on renewable generation. The draft final report is less encouraging about substituting other non-renewable fuels for gas:

"Using other fuels can also reduce the demand for natural gas facilities. For a host of legal, environmental, and cost reasons, nuclear, large hydroelectric, residual fuel oil, and coal facilities are unlikely candidates for offsetting natural gas-fired generation for California. On the other hand, the development of cost-effective renewable resources (wind, geothermal, biomass, and solar) have [sic] tremendous potential in California to meet part of our future demand."86

It is clear that the CEC does not see the use of alternative fuels, except for renewable sources, as a long-term source of diversity in generation sources in California.

SDG&E proposed a Balanced Portfolio as part of its long-term plan. The plan posits increased transmission capability, additional on-system generation both prior to and after the transmission addition, and off-system resources including the fuel diversity represented by a coal-fueled resource. SDG&E's Robert Resley's testimony notes that its ability to add fuel diverse resources is constrained by the nature of its service territory, public policy, and possible limited availability of non-fossil resources.87 SDG&E recognizes that the advantage of diversity, a significant reduction in potential price volatility by reduced dependence on gas prices, would be counterbalanced by additional emissions.

The long-term plans of the other utilities, PG&E and SCE, do not mention fuel diversity by name, and do not include non-gas power plants in their future plans.

California is an environmentally sensitive state both by its geography and by its politics and sensitivities. Conventional power plants are difficult to site here. Even those fired by the cleanest technologies and fuels - at this time, that means natural gas - are not generally welcomed here. The most recent data show that electric generation in California from coal, petroleum, and other gases besides natural gas accounts for only three-percent of total generation in the state, compared to about 56 percent for natural gas.88 SCE is in the midst of a proceeding before us, A.02-05-046, on the future disposition of the Mohave power plant, which is the largest single coal-fired source for any of the utilities.

SDG&E is correct in arguing that a balanced portfolio that includes a coal-fired resource would require new transmission, for it is very unlikely that a coal-fired plant ever could be built within its service area.

Fuel diversity is not only a matter of choices of different fuels. The principal advantage we are looking for, reduced likelihood of shortages and price spikes, can be achieved through greater reliance on additional sources of fuel, including natural gas itself. It is possible that the addition of at least one Liquefied Natural Gas (LNG) port capable of serving gas to Californians, including California's electric power plants, can provide at least some of the benefit we are searching for in fuel diversity. Only in this case, it would not be diversity of the fuel types, but of the fuel sources.

7. QFs

Currently, there are about 600 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 (see Table QF-3, Load Served by QFs below). QFs have been reliably providing power for over 20 years, under standard offer and fixed-priced contracts, and under some non-standard offer contracts, approved by this Commission. As we discussed in our Interim Opinion, QF power does provide many benefits to California:

"As a general proposition, we find that QF power provides significant benefits to the state, in the form of more efficient industrial processes, as well as electric power. QFs have continued to provide power to the state during difficult circumstances during the past several years. A consequence of not making provisions for continuing QF contracts would be more QF power going off-line, creating additional net short that the utilities would need to procure during the interim period." (D.02-08-071, p. 31.)

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. By 1995, FERC noted that the QF industry had matured considerably:

"The QF industry is now a developed industry and the need for integration of policy objectives under PURPA and other federal electric regulatory policies is pronounced. This is particularly the case given the fact that the electric utility industry is in the midst of a transition to a competitive wholesale power market, and some States, including California, are considering direct access for retail customers."89

Although this determination was made eight years ago, the challenge of correctly implementing PURPA for a developed QF industry, which now co-exists with increasingly developed wholesale power markets, does present a considerable challenge. We must strike the proper balance between certain policy preferences and a myriad of legal requirements.

This industry is so mature, in fact, that QF power contracts are actually set to expire at a significant rate over the next five to seven years. By 2008, expired QF contract capacity is expected to exceed 1,000 MW and approach 1,800 MW by 2010. SCE is projected to lose the most QF capacity during this time period.

Table QF-1, Expiring QF Contract Capacity

 

2005

2006

2007

2008

2009

2010

PG&E QFs

0%

1%

6%

8%

19%

23%

SCE QFs

1%

11%

11%

31%

38%

43%

SDG&E QFs

0%

0%

0%

0%

0%

0%

Combined QFs

1%

6%

8%

19%

28%

32%

             

a) Parties' Positions

    Utility Recommendations

PG&E, SCE, and SDG&E have proposed to not automatically renew expired QF contracts, but differ in their willingness to do so. SDG&E is the most willing of the three and does assume that its QF power deliveries will remain relatively constant throughout the forecast period, and that expired QF contracts will be renewed under certain conditions. However, all three utilities agree that the Commission should reexamine SRAC pricing to ensure that utility avoided cost more accurately reflects the cost of their replacement power alternatives. SDG&E is amenable to renewing expired QF contracts through the use of Standard Offer 1 (SO1) contracts that would be renewed annually based on need. SDG&E is opposed to the use of QF-only auctions.

PG&E occupies the middle-ground on QF issues with its proposal to offer one-year SO1 contracts with modifications pertaining to: (1) the provision of 1,000 discretionary curtailment hours, both financial and physical curtailment, (Tr.5744, lines 2-9), although the detailed protocols on specific curtailment frequency, duration, and notice provisions were not specifically set forth; (2) providing for an option to terminate a contract once the seller enters into a winning RPS bid; (3) revisiting SRAC methodologies, and (4) the opportunity for QFs to participate in any upcoming power solicitations.

SCE stands alone at the other end of the spectrum with its solicitation-only proposal. SCE contends that its PURPA obligations will be fully satisfied simply by affording QFs the opportunity to participate in upcoming solicitations for renewable and/or non-renewable contracts. SCE puts forth that California and other states have considerable discretion in implementing PURPA's mandatory purchase requirement, and that the demise of the California Power Exchange ("PX") has not altered the basic proposition that PURPA may be properly implemented by providing QFs with the opportunity to participate in a competitive procurement process. SCE further notes that revival of mandated SO1 contracts would impose must-take obligations on the IOUs in all hours, including many hours when the true costs avoided by the QF purchases approach zero and may even be negative.

Several parties have weighed in on QF issues on some detail: CCC, CAC-EPUC, and ORA.

    CCC Recommendations

CCC recommends that QFs should be allowed to preferably enter into 10-year SO1 contracts, or alternatively, short-term annual SO1 contracts; (2) bid to provide long-term procurement products to the IOUs (such as firm capacity products), while (3) retaining their right to sell energy at SRAC prices to the IOUs in other hours. CCC contends that its long-term procurement proposal (for cogenerators) would provide benefits to both ratepayers and QFs, including conservation, energy efficiency, additional supply, and market-based pricing under SRAC.

CCC also proposes a way to mitigate impacts of excess base load power through the expanded use of bid curtailment programs. IOUs could utilize such programs to economically back-down QF power. CCC states that these programs encourage QFs with operational flexibility to reduce their output during hours when the utility has too much must-take power. The purchasing utility provides each of its QFs with the opportunity to bid a price for megawatt-hours of production that each QF can curtail. The IOU can accept those bids that offer ratepayer benefits.

CCC also notes that SRAC TOU (time of use) factors could be revised to more accurately encourage QFs to deliver power when it is needed. CCC states that the vast majority of QF power is either under non-standard contract or is on 5-year, fixed price contracts at 5.37/kWh until mid-2006. Thus, modifications to SRAC pricing would have no appreciable effect until after mid-2006. (CCC Direct Testimony, 06-23-2003, p.5, line 20).

CCC observes that PURPA is still law, that it has not been repealed, and that the statute still requires "IOUs to purchase power from QFs at prices based on the IOUs' full avoided costs" (CCC Direct Testimony, 06-23-2003, p.10, line 26). CCC notes that D.02-08-071 required the IOUs to offer SO1 contracts during the interim procurement period (p.12, line 4). CCC contends that a long-term SO1 contract "will allow the IOU to meet its PURPA purchase mandate..." (p. 4, line 40.)

CCC states that QF capacity will decline sharply after 2005, as a result of the termination of the large cohort of QF contracts with 20-year terms for projects that began operations from 1985 to 1990." (CCC Direct Testimony, p. 7, lines 18-21). CCC contends that more capacity needed by 2008, even though CEC 'incorrectly' assumes constant QF power:

    "The CEC forecast appears to assume that present levels of QF generation are maintained. Even assuming QF resources are retained, the CEC forecast suggests that, on a statewide basis, another 2,000 to 5,000 MWs of peak capacity will be needed by 2008, simply in order to maintain reserve margins in the range of 15% to 20%." (CCC Direct Testimony, p. 8, line 8.)

CCC contends that QFs can supply additional power in 2004 and beyond:

    "Cogeneration projects that could supply additional power to the IOUs in 2004 are, for the most part, already built and have operated successfully for many years. Most are located in the state's load centers, improve the reliability of the state's electric grid, and avoid the need for the California Independent System Operator (ISO) to contract for reliability must-run (RMR) generation." (CCC Direct Testimony, p. 3, line 3.)

CCC notes that the IOUs can readily hedge their exposure to high SRAC prices through the use of financial hedge products. SCE hedged its QF price risk in 2002 and 2003 and has obtained authority to hedge in the first half of 2004. PG&E and SDG&E also have such hedging authority. (CCC Direct Testimony, p.10, line 34). CCC states that QFs avoided the construction of additional central station coal and nuclear power plants, such as the Diablo Canyon and SONGS plants that were built in the 1980s. CCC also notes that there are conservation and efficiency benefits associated with cogeneration -- the dual production of two useful forms of energy from a single fuel source. (Direct Testimony, p. 2, line 22.).

CCC also encourages the Commission to reject PG&E's proposal to incorporate 1,000 hours of annual curtailment into SO1 contracts. CCC contends that PG&E has not shown that the utility's avoided costs are negative in this many hours, nor has the utility provided details on how it would administer such curtailments. CCC states that this issue would be best considered during a comprehensive review of SRAC pricing issues. Finally, CCC notes that QFs are still ready, willing, and able to sell power to below investment-grade utilities.

    "Most, if not all, of the cogeneration projects that could provide additional power to the IOUs in 2004 are already built and have operated reliably for many years under standard offer QF contracts. The IOUs have many years of performance data for such projects. These are resources that are ready, willing, and able to supply power to California. QFs continue to be willing to sell to PG&E and Edison despite the fact that the credit of these IOUs remains below investment-grade." (CCC Direct Testimony, p. 27.)

    CAC/EPUC Positions

On QF issues, CAC/EPUC contends that (1) the IOU power solicitation proposals do not solely satisfy utility PURPA purchase obligation requirements, and (2) changed circumstances do not preclude QF cost recovery, thus existing QF contracts must be upheld. CAC/EPUC cites Cogen Lyondell, Inc., et al., 95 FERC 61,243 (2001) in support of its first contention on PURPA purchase obligation requirements: "The opportunity to participate in a solicitation process is a far lesser right than that expressed in the FERC rules and may not be sufficient to encourage QF cogeneration as prescribed by Federal law" (CAC/EPUC Direct Testimony, 06-23-2003, p.5, line 6). With regard to existing QF contracts, CAC/EPUC notes that New York State Electric & Gas Corp., 71 FERC 61,027 (1995) upholds existing QF contracts even under changed circumstances. Both of these FERC orders are discussed in more detail below.

During cross-examination of PG&E's QF witness (Pappas), CAC/EPUC counsel noted that existing State of California policy, as set forth in Pub. Util. Code § 372(f), also encourages the continued development, installation, and interconnection of clean and efficient self-generation and cogeneration resources (Tr. 5694, lines.20-28), in addition to the federal PURPA statute. Pub. Util. Code § 372(f) is as follows:

    "372 (f) To encourage the continued development, installation, and interconnection of clean and efficient self-generation and cogeneration resources, to improve system reliability for consumers by retaining existing generation and encouraging new generation to connect to the electric grid, and to increase self-sufficiency of consumers of electricity through the deployment of self-generation and cogeneration, both of the following shall occur:

Although ORA does not appear to oppose PG&E's power solicitation and SO1 contract proposals, ORA does state that these seem to be "inconsistent with the Commission's intent for a limited revival of SO1 contracts" (ORA Direct, p.80). Regarding PG&E's 1,000-hour discretionary curtailment proposal, ORA's direct testimony at page 79 did not reflect a full understanding of PG&E's proposal, as evidenced during hearings (Tr.5883, through 5886). Under cross- examination by CCC, ORA did express concern over the possibility that "PG&E's exercise of the [1,000 hour] curtailment right [might have] the effect of shutting down [some] QF operations" (Tr.5886, ln.17-20). ORA is not opposed to PG&E's proposal to revamp SRAC pricing methodologies, but ORA notes that no specific details were provided.

ORA's position on SCE's position that, "its PURPA obligations will be fully satisfied by affording QFs the opportunity to participate in upcoming solicitations for renewable and/or non-renewable contracts," is ambiguous:

    "If, as SCE represents, additional SO1 contracts will not be a good fit to SCE's primary need, then so be it. SCE should not force itself to enter into this type of contract beyond those already required in existing Commission orders. SCE has indicated several planned new contracts during the plan period through 2012. But SCE should describe in more explicit terms the solicitation opportunities it plans to make available to QFs and all other bidders in both renewables and non-renewables." (ORA, Direct Testimony, p. 82.)

As a policy matter, ORA states that SCE should be more explicit in identifying specific opportunities for QFs to bid in future SCE solicitations.

b) Discussion

The spectrum of QF issues is defined on the one end by an absolute, mandatory PURPA purchase obligation regardless of utility need (as advanced by CCC), and on the other end by a solicitation-only opportunity for QFs to bid on yet-to-be-defined power products at future yet-to-be-specified dates. We are not only faced with a range of policy choices but also with complex legal requirements set forth in federal and state law.

    (1) The PURPA Purchase Obligation Requirement

In our Interim Opinion in this rulemaking, D.02-08-071, we discussed the applicable federal and state mandates associated with PURPA, along with our interim approach on QF issues. In that decision, we stated that, "[a]lthough the requirements of PURPA give us considerable discretion and do not obligate us to continue SO1 contracts [until long-term procurement plans have been adopted], we nonetheless must comply with PURPA." With regard to QFs, the issue of the obligation to purchase QF power according to the requirements set forth under PURPA is at issue in this rulemaking. In 105 FERC 61,004 (Para. 20), FERC clearly summarized the PURPA purchase obligation requirement, along with some associated provisions:

      "[FERC] implemented the purchase obligation set forth in PURPA in Section 292.303 of its regulations, 18 C.F.R. § 292.303(a) (2003), which provides: Each electric utility shall purchase, in accordance with § 292.304, any energy and capacity which is made available from a qualifying facility . . . . Section 292.304, in turn, requires that rates for purchases shall: (1) be just and reasonable to the electric customer of the electric utility and in the public interest; and (2) not discriminate against qualifying cogeneration and small power production facilities. 18 C.F.R. § 292.304(a)(1) (2003). The regulation further provides that nothing in the regulation requires any electric utility to pay more than the avoided costs for purchases. 18 C.F.R. § 292.304(a)(2) (2003)." (Emphasis added.)

      "`Avoided costs' is defined as `the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.'" 18 C.F.R. § 292.101(b)(6) (2003)

The QF parties in this rulemaking have generally portrayed the PURPA purchase obligation requirement as rather absolute.90 However, the PURPA purchase obligation is neither as broad or as absolute as the QF parties assert. The QF parties do acknowledge that the PURPA purchase obligation is subject to specific curtailment provisions in 18 C.F.R. Section 292.304(f).91 Additionally, the waiver provision in 18 C.F.R. 292.402 provides further flexibility to states in their implementation of the PURPA purchase obligation. Specifically, section 292.402 provides for a waiver of Subpart C of Part 292. Subpart C is titled as, and sets forth, "Arrangements Between Electric Utilities and Qualifying Cogeneration and Small Power Production Facilities Under Section 210 of the Public Utility Regulatory Policies Act of 1978." The waiver allowed for under section 292.402 applies to sections 292.301 through 292.308, excluding section 292.302, but including section 292.303, which is the particular section that sets forth the obligation of electric utilities to purchase QF power. Section 292.402 reads as follows:

      "(a) State regulatory authority and non-regulated electric utility waivers. Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or non-regulated electric utility may, after public notice in the area served by the electric utility, apply for waiver from the application of any of the requirements of subpart C (other than 292.302 thereof).

      "(b) Commission action. The Commission will grant such a waiver only if an applicant under paragraph (a) of this section demonstrates that compliance with any of the requirements of subpart C is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA."

It is clear from this language in FERC's regulations that states, through their utility regulatory commissions or individual utilities, have the authority to request FERC authorization to waive the applicability of the PURPA purchase obligation under certain conditions.92 During the course of these proceedings, a number of QF parties have raised the issue of the scope of this waiver authorization, citing a FERC decision, Cogen Lyondell, Inc., et al., 95 FERC 61,243 (2001), as a definitive refutation of PG&E's and SCE's power solicitation proposals, which the utilities claim will satisfy their PURPA purchase obligation requirements.

Although, the QF parties claim that PG&E's and SCE's power solicitation proposals are inconsistent with the requirements of PURPA and its implementing regulations, the QF parties' reliance on the Cogen Lyondell order for such a proposition is misplaced. At issue in the Cogen Lyondell case is the Texas PUC's request for a waiver, under 18 C.F.R. 292.402, of the PURPA purchase obligation set forth in 18 C.F.R. 292.303. In that order, FERC stated that "the Texas Commission's proposal amounts to an opportunity for QFs to make sales, which is inferior to having an electric utility-purchaser with a mandatory purchase obligation under PURPA" (pages 6-7). Notwithstanding this determination, FERC noted that: (1) the purchase obligation could be waived in some circumstances; (2) FERC has, in fact, granted waiver of the purchase obligation in certain limited circumstances; and (3) in the Cogen Lyondell case, FERC stated that "the Texas Commission has offered no specific showing [for a waiver], relying instead on broad competitive assertions." The relevant language to this effect is stated in the Cogen Lyondell order, as follows:

      "The Commission recognized, when it promulgated its regulations implementing PURPA, that the purchase obligation could be waived in some situations. See Small Power Production and Cogeneration Facilities: Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, Order No. 69, FERC Stats. & Regs. Regulations Preambles 1977-1981 30,128 at 30,871, 30,894 (1980), order on reh'g, Order No. 69-A, FERC Stats. & Regs. Regulations Preambles 1977-1981 30,160 (1980), aff'd in part and vacated in part, American Electric Power Services Corporation v. FERC, 675 F.2d 1226 (D.C. Cir 1982), rev'd in part, American Paper Institute, Inc. v. American Electric Power Service Corporation, 461 U.S. 402 (1983)."

      "The Commission has in the past granted waiver in certain limited circumstances. See City of Ketchikan, Alaska, 94 FERC 61,293 (2001) (Ketchikan ); Seminole Electric Cooperative, Inc., 39 FERC 61,354 (1987); Oglethorpe Power Corporation, 32 FERC 61,103 (1985), reh'g denied, 35 FERC 61,069 (1986), aff'd Greensboro Lumber Company, 825 F.2d 518 (D.C. Cir. 1987). In the recent Ketchikan order, for example, the Commission granted waiver of the purchase obligation based on a showing that QF capacity was not needed and would merely displace sales of capacity from other resources. Here, the Texas Commission has offered no such specific showing, relying instead on broad competitive assertions." Cogen Lyondell, Inc., et al., 95 FERC 61,243 (2001), footnote 3 (emphasis added).

With regard to the extreme breadth of the Texas Commission's request, FERC stated:

      "We will deny the Texas Commission's request for waiver. As an initial matter, what the Texas Commission requests is essentially a complete waiver of the PURPA purchase obligation for all Texas utilities. On this record, we cannot grant such a waiver." Cogen Lyondell, Inc., et al., 95 FERC 61,243 (2001), page 4 (emphasis added).

Thus, FERC's Cogen Lyondell order does not stand for the broad proposition that the QF parties in this proceeding have cited it for. Rather, this order addresses an extremely broad request for waiver that was supported by nothing more than generalized assertions, and is in no way dispositive of the complex and nuanced issues relating to the future procurement of QF power in California that are under review in this proceeding. In contrast to what FERC was addressing in the Cogen Lyondell order, the PG&E and SCE power solicitation proposals that were put forward in this proceeding are being reviewed in the context of a very detailed, factually intensive record addressing both short- and long-term policy issues and procurement plans for California's three largest investor-owned electric utilities.

The Cogen Lyondell order can be distinguished from the circumstances we are dealing with here in a number of other key respects. First the Texas PUC request in that case was for the removal of the PURPA purchase obligation for all of its QFs, both existing QFs and future QFs. In contrast, in this case, PG&E and SCE would continue to honor existing QF contracts. Second, the underpinnings of the Texas PUC request were very general competitive assertions, whereas in this case, PG&E and SCE have put forward very specific concerns about their QF contracts and PURPA purchase obligations. The two utilities have noted that as a result of DWR contract allocations, they have had excess power in a range of hours, a condition that may persist for some years. The two utilities also note that this excess power situation will be alleviated over the next few years as a significant number of QF contracts expire. However, the QF parties have expressed a definite interest either in entering into new contracts that could be renewable on an annual basis or on longer terms, given that there is still remaining useful life in many of these facilities.

As a counterpoint to the Cogen Lyondell case, both PG&E and SCE cite City of Ketchikan, 94 FERC 61,293 (March 15, 2001). In that order, FERC granted a limited waiver of the PURPA purchase obligation because a proposed QF contract would, in fact, displace existing utility resources and result in additional unneeded power. PG&E describes the order in its September 22, 2003 reply brief:

      "In Ketchikan, a self-certified QF who had not yet constructed a new facility attempted to displace energy the City utility was already under contract to purchase by requiring it to purchase from its proposed QF. The City sought and was granted a waiver of any PURPA requirement to take power from the new QF. FERC approved the waiver because "there is no obligation under PURPA for a utility to pay for capacity that would displace existing capacity arrangements." (Id. at p. 62,061.) Because capacity from the new project was not needed, FERC held that its acquisition did not avoid "building or buying future capacity." (Id. at p. 62,062.) FERC also held "compliance with the utility purchase obligation, by means of a purchase that would displace power from the Four Dams Pool Initial Project, is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA." (Id. at p. 62,061.) In support of its ruling, FERC also cited a long-standing Order No. 69, FERC Stats. & Rags. Preambles 1977-1981 ¶ 30,128 at p. 30,870, which provides that a qualifying facility should only be required to be paid for "energy or capacity the utility can use to meet its system load." (Emphasis added.)

The PURPA purchase obligation does not lawfully exist apart from the determination of the need for such power by the host utility. FERC's Ketchikan order, provides abundant support for this proposition, both in project-specific terms and much more broadly as a gloss on the basic requirements of PURPA:

      "...we find that compliance with the utility purchase obligation, by means of a purchase that would displace power from the Four Dam Pool Initial Project, is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA. We make this finding because, as we have stated previously, there is no obligation under PURPA for a utility to pay for capacity that would displace its existing capacity arrangements. Moreover, there is no obligation under PURPA for a utility to enter contracts to make purchases which would result in rates which are not `just and reasonable to electric consumers of the electric utility and in the public interest' or which exceed `the incremental cost to the electric utility of alternative electric energy.'" 16 U.S.C. § 824a-3(b) (1994). (footnotes omitted, emphasis added) City of Ketchikan, 94 FERC 61,293 (March 15, 2001), pages 15-16.

Thus, as FERC itself has recognized, we must 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. In this regard, we note that this Commission has suspended QF standard offer contracts at various times to prevent over-subscription93 because additional power would have resulted in negative avoided cost and/or displaced existing cost-effective utility resources.

In light of the foregoing legal and policy considerations, it is now appropriate to consider our options with regard to several distinct groups of QFs: (1) Existing QFs with existing utility contracts, (2) Existing QFs with expired, or soon-to-be expired, utility contracts, and (3) New QFs with possible future utility contracts.

    (2) Existing QFs With Existing Utility Contracts

None of the three utility proposals on QF issues would affect or impair existing QF contracts. This is, of course, in stark contrast to the Cogen Lyondell case wherein the Texas PUC sought a complete waiver of the PURPA purchase obligation for all its QFs, both existing and new. We will continue to uphold existing QF contracts.

    (3) Existing QFs With Expired, or Soon-to-be Expired, Utility Contracts

On the issue of whether to renew existing QFs with expired, or soon-to-be expired, utility contracts, the three utility proposals, already discussed in some detail, do differ from one another.

Of the three proposals, SCE argues in the extreme that renewal of existing QF contracts is not necessary and that QFs can instead compete in any upcoming power solicitation proposals that maybe offered in the future. Under SCE's paradigm, determinations of need might be made from time-to-time as the utility issues RFOs for power under certain quantity, quality, and duration parameters; in addition, instead of plainly stating its need in the form of an exact quantity, the utility might be expected to simply specify acceptable bidding units of, for example, anywhere from one megawatt to 25 MW, or more in order to avoid revealing its exact net short position.

The SCE proposal appears to us to be inconsistent with a long-term, integrated resource planning process. SCE's "solicitation-only" opportunity for existing QFs to renew existing contracts that are expiring may technically comply with PURPA, but it does not fit well within the context of a long-term planning process of the type that is at the heart of this procurement proceeding. In this proceeding, we are reviewing proposed 20-year plans. By 2008, SCE will have a need for baseload power, which results, at least in part, from the expiration of QF contracts. Although the need for baseload power does diminish in the near-term, due in large part to the existence of the DWR contracts, we note that there is a need for power that materializes as existing QF contracts expire. Renewal of existing QF contracts should accordingly 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.

The IOUs have proposed to comply, in whole or in part, with their PURPA purchase obligations by allowing QFs, including existing QFs with expiring contracts, the opportunity to participate in power solicitations. A competitive all-resource bidding process is an optimal means for an IOU to determine what resources can best meet its need for additional capacity. Ideally, QF participation in such solicitations is the best way for the IOUs to match their need for new capacity with the range of potentially available resources, including QFs. However, we do not believe that such participation should be mandatory for existing QFs seeking to renew their contracts.

In light of the continuing need for most of the power that QFs currently provide, we do not think that IOUs proposal is, in and of itself, sufficient. We accordingly encourage the IOUs to renegotiate contracts with existing QFs independently of their planned power solicitation processes. To the extent that a given IOU individually, or all three of the major electric IOUs collectively, seeks to propose a new or revised standard offer contract to be used in entering into such renewed contracts, we encourage them to do so and to apply to the Commission for approval of such new or revised contracts.

Although we are not requiring existing QFs seeking to renew their contracts to do so via the competitive solicitation process, it is foreseeable that there will be problems if a given existing QF seeking to renew its contract proposes to do so on terms that are inconsistent with the IOU's then current and future needs for power. A given utility may have imminent needs for peak and intermediate (load-following) power, but no need for baseload power. In such cases, there would be no legal obligation under PURPA for a utility to enter into a renewed contract with a QF that offers only must-take baseload power 24 hours per day, seven days per week. To require the utility to enter into such a contract would not provide reasonable value either to the utility or to its ratepayers and would unduly subsidize the QF at the expense of ratepayers. A subsidy with no commensurate value is not a prudent expenditure of ratepayer funds. On the other hand, an existing QF with an expiring or expired contract proposing to provide power in a manner that does track the utility's actual needs would, under PURPA, be entitled to an agreement to provide the energy and capacity needed by the utility.

By definition, the PURPA purchase obligation originates out of a utility's need for power, either the need for energy or the need for capacity. Without need, there is no avoided cost because without a need for power the utility would not have the obligation to either generate or purchase any incremental amount of energy or capacity to serve load. The key to resolving this problem is through a revision to the methodology used to determine the prices that existing QFs seeking to renew their QF contracts are actually paid for the power they provide. It is entirely possible that a revision to this methodology will result in a scenario under which a given existing QF, which must generate power 24 hours per day, 7 days per week will be required to pay the IOU to take that power during certain off-peak periods, when the IOU's short-run avoided cost (SRAC) for that power is negative. Of course, an existing QF seeking to renew a QF contract could avoid such a result by agreeing in the renewed contract not to require the IOU to take (or pay for) power it does need when it does not need it. Accordingly, 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.

Given the importance of the need to match an IOU's actual power needs with the nature of the resource being offered by certain QFs, there is one important element of the IOUs' competitive bidding processes that is highly relevant to the terms of future renewed contracts for existing QFs, namely, the use of such bidding processes to establish the value of the capacity provided by QFs. 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. Accordingly, the results of the competitive all-source bidding processes that the IOUs have already undertaken, or will shortly undertake, will greatly assist in updating the value of the capacity component of the total short-run avoided cost (SRAC) that QFs are entitled to be paid pursuant to PURPA and state law. As will be discussed in more detail below, it is important that the current methodologies to establish SRAC be modified.

We understand that most of the existing QF contracts will not expire before the end of 2005, and we expect that our review of the SRAC methodology will be completed well in advance of that date. However, there will be some QF contracts that expire prior to the completion of that review. Since the resolution of the key questions relating to how QFs will be paid on a going-forward basis must await the completion of our review of the SRAC methodology, we should continue to provide interim treatment, as we did in Decision D.02-08-071, for QF contracts expiring prior to the completion of that SRAC review for which the QF and the utility do not reach agreement on the terms of a new long-term QF contract. Accordingly, the utilities shall continue to purchase power until December 31, 2005 from any QF pursuant to an SO1 contract under the following conditions:

The pricing terms for any such contract should be consistent with existing Commission SRAC policy established in D.01-03-067, as modified by D.02-02-028; provided, however, to the extent that the Commission adopts a revised SRAC policy at any time prior to December 31, 2005, the pricing terms of the contract shall be modified to reflect said revised SRAC policy as of the effective date of the Commission decision adopting a revised SRAC policy.

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.

    (4) New QFs With Possible Future Utility Contracts

With regard to new QFs with possible future utility contracts, we believe that the PURPA purchase obligation is clearly subject to a determination that such QF power is, in fact, needed. As FERC stated in Ketchikan, "...we find that compliance with the utility purchase obligation, by means of a purchase that would displace power ... is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA. We make this finding because, as we have stated previously, there is no obligation under PURPA for a utility to pay for capacity that would displace its existing capacity arrangements."

We accordingly find that in connection with all systematic procurement activities starting in 2005, each of the utilities shall examine its need for additional QF power from new facilities. In a given procurement cycle, a utility may have imminent needs for peak and intermediate (load-following) power, but no need for baseload power. In such cases, there would be no obligation under PURPA for a utility to enter into a contract with a new QF that offers only must-take baseload power 24 hours per day, seven days per week. To require the utility to enter into such a contract would not provide reasonable value either to the utility or to its ratepayers and would unduly subsidize the QF at the expense of ratepayers. On the other hand, a new QF proposing to provide power in a manner that does track the utility's actual needs would, under PURPA, be entitled to an agreement to provide the energy and capacity actually needed by the utility.

Thus, as to new QFs, we conclude that a utility must make a determination of need prior to offering a contract to a new QF. Such determinations can be made as part of a utility's normal procurement cycle, but, so long as PURPA remains operative law, a new QF that offers to meet a utility's actual, demonstrated power needs at avoided costs prices would be entitled to a contract.

    (5) PG&E's Proposed 1,000 Hours Curtailment Proposal

PG&E has proposed to offer SO1 contracts to QFs whose contracts have expired, provided the contract is mutually agreeable with possible annual renewal. As part of that contract proposal, PG&E included an updated curtailment provision, which would allow the utility, at its discretion, to physically and financially curtail such QF contracts up to 1,000 hours annually. PG&E contends that its proposal should be adopted for several reasons: (1) baseload power is not needed until after 2008, (2) allocated DWR contracts result in more energy than PG&E can use in many hours during the year, and (3) the 1,000 curtailment hours provision was previously approved by the Commission in connection with the Interim Standard Offer No. 4 Curtailment Option B. PG&E further contends that its 1,000-hour curtailment proposal is very reasonable and is perhaps overly generous, given that PG&E does not need additional generation during the next several years. (PG&E Post-Hearing Brief, September 15, 2003, pp. 85-87).

We are unpersuaded by PG&E's arguments on this issue. PG&E's 1,000-hour curtailment proposal is not the result of any detailed avoided cost calculations based upon an approved avoided cost methodology or concept. However, modifications to SRAC, which are discussed just below, should address PG&E's concerns, and will provide a more reasoned basis for the type of SRAC payment adjustments that PG&E's proposed contract provision seeks to effectuate.

    (6) Revision of SRAC Prices

As mentioned already, all three utilities contend that revision of the current SRAC methodologies for determining QF energy and capacity payments is needed. For many years now, SRAC has been approximated through time-differentiated energy prices (set once a month) and time-differentiated capacity prices (set annually). However, there is substantial evidence on the record in this proceeding that indicates that the current SRAC energy pricing methodology has yielded prices in excess of spot market prices for significant periods of time.

The Commission has established SRAC methodologies used to calculate avoided cost energy and capacity payments for QF power. Per the requirements of Pub. Util. Code § 390, SRAC energy prices are tied to natural gas spot border prices, which have not necessarily reflected the more diverse utility portfolio that should be reflected in utility avoided cost. The result of the current SRAC pricing system has been that utilities have paid too much for QF power in certain time periods relative to market prices. More specifically, based on current SRAC time of use (TOU) factors, utilities have paid too much for QF power at certain times of day.

Because of this pricing problem, the Commission has also authorized utilities to purchase financial derivative products to hedge the QF price risk created, in part, by the approved SRAC methodology, which has been greatly affected by the volatility in the natural gas market over the past several years. In fact, the utilities have expended considerable sums of money hedging QF price risk resulting from this spot market-based (and in part Legislatively-mandated) avoided cost pricing formula. The amount of this hedging activity demonstrates that the current avoided cost pricing formula has not reflected utility avoided cost either as accurately as we had hoped or as precisely as we would like to see in the future.

Accordingly, in our view, there is a pressing need for a modified SRAC pricing system, which will accurately and fairly set utility avoided cost prices both under current and expected future market conditions and with an eye to the diversity of a given utility's actual resource portfolio.

Section 390 is now something of an artifact of the AB 1890 electric restructuring landscape, for the reason that Section 390 can never be fully implemented in accordance with the provisions set forth in Section 390(c) due to the demise of the Power Exchange (PX).

As the foregoing discussion demonstrates, the SRAC energy pricing formula is now out-of-date and inequitable. However, the capacity pricing component of the SRAC formula is also problematic, because the QFs receive capacity payments in addition to energy payments. With SRAC energy prices that are now frequently above market prices, the additional capacity payments that QFs receive merely compounds the inequity to the utilities and their ratepayers of the current SRAC pricing formula.

The Commission should carefully consider how to modify the SRAC methodology and whether to seek legislative changes to Section 390. We have a two-year window until most existing QF contracts begin to expire, and we should craft a remedy in the new OIR that better matches QF contracts with the actual needs and economic alternatives of the IOUs.

C. Risk Management

In the legislative intent section of AB 57, Section 1(d), the Legislature:

"Directs the Public Utilities Commission to assure that each electrical corporation optimizes the value of its overall supply portfolio, including Department of Water Resources contracts and procurement pursuant to Section 454.5 of the Public Utilities Code, for the benefit of its bundled service customers."

In implementing Pub. Util. Code § 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. (Sections 454.5(b)(1), 454.5(d)(4), and 454.5(d)(5).)

The manner in which each utility identifies and manages price risk in and optimizes the value of its overall supply portfolio for the benefit of its bundled service customers is the risk management function. The Commission has four primary oversight responsibilities in risk management: (1) specify the level of consumer risk tolerance that the utilities should use in managing their procurement portfolios; (2) make sure each IOU has tools in place to measure ratepayer risk exposure; (3) review and adopt utility procurement plans; and (4) adopt and administer a procurement incentive mechanism for each utility. We address here consumer risk tolerance and incentive mechanisms.

1. Consumer Risk Tolerance (CRT)

In D.02-10-062, we defined consumer risk tolerance (CRT) as "the price that an average consumer would be willing to pay to reduce the risk of higher prices in the future (i.e., the cost-to-risk tradeoff), discuss its importance is setting the limits of potential price risk under which each utility should manage its procurement portfolio, direct the Energy Division to retain a consultant to gather additional information regarding appropriate CRT levels, and requested parties to propose an interim CRT.

In D.02-12-074, we adopted an interim CRT level and notification protocol based on modifications to proposals advanced by ORA and TURN. While PG&E and SDG&E filed CRT proposals in their modified 2003 plans, SCE did not. SCE's interpretation of the CRT protocol that was outlined in Confidential Appendix C to D.02-12-074 led it to later file a petition to modify D.02-12-074, which we addressed in D.03-06-076.94

At present, each utility implements the CRT slightly differently. PG&E is the only utility to publicly discuss the specifics:

"PG&E currently manages the electric portfolio recognizing a consumer risk tolerance of one-cent per kWh, assumed to apply to a potential rate increase of one-cent per kWh over a one-year period. This translates to a risk tolerance level of about (confidential number). PG&E's approved 2003 Procurement Plan also established a notification limit to the Commission when portfolio exposure reached 125 percent of this risk tolerance." (Exhibit 26, p. 3-2.)

As a result of budget uncertainties, the consultant study authorized under Section 454.5(f) has been delayed. Energy Division plans to consult with each utility in the first quarter of 2004 and then prepare a draft scope of work for comment by all parties. A final consultant's report should be served on all parties for comment and the consultant be available as a witness if requested by the Commission.

For 2004, the utilities should continue to use the interim CRT.

2. Incentive Mechanism

In D.02-10-062, the Commission recognized the importance of developing an incentive mechanism and directed SDG&E, the only utility to support development of an procurement incentive mechanism, to lead a workshop proess. The Commission stated:

"SDG&E shall sponsor, in coordination with the other utilities, an all-party workshop to develop an incentive mechanism proposal. If consensus is reached, the proposal should be filed in each utilities' long-term procurement plan. If consensus is not reached, SDG&E should file a workshop report containing areas of agreement and disagreement by February 15, 2003, for our further consideration." (Ordering Paragraph 7.)

SDG&E hosted a series of workshops on incentive regulation in February and March. All three of the respondent utilities sent representatives as did the California Farm Bureau Federation (CFBF), CAISO, Calpine, CEC, CUE, Duke Solar, Mirant, NRDC, ORA, Sempra, TURN/UCAN, and Vulcan Power. On April 15, 2003, SDG&E submitted a Workshop Status Report to the Commission, in which it cited the Joint Consensus Incentive Mechanism Principles, stating that they are the "result of robust debate among a wide range of stakeholders who participated in the workshop process."95

The Joint Consensus principles are helpful in understanding the difficulties in crafting an appropriated incentive mechanism. But it is another long step from principles to an actual incentive mechanism proposal. We understand that ORA is currently negotiating an incentive mechanism proposal with SDG&E96 and has held preliminary discussions with SCE on this subject. To date, none of the IOUs has submitted a formal incentive mechanism proposal to the Commission.

The Commission considers an incentive mechanism an integral part of its long-term procurement strategy, and as such, shall direct the IOUs to move more ambitiously in crafting incentive mechanism proposals. We give specific direction in the new Procurement OIR we intend to open in the second quarter of 2004.

We direct each utility to submit by application a supply-side procurement incentive mechanism by March 1, 2004. Other parties also may propose supply-side procurement incentive mechanisms. We start with a supply-side mechanism here for simplicity. Proceedings dealing specifically with demand-side resources are better able to tailor appropriate demand-side incentive mechanisms and design the necessary measurement and evaluation requirements. An energy efficiency incentive mechanism should be addressed in R.01-08-028 and, when appropriate, a demand reduction incentive mechanism considered in R.02-06-001.

D. Other Proposals

1. CPA Peaker Initiative

CPA notes that the law charges it with insuring that electricity reliability is maintained by providing financing for power plants, efficiency, and renewable resources that meet this charge. The Agency carried out a rulemaking (2002-07-01), culminating in a final decision (D.03-001) in January 17, 2003. In D.03-001, the CPA finds that "Each utility should demonstrate to its appropriate regulatory body, and to others as required, that the utility owns, controls or reliably can acquire capacity that is expected to be available to the utility to reliably serve its load."97 Further, the CPA finds that dependable capacity should equal 117-percent of monthly peak load, resulting in a reserve ratio of 17-percent. The decision states:

    "The Power Authority expects that the reasoning and information stemming from this rulemaking will offer helpful guidance to the appropriate regulatory bodies when considering procurement policies and deciding whether or how much to differ from these recommendations based on their particular circumstances. The Power Authority also notes that this rulemaking was cited in the recent Procurement Decision in CPUC Proceeding R01-10-024; and provides this Final Decision as further input to that ongoing proceeding."98

In D.03-001, the CPA also finds that reserves are not adequate in California:

    "The Power Authority believes that up to this time, the evidence favoring the need for additional reserves is convincing. Documented withholding, exercise of market power, and rotating outages during the past two years provide stark evidence that the new paradigm brings a host of issues not envisioned under the previous scheme. Some level of additional dependable capacity, along with clear assignment of responsibilities is the best way to manage this new set of problems. The Power Authority intends to visit this reserve target recommendation each year, as it reviews its Energy Resource Investment Plan. There will be ample opportunity at that annual review to adjust targets as needed to compensate for improvements in the market structure."99

CPA's Energy Resource Investment Plan - 2003-2004 was issued in final form on June 27, 2003. That document makes explicit conclusions about the need for more capacity in California, and it is that document that enunciates the proposal for new peaking capacity:

    "The CPA has initiated an effort to increase the Statewide electricity reserve margin to ensure reliability and reduce peak price volatility. The goal is to obtain up to 300 MW of new efficient peaking resources under CPA ownership, with the power output to be provided at cost for California's electricity consumers. The CPA invited proposals from generators that meet three primary criteria: lowest cost, proximity to reliability-need areas, and earliest on-line date."100

CPA also notes that its policy and strategic contributions include a commitment to:

    "[C]ollaborate with the CPUC, CEC, and investor-owned utilities during 2003 regarding the resource plans and specific procurement strategies by the IOUs. The CPA's focus will be on ensuring that environmentally responsible and cost-effective options are considered for meeting renewable energy, localized reliability, and demand response resource needs. CPA may be able to offer ownership and/or financing solutions to achieve these needs."101

The testimony and brief of CPA emphasize that action is needed now to bring on new peaking capacity by the summer of 2005 to lessen the risk of another cycle of high and uncontrollable spot market prices and blackouts. The benefits to consumers of CPA's peaker initiative include (1) current conditions that are very favorable to plant construction; (2) the ability of CPA to help shore up investor confidence in California, (3) bolster in-state reserves; and (4) reduce RMR and other locational costs. CPA also asserts that there would be a benefit to the utilities having access to one-hundred-percent debt financing through the public power sector of the municipal bond market.

TURN supports the Peaker Initiative arguing that contracting for peaking capacity may be better than the utilities' current practice of purchasing 6-by-16 power contracts. Moreover, TURN favors CPA's low-cost financing options and favors the public investment aspect of the initiative, stating "All customers benefit from a more reliable system, but investment in such resources may not be profitable for the private sector because of the sporadic use of these units."102

CEC states that the peakers "could be a desirable resource addition"103 under certain circumstances, but finds the CPA has not demonstrated those circumstances as part of CEC's 2003 IEPR analyses. ORA finds that CPA has not made a particular showing in this record that peaker plants are necessary to support California's future electricity needs.

PG&E and SCE mounted a vigorous opposition to CPA's initiative. PG&E states that CPA's proposal for 300 MW of new peakers should be rejected because no need for them has been demonstrated, they are not cost-effective, and they do not meet the stated objective of enhancing local reliability. SCE argues that the CPA process that determined the need for the peakers was deficient, that the CPA would force the utilities to take the contracts without recourse for damages, and that the CPA itself would face no risk for construction costs for the plants.

WPTF argues that the Peaker Initiative "jumps the gun"104 on the resource adequacy issue and pre-defines the solution. WPTF would rather the utilities put their future needs out to bid after resource adequacy is fully defined.

Based on the record here, 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. Therefore, we do not direct the utilities to facilitate the CPA Peaker Initiative by entering into good faith negotiations with CPA for PPAs tied to specific power plants at specific prices. However, we do 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.

2. City of San Diego's Proposal

In its testimony, the City of San Diego requests that the Commission allow cities to serve their own load with renewable energy, where the renewable generators are owned by a city and located distant from the load being served. City of San Diego witness Monsen describes the proposal, stating:

"Cities with developable sites for renewables should be able to serve their own loads (i.e., loads for city facilities) with renewable energy, even if loads are at locations that are remote from the renewable generation." (Testimony at p. 10.)

Witness Monsen further states:

"[T]he net metering treatment chaptered through Assembly Bill 2228 for dairy farm operations, if extended to include multiple sites and multiple generators, could serve as a model for such a crediting system." (Testimony at p. 11.)

It appears the proposal would allow retail credit for renewable generation against a distant customer site, an accounting method similar in concept to the method used for on-site generation under existing net metering tariffs. However, those tariffs, including those implementing the pilot program under AB 2228, allow customers to net generation against consumption only at a single customer site. The current tariffs are not intended to permit such net accounting for multiple or remote sites.

We will neither modify net metering tariffs nor reinterpret the intent of the Legislature with respect to net metering law in this proceeding. Any changes to net metering tariffs 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.

D.03-02-068 addressed retail sales by a generator to a customer on the same distribution circuit, and did not adopt a distribution-only tariff. The City of San Diego proposal alludes to the use of high voltage transmission lines, which are located "in close proximity to these parcels of land." (Testimony at p. 11) This suggests that the facilities would utilize transmission facilities in addition to the distribution facilities used to serve the load. The proposal also refers to a "means to transmit power from these remote locations to [the city's] loads," while remaining silent on the impacts (such as costs) associated with use of transmission and distribution facilities.

Since direct access transactions have been suspended,105 new transactions of the type proposed by the City of San Diego between non-utility generators and consumers that utilize utility facilities are not allowed. Thus, there is currently no means for customers to serve their own loads with remotely sited generation. For the foregoing reasons, we do not adopt the City of San Diego's proposal.

3. CAC/EPUC's Request for Clarification of Net v. Gross Load Calculation

A major issue during the hearings was the appropriate calculation of reserve requirements for Qualifying Facilities and other on-site generation. The issue involved whether reserve requirements should be calculated on a "gross" or "net" basis. The distinction between "gross" and "net" load is that "gross" load includes the on-site load served by the generator while it is operating, whereas "net" load excludes this on-site load and looks only at energy that is delivered to the grid.106 Prior to the end of the hearing on August 12, 2003, FERC issued a final order where the issue of gross versus net determination of operating reserves was litigated.107 In its order, FERC "[A]ffirm[ed] the judge's finding that the long-standing practice in the CA ISO control area of scheduling, metering and procuring reserves on a net load basis should be permitted to continue, so long as a QF has contracted for standby service with a [Utility Distribution Company ("UDC")], i.e., a contract that provides for the immediate replacement of energy in case of the QF's forced outage."

Based on FERC's decision, all parties (including the ISO which was one of the stronger advocates for use of the "gross" approach)108 have agreed that the use of the "net" approach is appropriate for those resources that contract with the utility for stand-by service. We will therefore adopt this approach. In doing so, we note that adoption of this approach may have only minimal effects on the utilities' procurement needs. For example, in reviewing the utilities' filings, it appears that they already implicitly discount QF availability by using historical deliveries to the grid.

The Joint Parties Interested in Distributed Generation/Distributed Energy Resources (Joint Parties) argue that the same "net" treatment should apply to distributed generation.109 Provisionally, we agree. However, since the Commission has stated its intention to soon open a new rulemaking into the issue of distributed generation, we will revisit this determination in that proceeding.

65 Opening Brief, pp. 1-4. 66 SCE's energy efficiency costs from their "referred plan." 67 M. Rufo and F. Coito, California's Secret Energy Surplus: The Potential for Energy Efficiency, Xenergy Inc., for the Energy Foundation and the Hewlett Foundation, 2002 www.energyfoundation.org/energyseries.cfm 68 This count includes only the PG&E single program proposal in the PGC Rulemaking, which is for all of the procurement related energy efficiency program activity it proposes to implement in 2004 and 2005. It does not include the count of specific program activity proposed by PG&E that include activities in five statewide residential and nonresidential programs 69 Based on 2004-05 utility PGC and Procurement Submissions (9/23/03) 70 PG&E, Chapter 3, p. 10. 71 SCE, V.2, C. Dominiski, pp. 87-88. 72 Smith/SDG&E, Tr. 30/3650, 3667-68. 73 SCE-LTP-Rebuttal, p.100. 74 Discussion of Proposed Energy Savings Goals For Energy Efficiency Programs in California, Energy Efficiency and Demand Analysis Division, California Energy Commission, September 2003 75 ORA testimony, p. 67 76 PG&E 2004 plan, p. 4-4 77 PG&E long-term plan, p. 6-19 78 PG&E 2004 plan, p. 4-5 79 See also PG&E 2004 plan, p. 1-17, PG&E long-term plan, 1-21 80 Pub. Util. Code § 399.14(a)(1)(A)(ii), as added by SB 67, allows an electrical corporation to undertake renewables procurement to fulfill its RPS obligations once the Commission has determined "[t]he electrical corporation is able to procure eligible renewable energy resources on reasonable terms, those resources can be financed if necessary, and the procurement will not impair the restoration of an electrical corporation's creditworthiness. This provision shall not apply before April 1, 2004, for any electrical corporation that on June 30, 2003, is in federal court under Chapter 11 of the federal bankruptcy law." 81 Pub. Util. Code § 399.14(a)(3)(A) requires the renewable procurement plan to include: "[a]n assessment of annual or multiyear portfolio supplies and demand to determine the optimal mix of renewable generation resources with deliverability characteristics that may include peaking, dispatchable, baseload, firm, and as-available capacity. 82 Transcript 3864-5, Volume 31. 83 In assessing deliverability for specific PPAs the utilities propose entering, we should also look to see that the supplier pays for any network upgrades needed to ensure power deliverability under the contract. 84 Exhibit 49, pages 5-6. 85 Page 22. 86 Page 23. 87 Page 9. 88 DOE/EIA State Electricity Profiles 2001, published October 2003, Energy Information Administration, US Department of Energy. 89 Southern California Edison and San Diego Gas & Electric, 70 FERC 61,215 (1995) 90 In fact, during hearings in response to a hypothetical example, the CCC witness (Beach) even went so far as to state that the PURPA purchase obligation would probably even require an electric utility (that is isolated from the transmission grid outside its service territory) to build a transmission line for the expressed purpose of exporting QF power to an outside market, as opposed to not contracting for unneeded power in the first place. 91 292.304 (f) Periods during which purchases not required. 92 We note that the right to seek any such waiver rests with the state regulatory commission, and not with the utilities over which any such commission may have regulatory authority. 93 The SO2 contract was temporarily suspended in D.86-05-024. The SO4 contract was temporarily suspended in D.85-04-075, and permanently suspended in D.85-07-021, in anticipation of a final long-run contract. 94 In hearing testimony, witness Cini indicated that, as per D.03-06-067, SCE no longer sees the CRT as a barrier to forward procurement, and that its 2004 STPP should be modified to reflect this position. 95 SDG&E Workshop Status Report, April 15, 2003, p. 2. 96 Hearing Testimony of Jan Reid, July 28, p. 4218. 97 CPA Decision D03-001, pages 5-6. 98 Page 29. 99 Page 37. 100 CPA Energy Resource Investment Plan - 2003-2004, page 27. Emphasis in the original. 101 Page 33. 102 TURN Opening Brief, page 17. 103 CEC Opening Brief, page 20. 104 WPTF Opening Brief, page 42. 105 See D.02-03-055 and Water Code § 80110. 106 Tr. (Pettingill) at 4378-4381. 107 California Independent System Operator Corporation, 104 FERC ¶ 61,196 (August 12, 2003) in docket Nos. ER98-997-000; ER98-997-002; ER98-1309; ER02-2297-001; and ER02-2298-001. 108 ISO Opening Brief, p. 73. 109 Joint Parties Opening Brief, p. 15.

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