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 ORA also notes that the utilities' fuel price forecasts were out of date, and that actual gas prices were higher than expected.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 noncore 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.76
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" criterion. However, in D.03-12-062 we authorized procurement only for the year 2004, based on the utilities' short-term forecasts. We see a gap that needs to be filled so that during 2004 utilities may begin the normal cycle for procuring products required for 2005, in particular for the summer peak. While we will finish that review before the end of the year, most probably within the fourth quarter, the utilities may need this authority in advance of that time. Therefore, we will extend the authority for the utilities to procure contained in the 2004 short-term plans adopted in D.03-12-062, with one revision, to the first three quarters of 2005. This should allow the utilities to being their planning and buying for their needs in advance of the 2005 summer peak.
The utilities are directed to provide updated forecasts of 2005 open positions by compliance advice letter within 30 days of the effective date of this order. These advice letter filings will be subject to prompt Commission review and public comment and will be voted upon by the Commission, in order to comply with the requirements of AB 57. The authority granted in D.03-12-062 allows the utilities to buy for their needs in 2004, and, if advantageous, to buy for their 2004 need level as much as five years out. We leave this authority unchanged. For 2005, we limit the purchase authority to short-term contracts, that is, contracts of one year or less duration.
Returning to the issue of long-term resources, 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, as well as the prospect of departing load resulting from community choice aggregation under AB 117, 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 utilities should begin their analysis of their needs by relying on the information and analysis contained in the CEC's Integrated Energy Policy Report (IEPR) and should incorporate that information to form a base case. If a utility does not find it appropriate to use the IEPR results as its base case, it should include an IEPR case along with its more appropriate base case. The utility should explain the reasons for not adopting the IEPR case as its base case and should state how and why the assumptions underlying its base case differ from those of the IEPR. The utilities themselves are the ones responsible and accountable for meeting the loads and energy requirements of the customers in their service areas. The utilities, not the CEC, are required to meet an obligation to serve under several sections of the Pub. Util. Code. We specifically cite here Section 451's requirement to "furnish adequate, efficient, just, and reasonable service ... necessary to promote the safety, health, comfort, and convenience of its patrons, employees, and the public." Therefore, regulatory clarity and appropriate placement of responsibility requires that the utilities should have the responsibility of estimating their own future needs.
The utilities should prepare long-term plans based on the outcome of the issues to be addressed in workshops regarding resource adequacy. If those issues are not settled by the time the utilities need to begin their planning, they should make their best estimate of the outcome of the workshop process and estimate needs accordingly.
The long-term plans should provide a range of estimates of future needs taking into account short-term and long-term drivers of need. 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. We also expect the utilities to continue to consider a core/non-core scenario in their forecasts. The utilities should also supply a range of forecasts of load in their revised 2004 long-term plans in order to account for potential changes in community choice aggregation and direct access. This should include forecasts for a scenario involving the resumption of direct access and a separate scenario modeling widespread adoption of community choice aggregation.
The long-term procurement plans should include a mix of all of the resources and products authorized in this decision and in D.03-12-062, with a policy priority given to specific resources, as discussed in the following section. Specifically, in Section V.B, we discuss integrating specific types of resources into procurement plans in the order stated in the Energy Action Plan. As part of their long-term plans, the utilities should identify which procurement proposals will require environmental review, special permits, separate applications, or other regulatory procedures or proceedings.
The federal and state legislatures, the Federal Energy Regulatory Commission, and this Commission have set a number of criteria through which utilities are to meet their obligations to their customers. The cogeneration requirements of the Public Utilities Regulatory and Policies Act of 1978 and their implementation by this Commission here in California, the renewable portfolio standard, mandated under SB 1078 and SB 1038 and implemented in this docket, the funding of efficiency programs and mandating of efficiency targets, and the Energy Action Plan's preferred loading order, to name but a few, place the utilities in the position of having less discretion than in the past in determining the best combination of resources with which to meet the needs of their customers and of the state. Therefore, the work of the utilities in forming long-term plans is less a matter of Integrated Resource Planning under generalized criteria using a proverbial "clean sheet of paper" than it is a process of "filling in the boxes" to satisfy requirements that have been set up by others. All of those requirements are mandated in the interest of those same customers and residents of California and of the United States. But the process of meeting them may appear less elegant than if the plans were developed de novo. We recognize that a completely fresh set of evaluations of the costs and benefits of different resource options could yield a different set of results than California's current set of policy preferences and legislative mandates.
We use the term "integration" to refer to the utilities' efforts to incorporate various instruments into the energy system planning process - energy conservation and efficiency measures, demand-side management and renewable energy resources are perhaps the most prominent - to enable us to achieve our policy goals of sustainable, reliable and reasonably priced energy service in ways that limit the environmental consequences of the supply process. The CEC also refers to an "integrated" planning process in its Integrated Energy Policy Report. However, our efforts to-date are only initial steps on the road to developing integrated resource plans. What we have accomplished up to this point might be more accurately characterized as "aggregation"-through the Energy Action Plan and our decisions in this docket, we have asked each utility to apply a "loading order" to its resource additions, favoring energy efficiency and conservation, followed by renewable and distributed generation and then relatively cleaner gas-fired central station plants. In effect, the utilities have identified prospective resource additions that fit in each of these categories and gathered them into a bouquet.
While this process has been consistent with our statewide goals for energy efficiency and renewables, it does not end our efforts to promote better-informed, more accountable utility planning. The integrated resource planning we seek to achieve would provide a comprehensive context for all of a utility's resource decisions and would include the following features:
1. Rather than considering projected load and resource needs only on a statewide or service territory scale, each utility would assess the different characteristics of the many planning areas within its service area - taking into account the nature of local customer load (such as specific industries, the residential mix, and related load profiles), transmission and distribution constraints, existing generation resources, land use concerns and community values.
2. Each utility would develop a base plan that would take into account least-cost resources, reliability needs, fuel diversity, and other risk management concerns. On the local level, the utility would determine the optimal way to meet demand (whether it would be through energy efficiency, demand reduction, transmission or distribution additions, distributed generation, renewables, or fossil generation).
3. On a service territory-wide basis, the utility would then determine whether the optimal local solution adequately supports total resource needs and the achievement of the state's policy preference for energy efficiency and renewables, and adjust the plan as needed to serve those broader needs.
By relying on such a bottoms-up approach, the utility would be able to understand the implications of its planning decisions. The Commission and utilities would be able ensure that state policies are implemented in a manner designed to contain cost while achieving other goals. Such a process is not merely consistent with the state's broader policy goals - it will help sustain them.
We encourage the utilities to begin designing and creating the internal processes necessary to support this type of analysis and will further explore its implementation in our new long-term procurement proceeding.
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.
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 prices of fuel and costs of purchased power at least up to the 95th percentile of the expected distribution.
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. A standardized method of reporting costs is the Present Value Revenue Requirement as discussed in the testimony of SDG&E's Robert Anderson. This provides an objective tool for making cost comparisons.
The following table presents a summary of the dimensions of the information that should be presented in the long-term plans of the utilities:
Load Scenarios |
CEC-IEPR Case - Base Case |
Alternative Base Case | |
High Load Case (95th Percentile) | |
Community Choice Aggregation (CCA) | |
Core/Noncore Load Case | |
Other Load Forecast Cases | |
Portfolio Choice |
Preferred Mix of Assets including a mix of all of the resources and products authorized in this decision according to EAP loading order |
Other Portfolio options as appropriate | |
Cost Level |
Expected Cost Level |
Cost estimated at 95th percentile | |
Other cost estimates as appropriate |
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. We plan to finish this well before the end of the year to avoid the end of the year crunch that has occurred in this proceeding in the last two years. To achieve this undertaking, we will schedule an April 2004 PHC as an early status check. In preparation for the PHC, the utilities should file by the end of March 2004 a working outline of their long-term plans that includes the level of detail and specific scenarios addressed in this decision, the means by which they will incorporate the resource adequacy framework developed through workshops, and a showing that the material provided in the public filing will allow for meaningful participation by all parties; interested parties may file comments on the outlines by mid April 2004. The exact dates will be determined in a subsequent ruling from the assigned ALJ. The revised 2004 long-term plans and the results of the workshops described herein will be reviewed in a new procurement-related OIR, which we will open in the first quarter of 2004.
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
In general, we find that the utilities have taken a credible first step in their short-term plans, which we approved in D.03-12-062, in beginning to capture the energy efficiency potential available in their service territories. In those plans, we authorized utility energy efficiency activities, including the following: establishment of utility funding levels for energy efficiency activities for a two-year interim period, 2004-2005, to coincide with the two-year interim planning horizon for efficiency programs in R.01-08-028; program evaluation and selection criteria, submission timelines and proposal submission directives; a cost-recovery accounting mechanism and customer non-bypassable surcharge to fund procurement related energy efficiency programs; and a decision to shift deliberations on a potential performance incentives for procurement efficiency activities to R.01-08-028.
Though we authorized short-term funding and addressed several other issues in D.03-12-062, we are nonetheless mindful of the tremendous potential for efficiency savings that the utilities have left untouched in their proposed plans and we look to the utilities to significantly enhance their energy efficiency procurement activities in future updates to long- and short-term plans. For the present, utilities will need to "ramp-up" their efforts, to prepare for even more vigorous procurement related energy efficiency activities in the years ahead.
Furthermore, we note that each utility has used a somewhat different methodological approach to analyzing and integrating the energy efficiency component of their procurement efforts into their long-term plans. While we do not intend in this decision to proscribe a set format for each utilities' analysis of the potential for energy efficiency in their service territories and the relationship of that potential to meeting their overall resource needs -- we do urge the three utilities to come together to decide on a common approach to integrating energy efficiency procurement activities into their overall procurement forecasts and resource acquisition strategies. Such an approach will ensure future consistency in Commission evaluation of procurement related energy efficiency efforts.
We address here key procedural and coordination issues related to the Commission's Energy Efficiency Rulemaking 01-08-028. In D.03-12-062, the Commission determined that issues related to performance incentives for energy efficiency would best be able to be deliberated upon and resolved in R.01-08-028. Here, we identify several other issues that the Commission determines are able best to be decided in an integrated fashion in R.01-08-028 rather than in this rulemaking. These include the following: efficiency program duration and cycles, program level evaluations, goals for the Commission's portfolio of energy efficiency programs, future administration of energy efficiency programs, question relating to our preference that be permitted non-utility filings for procurement related energy efficiency activities.
In this decision, we also provide guidance on key issues related to the energy efficiency component of utility long-term plans, including the following: the need for utilities to account for energy savings in their territories from non-utility providers; and the issue of utility accounting for any future potential CO2 emission penalties in their cost-benefit assessments of project costs to ensure that ratepayers do not bear the burden of such future costs. We also address several technical issues related to the need for utilities to: (a) ensure that the amount of savings projected in procurement related programmatic energy efficiency submissions in R.01-08-028 are equal to or greater than the energy savings and demand reductions forecasted in utility long-term plan forecasts; and (b) ensure that the methodologies and projections used by utility long-term plan forecasters be made consistent with or equivalent to, the savings projected by utility program planners/designers in their program level energy savings submissions to the Commission in R.01-08-028.
a) 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 - ORA and TURN - 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 undergo Evaluation, Measurement, and Verification (EM&V) activities 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 EM&V review of specific program offerings in the future to R.01-08-028.
(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 workpaper77 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 R.01-08-028.
(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, argued 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 changed this position in its opening brief, requesting the Commission to adopt the energy efficiency and demand response budgets associated with their "preferred plan." This was done in D.03-12-062. 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.
(5) 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 parties able to assist the Commission in meeting its stated demand reduction and energy savings goals through the offering of innovative energy efficiency program proposals. We direct that a non-utility role be considered in the delivery of the procurement-related energy efficiency programs as well as public goods charge-related programs at the time the Commission considers the issue of the design of the future administration of energy efficiency programs in R.01-08-028.
b) Other Issues
(1) 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) 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 updates 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) Requirement that Savings Equal to or Greater than those projected in utility forecasts be present in Utility Programmatic Savings Projections
In reviewing utility short-term plan energy efficiency submissions, we have identified the need to ensure that projected utility savings and demand reductions from programs submitted in R.01-08-028, for the programmatic period in question, are in alignment with those forecasted in utility long-term plan in this rulemaking. We therefore establish the requirement here that utility procurement related energy efficiency program submissions be equal to or greater than those forecasted in their long-term plan forecasts for the forecast/program period in question. In making this requirement, we restate the importance of energy efficiency to the overall procurement activity and the need to ensure that projected savings are realized in programs aimed to help the citizens of the state save energy - thereby reducing the need for other non-renewable supply options.
(4) Alignment of Forecast Level Measure Values for Energy Efficiency Savings with Program Level Measure Values for Energy Efficiency Savings
Utility long-term forecasts submitted in this rulemaking utilize measure values for energy efficiency technology applications that are often different from the measure values used to determine savings in utility programmatic submissions. The need exists to ensure that the savings projected in the forecast submitted in this rulemaking are consistent with the projected energy savings calculations for programs submitted in R.01-08-028. We therefore require the utilities to submit within 20 days of this ruling their approach, with relevant examples, of how each utility will ensure that savings forecast in this rulemaking result in savings (and demand reductions) captured in their projected program targets in the Commission's Energy Efficiency Rulemaking.
(5) Direct Access Customer Eligibility for Procurement Energy Efficiency Programs
In its comments AReM raises the issue of direct access (DA) customer eligibility for energy efficiency programs, requesting that the Commission clarify that DA customers should only be responsible for energy efficiency program costs for programs in which they are eligible to participate (p. 23). The record in this proceeding is limited on this issue, yet it is the Commission's understanding based on SDG&E's evidence that all parties paying non-bypassable surcharges for energy efficiency are eligible to participate in these programs. SDG&E witness Smith stated in her July 22, 2003 and in earlier testimony that SDG&E believed that "all classes of customers should be allowed to participate in these programs, including both bundled customers as well as direct access customers."
2. Demand Response
In D.03-12-062, we summarized the policy framework from R.02-06-001 and the Energy Action Plan supporting demand response programs in California, provided an overview of the respondent utilities' demand response proposals from their long-term procurement plans, approved the proposals filed by PG&E and SDG&E, and rejected SCE's request for additional funding of a new Air Conditioning Cycling Program. For purposes of providing a complete discussion of demand response issues in this decision, we repeat below the text from Section VI of D.03-12-062 addressing 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:
"_ Implement a voluntary dynamic pricing system to reduce peak demand by as much as 1,500 to 2,000 megawatts by 2007.
"_ Improve new and remodeled building efficiency by
5 percent."_ Improve air conditioner efficiency by 10 percent above federally mandated standards.
"_ Make every new state building a model of energy efficiency.
"_ Create customer incentives for aggressive energy demand reduction.
"_ Provide utilities with demand response and energy efficiency investment rewards comparable to the return on investment in new power and transmission projects.
"_ Increase local government conservation and energy efficiency programs.
"_ Incorporate, as appropriate per Public Resources Code section 25402, distributed generation or renewable technologies into energy efficiency standards for new building construction.
"_ Encourage companies that invest in energy conservation and resource efficiency to register with the state's Climate Change Registry.
"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.
"In its `preferred plan,' SCE requests $40 million in
pre-approved funding for seven years and approval of a `new and improved' Air-conditioning (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."78
In its direct testimony on the utilities long-term procurement proposals, ORA expresses concern with having the IOUs count new and untested demand reduction programs towards meeting capacity requirements. ORA testifies that "... only the reliable peak load reduction from the existing programs should be considered for planning purposes."79 We address this resource counting issue in Section IV.A. on Reserves and Resource Adequacy.
The CEC voices a similar concern in this area. In its comments on the proposed decision and alternate from Commissioner Peevey, the CEC states:
"All of the soft resource categories - EE, PRD [Price Responsive Demand], DG, and to some extent renewables - require specific monitoring mechanisms. Because these resources are highly dependent on consumer acceptance, it cannot be assumed that what is planned, and committed to, will have the same real world effect."80
The CEC adds that "While the CEC supports these preferred resource additions, we believe they must have corresponding monitoring mechanisms if they are to really be relied upon to displace generators."81
We agree with the thrust of the CEC's comments on this point and note that with respect to demand response programs, in D.03-06-032, we specifically authorized funding for monitoring and evaluation of such programs. In this decision we do not authorize additional funding beyond that ordered in D.03-06-032 for measuring and evaluation purposes.
Lastly, we note that on November 24, 2003, the Assigned Commissioner in R.02-06-001 issued a Ruling which, among other things, requires the utilities to submit plans on March 31, 2004 describing 2004 efforts for meeting the 5% system peak reduction goal in 2007. As part of the March 31 filing, the utilities will include an assessment of whether the programs authorized in D.03-06-032 need to be modified in order to achieve the 2007 goal, preliminarily identify new programs that may be needed, and propose changes to the demand reduction goals based on initial deployment of authorized programs. We expect any proposed program changes to be part of the utilities' revised long-term plans, however, evaluation of those changes will be considered in R.02-06-001 or its successor rulemaking.
3. Renewables
D.03-12-062 addressed renewables issues in the utilities' 2004 plans, deferring long-term planning issues to this decision and the forthcoming Renewables Portfolio Standard (RPS) rulemaking. The prior decision reaffirmed the guidelines to be used for any interim procurement activity prior to full RPS solicitation, and declined to adopt interim reasonableness benchmarks. That decision also reaffirmed a finding in D.03-06-071 that renewables contracts should have terms no less than 10 years to foster a long-term market for renewables.
In D.03-12-062, we determined 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. The forthcoming RPS rulemaking will require the utilities to file renewable procurement plans pursuant to Pub. Util. Code § 399.14(a)(3). In those plans, we will require full assessments of renewables needs to meet the utilities' energy and capacity needs and RPS requirements. As we turn our attention now to the long-term plans, we require those plans to contain more detailed estimates of each respective utility's renewable resource profiles, as discussed below.
The long-term procurement plans currently under consideration do not constitute a filing of the required renewable procurement plans, nor does their approval "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. We reaffirm that interim solicitations will follow guidelines already established by the Commission.
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"82 in the RPS program, is "ineligible to participate,"83 and goes so far as to say it "will not participate in the RPS program until it is creditworthy."84 ,85 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 creditworthiness.86 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). A non-creditworthy utility may also be directed by the Commission to prepare a renewable procurement plan, as this is not considered "procurement" under 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.
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, contracts signed under the transitional procurement period, and anticipated long-term peaking and baseload needs, 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,87 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 shall be modified accordingly.
The IOUs should also update their long-term plans to include interim procurement activity from 2003 and any resulting changes to the quantity of renewable energy delivered in subsequent years. 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 early this year. 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 separately filed conceptual transmission plans to this effect, and the Commission has submitted 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:
1. Promote clean, small generation resources located at load centers;
2. Determine whether and how to hold distributed generation customers responsible for costs associated with Department of Water Resources power purchases;
3. Determine system benefits of distributed generation and related costs;
4. Develop standards so that renewable distributed generation may participate in the Renewable Portfolio Standard program;
5. Standardize definitions of eligible distributed generation technologies across agencies to better leverage programs and activities that encourage distributed generation;
6. Collaborate with the Air Resources Board, Cal-EPA and representatives of local air quality districts to achieve better integration of energy and air quality policies and regulations affecting distributed generation; and
7. Work together to further develop distributed generation policies, target research and development, track the market adoption of distributed generation technologies, identify cumulative energy system impacts and examine issues associated with new technologies and their use.
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 stated our intent to take a comprehensive outlook when considering resource procurement to meet demand. This approach should balance the benefits of generation, transmission, and demand-side options in meeting need in a cost-effective, environmentally sensitive manner. We also made clear in the EAP our objective of ensuring 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 additional transmission 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 Palo Verde 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.88 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 local deliverability requirements.
We find here that a minimum requirement is that the IOUs work with the ISO on defining conceptual scenarios for resources imported into the ISO control area and deliverable to the individual IOU's load, 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. While we maintain that deliverability is a critical criteria for a resource to "count" towards a LSE's resource adequacy requirement, as we discussed earlier, we look to further defining and refining a standard of deliverability following our resource adequacy workshop.89
In its testimony, the CEC states that the Commission's focus in D.02-10-062 was generation-focused and we must expand to include generation, 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.90 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 and reasonable rates; this is the utilities' statutory obligation to serve.
In guiding the utilities' long term planning process, we focus on developing an integrated resource approach, one that recognizes our policy priority for demand-side resource additions, and that optimizes generation and transmission resources.
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:
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.
We commend SDG&E for incorporating both a deliverability component as well as a local reliability aspect in their approach. We agree that these are critical components to a comprehensive approach to meeting need. Including a local reliability criteria for new generation in order to address transmission issues in load pockets is critical to addressing specific local reliability issues, which exist predominantly in SDG&E's and PG&E's service territory.
Currently, local reliability is addressed through Reliability Must-Run (RMR) contracts. Reliability Must-Run units are generation units that the CAISO has determined have to run for local reliability reasons. They are predominantly in transmission-constrained areas where local generation near load balances the limitation on imports over constrained transmission lines. While RMR serves an important purpose, RMR contracts are annual contracts that detract from a comprehensive infrastructure planning approach. They are also expensive, costing $360 million in 2003. There are several reasons that RMR contracts are expensive: 1) the generator is in an advantageous bargaining position since by their very nature RMR contracts are required for reliability; and 2) many of the generating units are very old and inefficient.
The IOUs in their long-term procurement plans are in a position to foster a more comprehensive approach to meeting local and system needs through long range plans that incorporate generation, transmission, and demand-side trade-off analysis from a least cost perspective. We direct the utilities to include a local reliability component in their next procurement plan. This approach will facilitate a more comprehensive approach to resource planning. It is our intent that this approach will increase the effectiveness of resource procurement and result in lower costs to ratepayers.
While we conceptually agree with SDG&E's 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 next 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: requiring the removal of old, surplus, above-ground lines when new ones are added, tying in local power sources and renewables in evaluating sites, upgrading line capacity for growth, and 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 communities affected, 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 in its General Order 131-D CPCN; 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 transmission 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."91
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."92
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.93 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.94 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, which may provide significant fuel diversity benefits. In order to ensure that a variety of fuel diversity options exist in SCE's revised long-term plan, we expect SCE's revised long-term plan to contain scenarios both including and excluding the Mohave power plant.
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
In D.03-12-062, we directed the IOUs to extend expiring or expired contracts with existing QFs for another year until December 31, 2004. We did this in order to assure the continuing availability of QF power during 2004 through the use of SO1 contracts under the following conditions:
· The QF must have been in operation and under contract to provide power with an IOU at any point between January 1, 1998 and the effective date of this decision; and
· The QF contract must be set to expire before January 1, 2005, or have already expired.
However, D.03-12-062 did not allow for any new QF contracts with new QFs during the short interim period between the issuance of that decision and the issuance of this decision.
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. 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 D.02-08-071, QF power provides 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."95
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.
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' Comments on the Proposed Decisions
On December 8, 2003, PG&E, SCE, CCC, CAC/EPUC, and IEP filed their respective comments on QF issues96 contained in the ALJ Walwyn Proposed Decision (PD) and the Peevey Alternate Decision (AD). On December 15, 2003, these same parties filed reply comments,97 as well as comments on the Lynch Alternate Decision. Ridgewood filed comments on all three proposed decisions on December 15, 2003.
In comments on the ALJ PD and the Peevey AD, PG&E was strongly supportive of the "recognition that ratepayers have paid above-market prices for QF power." PG&E suggested that the term of new SO1 contracts be limited to one year, during which time the Commission could revise QF pricing. PG&E requested that QF payments under new SO1 agreements be subject to later true-up to the extent they exceed the utilities' avoided costs. PG&E further requested that any additional interim SO1 contracts be energy-only contracts for months where capacity is not needed (PG&E, pp. 17-19).
SCE comments that it would be inconsistent for the Commission to conclude that (1) short-run avoided cost (SRAC) pricing exceeded utility avoided cost and then (2) direct IOUs to extend QF contracts through 2004 at current over-market SRAC prices. SCE states that some accommodation must be made to reconcile the policy conclusion that SO1 contracts should be extended with the evidence that SRAC prices were too high.
IEP comments that the PD and AD misread the Ketchikan waiver as extending to both energy and capacity, which IEP contends is applicable only to capacity. IEP further states that the PD and AD unlawfully step into FERC's role of granting waivers from PURPA's purchase obligation, which would be a violation of federal law. IEP states that PURPA continues to require utilities to purchase power from QFs.
CCC comments that the Commission cannot lawfully excuse IOUs from their PURPA purchase obligation. It cannot condition PURPA purchase obligation on a determination of need for the power. CCC contends that the Commission should order IOUs to take QF power and to do so using the same interim 2003 SO1 contract that was authorized in Commission decision D.02-08-071. According to CCC, the PD must clearly reject the notion that PURPA is satisfied simply by allowing QFs to participate in competitive solicitations, and the PD's and AD's findings on SRAC Pricing (i.e., that SRAC prices are above market and inequitable) are unsupported by the record.
CAC/EPUC comments that the Commission must uphold the QF purchase obligation in order to secure the many benefits of QF power, which include increased capacity in California, reduced impacts on the grid, increased system reliability, reduced consumption of natural gas, greater efficiency, and environmental benefits.
In its December 15, 2003 Reply Comments on the PD and Alternates, PG&E contends that QF parties incorrectly argue that the Commission must seek a waiver of the PURPA purchase obligation requirement from FERC in order to limit the utilities' future QF purchase obligation to those times when power is needed. PG&E states that Commission suspension of Standard Offer contracts is not predicated on FERC approval, even though suspension is due to oversupply. PG&E contends that the IOUs are in compliance with PU Code Sec. 372(a), regarding encouragement of cogeneration, because current QF power represents a significant portion of IOU power and thus there is no current need for a long-term standard offer to encourage additional cogeneration. PG&E states that it looks forward to the use of "new, more accurate mechanisms to establish the utilities' avoided costs [other] than the current outdated [SRAC] methodologies or administratively determined benchmarks." In addition, PG&E contends that its "1,000-hour curtailment" proposal would not cause QFs to shut down.
In its reply comments, SCE reiterates its position that the PURPA purchase obligation is not an unconditional, mandatory purchase obligation, but is rather a requirement that should be balanced against a utility's need for power and with the standard for just and reasonable rates. SCE also more broadly contends that the utilities cannot lawfully be required to pay current SRAC for QF power, given that the utilities have paid above-market prices for QF power in certain time periods.
In its reply comments, CCC states: (1) SCE misrepresents the record to conclude that SRAC exceeds avoided costs; (2) next year's SRAC review should not be prejudged by the limited and conflicting evidence on this record; (3) unsubstantiated SRAC findings should be deleted; and (4) PURPA purchase obligations should not be contingent on a utility's own determination of need for QF power.
In its reply comments, IEP opposes PG&E's request to subject new SO1 QF contracts to a later true-up to the extent posted SRAC prices exceed utility avoided cost. IEP contends that (1) the proposed true-up is inconsistent with established precedent whereby QF prices have always been set prior to delivery, and (2) a true-up would "cloud investment and place [QF operations] at risk." IEP also opposes PG&E's request to remove capacity payments from new SO1 contracts during months when the utility does not forecast a need for such capacity. IEP contends that this PG&E proposal is unfounded, as the utility has not presented any publicly available data in support.
In its December 15, 2003 comments on all three proposed decisions, Ridgewood Olinda contends that each PD must be modified to (1) require expressly that utilities purchase all electricity offered for sale by QFs at avoided costs, (2) to eliminate the waiver of this obligation based on utility need, and (3) to eliminate the disparate treatment of new and existing QFs.
b) Parties' Recommendations Not Yet Discussed
CCC Positions
CCC recommends that QFs should be allowed to (1) 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 would provide 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. 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.).
CAC/EPUC Positions
On QF issues, CAC/EPUC contended 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:
"(1) The commission and the Electricity Oversight Board shall determine if any policy or action undertaken by the Independent System Operator, directly or indirectly, unreasonably discourages the connection of existing self-generation or cogeneration or new self-generation or cogeneration to the grid.
"(2) If the commission and the Electricity Oversight Board find that any policy or action of the Independent System Operator unreasonably discourages, the connection of existing self-generation or cogeneration or new self-generation or cogeneration to the grid, the commission and the Electricity Oversight Board shall undertake all necessary efforts to revise, mitigate, or eliminate that policy or action of the Independent System Operator."
ORA Positions
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.
c) Discussion
The spectrum of QF positions in this proceeding is defined on the one end by an absolute, mandatory PURPA purchase obligation regardless of utility need, 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. We are cognizant of the fact that, whatever our policy preferences, we must make our policies conform to the legal requirements. Thus, what follows is a discussion of our legal constraints.
(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." In the three proposed decisions that were circulated for comment, we stated that 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." This characterization of the QF issue and associated discussion was taken by some parties as an attempt to overreach our jurisdiction in order to make a determination that is clearly under the purview of FERC. This was not, and is not, our intention. We expressly acknowledge the authority of FERC to grant waivers or limited waivers of the PURPA purchase obligation as set forth in 18 CFR 304(f). However, in the interest of clarity, we shall provide more specific guidance with regard to the point at issue here in this rulemaking regarding QFs, namely, the implementation of the PURPA purchase obligation by California's IOUs.
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)
Several other recent FERC rulings shed light on states' obligations under PURPA.
In particular, the PURPA purchase obligation is subject to specific curtailment provisions in 18 C.F.R. Section 292.304(f)98. Additionally, the waiver provision in 18 C.F.R. 292.402 provides further flexibility to states in their implementation of the PURPA purchase obligation, should a state decide to pursue such a course of action at FERC. 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.99 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.
The relevant language from this case is 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 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 addresses broad requests for waivers but not specific circumstances where waivers may be granted.
Another recent FERC case that addresses circumstances potentially relevant in California today is 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.)
This case would seem to address issues relevant to California's current situation, where utilities have little need, in the short-term, for baseload power such as that provided by QFs. This is primarily due to the excess baseload power represented by the DWR contracts between now and 2005 or 2006 (depending on the utility). After that time, the net long positions of the utilities due to DWR contracts drop off dramatically.
Thus, we have a short-term situation when a large number of existing QF contracts are expiring just at the time when the utilities have excess power. This situation is temporary, however, and should not dictate our long-term policy. As CCC points out, QFs provide numerous benefits to California, including environmental characteristics, efficiency, contributions to the local economy, as well as power resources. It is in the State's interest for QFs to continue to provide those benefits over the long term, especially where they are already in existence. This is separate from the issue of the price to be paid for QF power going forward, which we have already determined in D.03-12-062 needs to be revised.
The situation related to existing QFs is distinguishable from the question or whether the Commission must provide an opportunity for new QF contracts. FERC's Ketchikan order and Order No. 69, provide more specific guidance on this question:
"...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 its December 15, 2003 comments on the proposed decisions, Ridgewood contends that FERC recently confirmed the PURPA purchase obligation mandate in 105 FERC 61,238 and 105 FERC 61,239 (Swecker QF orders), and that these rulings are applicable to our current situation here in California. While these FERC orders resolved a lingering dispute between a small wind QF100 and a small cooperative utility,101 the Swecker QF orders do not necessarily provide useful or dispositive guidance for our detailed and complex situation here in California where utilities with millions of customers and tens of thousands of megawatts of load have excess power in many hours.
As set forth in detail in all three proposed decisions, we have appropriately found the relevant guidance in FERC's Ketchikan and Cogen Lyondell orders. However, Ridgewood chose not to address, either order. Instead, Ridgewood relies exclusively on the Swecker QF orders. This Commission has acted in the past consistently with the holding in FERC's Swecker QF orders; indeed, we affirmed our implementation of the policy on PURPA's standard rates requirement for small QFs in D.96-10-036, Ordering Paragraph 7.
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
In D.03-12-062, we directed the IOUs to extend expiring or expired contracts with existing QFs for another year until December 31, 2004. However, that order only covers a very limited number of existing QFs, and the larger policy questions arising from the fact that many of the state's QF facilities have contracts that will be expiring over the next several years remain to be addressed.
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 and for the other benefits of QF power, we do not think that IOUs proposal is sufficient.
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 one 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 SRAC that QFs are entitled to be paid pursuant to PURPA and state law. As was discussed in D.03-12-062, it is important that the current methodologies to establish QF pricing be modified and the Commission will be moving forward to examine and propose appropriate modifications to the QF pricing methodology in the near future.
Another option for determining the appropriate price to be paid for QF power emanates from the renewable portfolio standard provisions established in statute. The RPS provides for identification of a market price referent as discussed earlier in this decision. That market price referent, designed to approximate the market price of power, could form a proxy for the price at which QF power should receive a contract renewal. In our examination of QF pricing methodology going forward, we will invite parties to comment on this option for QF pricing.
We understand that most of the existing QF contracts will not expire until the end of 2005, and we expect that our review of the QF pricing methodology will be completed well in advance of that date. However, there may be some QF contracts that expire after December 31, 2004 but 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 QF pricing methodology, we should continue to provide interim treatment, as we did in Decision D.02-08-071 and D.03-12-062, for QF contracts expiring prior to the completion of that review for which the QF and the utility do not reach agreement on the terms of a new long-term QF contract.
We are hereby extending the determinations we made in D.03-12-062 with respect to existing QFs with expiring contracts for up to an additional year, such that the utilities are obligated to continue to purchase power from any QF pursuant to an SO1 contract under the following conditions:
· The QF must have been in operation and under contract to provide power with an IOU at any point between January 1, 1998 and the effective date of this decision; and
· The QF contract must be set to expire before January 1, 2006, or have already expired.
In D.02-10-062 and D.03-12-062, we only required utilities to enter interim SO1 contracts of one year in length. In this order, however, we are persuaded by CCC and CAC/EPUC that a one-year SO1 contract is not sufficient to accomplish some of our goals.
In particular, we wish to encourage existing QFs to continue providing power over the longer term to the utilities. We also wish to encourage efficiency upgrades to existing facilities. Neither of these objectives will be met if we continue to offer only stopgap solutions in the form of one-year SO1 contracts.
Therefore, we will require the utilities to sign SO1 contracts of five years in duration with QFs wishing to provide power at SRAC prices. This is shorter than the duration suggested by CCC, owing to our uncertainty about power needs in the long-term and the fact that we have not yet adopted the utilities' long-term plans. Making the contracts five years in duration corresponds to the length of the utilities' general authorization for contracting, with the exception of renewables contracts.
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 QF pricing policy at any time prior to December 31, 2005, the pricing terms of the contract shall be modified to reflect said revised QF pricing policy as of the effective date of the Commission decision adopting a revised pricing 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; and (iii) five-year SO1 contracts with the understanding that appropriate revisions by the Commission to the QF pricing methodology will flow through to the renewed contracts. 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 or Modified QFs With Possible Future Utility Contracts
In its December 15, 2003 comments on the proposed decisions, Ridgewood argued that the disparate treatment of new and existing QFs in the proposed decisions should be eliminated. We have attempted to eliminate any such disparate treatment, as the following discussion shows.
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."
This being said, we reaffirm what we have stated in previous decisions, namely, that QF power provides significant benefits to the state. We must accordingly find a reasonable middle ground between the positions of the IOUs, on the one hand, who seek to relegate new QFs to only being able to participate in competitive procurement processes, and QF parties, on the other hand, who assert an unlimited right to supply power to IOUs regardless of need.
We accordingly find that a new QF proposing to provide power in a manner that tracks the utility's actual needs would, under PURPA, be entitled to an agreement to provide the energy and capacity actually needed by the utility.
For the moment, our policy focus is on retaining the existing QF power already under contract, and improving its efficiencies. Thus, we decline to require that the utilities offer standard contracts to new QFs. We may revisit this decision once our reevaluation of QF pricing methodologies is complete.
We want to reassure the QF community that this action is in no way intended to close off all avenues for potential new QFs to obtain contracts with IOUs during the time between our adoption of this Decision today, and that date in the next year or so when we shall adopt a decision modifying QF pricing. Specifically, we hold that a potential new QF may still obtain a contract from an IOU during the intervening period in two of the same ways as existing QFs with expired or expiring contracts, namely: (i) voluntary QF participation in IOU competitive bidding processes; and (ii) negotiation by the QF and the IOU on a case-by-case basis of non-standard contract terms.
Moreover, in connection with our consideration of appropriate revisions to the QF pricing methodology, we shall consider whether Standard Offer contracts, or some other instrumentality, should be available to potential new QF providers, and what specific form such contracts or instrumentalities should take. Thus, in our future decision modifying the pricing methodology, we expect to provide a mechanism whereby potential new QFs will be able to obtain a contract to provide power to an IOU without having to participate in a competitive procurement process, and without having to negotiate an individual bilateral contract.
With regard to any concerns that the QF community might have with respect to participating in IOU competitive bidding processes during this intervening period, we note that in this decision, we indicate that future procurement activities of the IOUs are to be conducted with much greater transparency than has been the case in the past. Thus, potential new QF power providers will be in a much better position to know what the power needs of the IOUs - which they would be seeking to satisfy - are likely to be. Furthermore, after completion of our upcoming pricing review, potential new QF power providers will also have accurate information on what the avoided costs prices that they will receive are likely to be. With this information, potential new QF power providers will be able to accurately assess the value and benefit to them of providing new or additional power to the IOUs. This approach provides fairness both to the QF community and to the IOUs and their ratepayers.
(5) PG&E's Curtailment and True-Up Proposals
In D.03-12-062, we rejected PG&E's 1,000-hour curtailment proposal. However, we need to address one remaining point regarding this proposal, namely that physical curtailment of QFs will provide unacceptable negative impacts on QF operations, which, in turn, could have the effect of discouraging existing QFs, on which the state does rely for power, from continuing in business. In this regard, we note that PG&E's witness, Pappas, did acknowledge that such curtailment would be both financial (i.e., no payments would be made to QFs in certain hours) and physical (i.e., QFs could even be prevented from physically letting free power flow on to the grid, which would force some QFs to back down on-site operations)] (p.4-5).
We also decline to adopt PG&E's request for true-up. We agree with IEP that PG&E's proposed true-up is inconsistent with established Commission precedent whereby QF prices have always been set prior to delivery.
C. Performance Incentives for Procurement 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 the Commission's 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.102 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 01-08-028. 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, we concur with TURN's comments that we do not have an adequate record on this issue with which to decide the issue.
Rather than simply adopting specific incentive mechanisms for particular resources (i.e., energy efficiency or demand response), we prefer an integrated incentive mechanism that rewards utilities for proper balancing of preferred resources, as identified in the Energy Action Plan "loading order" as well as D.02-10-062. We may choose to offer additional incentives if utilities meet or exceed particular targets set in other proceedings addressing the particular resources, but also believe that an overall incentive mechanism for proper portfolio balancing and management is important to establish.
Thus, by today's decision, we do several things. We refer the issue of incentives specific to energy efficiency 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 efficiency 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 PHC 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.
To the extent that any utility wishes to propose an incentive mechanism for demand response separately, that issue should be considered in the demand response rulemaking (R.02-06-001) or its successor.
We continue to support the development of an overall incentive mechanism as discussed above. As such, that issue will further be considered in the next procurement rulemaking with a goal of having a mechanism adopted in time for procurement beginning in 2005.
D. Other Proposals
1. CPA Peaker Initiative
CPA notes that it is charged statutorily 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."103 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."104
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."105
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."106
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."107
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."108
CEC states that the peakers "could be a desirable resource addition"109 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. We note, however, that in the context of renewable procurement discussed above, the utilities argue that they have need for peaking resources. These positions are potentially inconsistent, and demonstrate the need for further exploration of the peaking needs of the utilities both for renewable and non-renewable power.
WPTF argues that the Peaker Initiative "jumps the gun"110 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 sufficient showing to determine whether or not 300 MW of additional peaker capacity to be operational by 2005 is needed, either in the service area of PG&E or in the service area of SCE. It may be the some portion of the 300 MW proposed would represent prudent investment for PG&E and/or SCE. It may also be that some of the peaking capacity needs can be met through other means, including transmission upgrades or renewable procurement. However, the long-term peaking contracts proposed by the CPA potentially represent cheaper peaking alternatives and should be considered fairly by the utilities.
Therefore, we direct the utilities to consider the CPA Peaker Initiative by presenting an objective analysis of their peaking needs, and alternatives for meeting those needs, in their long-term plans. There is no reason that the utilities should reject the CPA Peaker Initiative out of hand simply because they did not control the RFP process. In that context, it may be reasonable for the utilities to enter into good faith negotiations with CPA for PPAs tied to specific power plants at specific prices for some or all of the proposed projects. We also 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,111 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.112 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.113 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)114 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.115 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.
- (1) Any electric utility which gives notice pursuant to paragraph (f)(2) of this section will not be required to purchase electric energy or capacity during any period during which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself.
(2) Any electric utility seeking to invoke paragraph (f)(1) of this section must notify, in accordance with applicable State law or regulation, each affected qualifying facility in time for the qualifying facility to cease the delivery of energy or capacity to the electric utility.
(3) Any electric utility which fails to comply with the provisions of paragraph (f)(2) of this section will be required to pay the same rate for such purchase of energy or capacity as would be required had the period described in paragraph (f)(1) of this section not occurred.
(4) A claim by an electric utility that such a period has occurred or will occur is subject to such verification by its State regulatory authority as the State regulatory authority determines necessary or appropriate, either before or after the occurrence.
101 "Midland Power serves approximately 8,600 households, businesses and organizations that purchase more than 208 million kilowatt-hours annually" [roughly corresponding to a system capacity of 20 megawatts (MW)]. Source: http://www.midlandpower.com/asp/AboutUs/. 102 SCE-LTP-Rebuttal, p.100. 103 CPA Decision D03-001, pages 5-6. 104 Page 29. 105 Page 37. 106 CPA Energy Resource Investment Plan - 2003-2004, page 27. Emphasis in the original. 107 Page 33. 108 TURN Opening Brief, page 17. 109 CEC Opening Brief, page 20. 110 WPTF Opening Brief, page 42. 111 See D.02-03-055 and Water Code § 80110. 112 Tr. (Pettingill) at 4378-4381. 113 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. 114 ISO Opening Brief, p. 73. 115 Joint Parties Opening Brief, p. 15."Standard rates for purchases. (1) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifying facilities with a design capacity of 100 kilowatts or less."
