4. Scoping Memo

In our OIR, the Commission lays out the comprehensive framework of issues that we need to address in establishing policies and cost recovery mechanisms for generation procurement and renewable resource development. I intend to take a two-pronged approach in addressing these complex issues. First, this proceeding will focus on what the Commission needs to decide in order to ensure the utilities successfully resume their obligation to serve and meet the needs of their customers no later than January 1, 2003 and to develop an interim rather than permanent cost recovery mechanism. In addition, I will pursue our mandate under Section 701.3 to promote the development of renewable electrical generation in California to the fullest extent possible within the confines of this proceeding schedule, explicitly emphasizing decisions that must be taken to meet the state's near-term needs. Second, I direct the utilities and the Commission staff to begin to assess long-term resource needs on an integrated basis; parties will be separately noticed of additional efforts for this endeavor. As in the BRPU, these resource plans should focus on identifying new resources that should be added to the system within the next five years for reliability or cost-savings.

4.1 Cost Recovery Mechanism Is the Near-Term Priority

My objectives in developing an interim cost recovery procurement mechanism are to:

· improve the ability of the respondent utilities to meet their obligation to serve their customers' electric loads;

· assure just and reasonable electricity rates;

· enhance the financial stability and creditworthiness of respondent utilities;

· diminish the need for after-the-fact reasonableness reviews of procurement purchases;

· ensure the timely recovery in rates of procurement costs in order to support the credit of the utilities that function as load serving entities; and

· pursue our mandate to promote the development of renewable generation in California.

The written comments of Edison and other parties state that the existing contracts entered into by DWR greatly reduce the procurement needs of the utilities through 2003. Therefore, my expectation is that the size and range of discretionary procurement choices the respondent utilities will need to make in order to serve their customers in the near term are quite limited. With possible exceptions for renewable power that will be discussed below, the interim cost recovery procurement mechanism the Commission develops here will be limited to short-term power products similar to those recommended by the Office of Ratepayer Advocates: spot market purchases, forward and options contracts of up to one year in duration, and ancillary services.4 I expect that these power products include the range of products that the utilities may need to firm up any capacity obligations the Commission may place on them as load serving entities in the ISO Control Area.5

The utilities state that a quick review and timely cost recovery process are critical to them. As other parties discuss, incentive mechanisms and affiliate transactions are two matters that do not lend themselves to these objectives. Therefore, in developing an interim procurement mechanism for 2003, parties should not propose to allow transactions with any affiliates of the respondent utilities, not just their own affiliates. Any incentive mechanisms proposed must be transparent and simple to implement to be given any consideration.

I have reviewed each of the utilities' accounting proposals for procurement cost recovery. I find that Edison's proposal is generally consistent with prior Commission cost recovery mechanisms for power purchases and it is therefore a familiar and understood approach to industry, consumer advocates, and the financial community. Edison proposes a procurement cost recovery mechanism that is conceptually similar to the long used and now defunct Energy Cost Adjustment Clause (ECAC) which was established to track fuel and fuel-related costs. Under Edison's proposal, fuel and power procurement costs, including residual net short procurement cost obligations, would be tracked in a balancing account and matched against billed revenues derived from a to-be-established Fuel and Purchased Power rate component.

To ensure timely cost recovery, Edison proposes to file an annual application at the end of the first quarter whereby entries made to the balancing account during the previous year (January 1 through December 31) would be verified by the Commission. Differences between recorded revenues and costs would be trued-up or down based on that review. The annual application would also specify a prospective Fuel and Purchased Power revenue requirement and associated rate during the following calendar year.

In addition to this annual review process, Edison proposes a trigger mechanism, similar to the trigger proposed in Assembly Bill 57, to dispose of balances in the balancing account. If at the end of a month, the balancing account is over- or under-collected by an amount that exceeds 5 percent of recorded generation revenues from the prior year, Edison would file an Advice Letter seeking a rate adjustment. The Advice Letter filing would become effective 60 days from the date it is filed. Lastly, Edison proposes to file an informational Advice Letter on September 1 of each year reporting the recorded operation of the balancing account from January 1 through June 30 of the same year. While this ruling neither approves of nor rejects Edison's proposal, I do want the utilities and parties to know that I am not comfortable with an interim cost recovery proposal that incorporates Advice Letter filings seeking balancing account rate adjustments without conditioning such rate adjustments as subject to refund in a subsequent annual review process. Additionally, as a general rule, I do not favor that call for Advice Letter filings to automatically take effect 60 days from the date the Advice Letter is filed. I note that any potential risks to the utilities has been reduced since most of their resource needs are covered by long-term, fixed price contracts entered into by DWR. In addition, if there were an unanticipated rise in procurement costs, utilities have a right to submit applications for changes in authorized levels between annual proceedings.

I direct the respondent utilities to serve testimony detailing an interim procurement cost recovery mechanism and addressing attendant implementation issues in testimony. I am especially interested in the utilities including in their testimony details on how the Commission should evaluate whether specific purchases of a particular product type are reasonable. PG&E and SDG&E shall propose ECAC-type cost recovery mechanisms similar to that proposed by Edison. Any deviations from the Edison proposal must be thoroughly explained and justified including any benefit or detriment to the ratepayers compared to the Edison proposal. Such proposals should be designed to be consistent with previous Commission decisions regarding cost recovery accounting. I expect parties will respond to the utility cost recovery proposals in rebuttal testimony.

At the PHC, PG&E, Edison, the Independent Energy Producers Association, and Dynergy Marketing and Trade ask that the Commission consider adopting here policy framework statements on timely recovery of costs and limiting the risk associated with after-the-fact reasonableness review that would apply beyond 2003 in order for the financial markets to be comfortable with the way this Commission will allow procurement costs to be recovered in the future. Parties may propose specific language that addresses this concern in their testimony provided they address the implications this will have on a permanent cost recovery mechanism that is not limited in its size and range of procurement choices and that may consider issues removed from the scope here.

The Natural Resources Defense Council requests that I expand the list of procurement products to include demand-side options among the short-term power options and Consumers Union specifically cites demand side options such as the Commission's interruptible rate program and the demand-side bidding program. While we are not designing cost recovery mechanisms for demand-side options here, the Commission does expect the respondent utilities to consider all their procurement options in their procurement planning. Demand-side options should be considered side-by-side with other short-term power options.

The fact that the cost recovery mechanisms for demand-side procurement options are not being addressed in this proceeding does not mean that the utilities should not include demand-side options in their procurement plans. I expect the utilities to include demand-side options in their procurement plans, and if they are not included, I expect the utilities to justify their exclusion in the testimony supporting their procurement plans. Any demand-side option included in the utilities procurement plans should be fully described and any deviations from authorized demand-side programs should be justified.

The Commission is addressing demand side options in related current proceedings, not here. In Phase II of our rulemaking on interruptible programs, R.00-10-002, the Commission is specifically addressing what will happen to our interruptible program after December 31, 2002 and is also the forum for considering requests to fund other demand response programs, such as the demand-side bidding program which has been funded by ratepayers through the Department of Water Resources (DWR). In our energy efficiency rulemaking, R.01-08-028, the Commission is currently considering which specific demand-side management programs to fund for 2002 and will open a separate docket to consider 2003 energy efficiency program proposals. I agree that these are important programs and that it is critical to address both demand- and supply-side options. These are programs and approaches our staff will address in proposing an integrated approach to addressing resource needs.

PG&E requests that I expand our list of short-term products to include: sales, exchanges, tolling agreements, and physical gas purchases, and that the adopted options would be applied to both gas and electric purchases. It is reasonable to address a short list of products in this proceeding in order to simplify the mechanism and because I expect the size and range of discretionary procurement choices to be limited in the near term. However, PG&E may sponsor a proposal to include these products in its testimony if it addresses how its proposal meets our stated objectives. The California Energy Commission (CEC) asked if the Commission would consider new market products that meet our definition, such as a day-ahead market operated by the ISO. Parties may address criteria for new products in their testimony, but are cautioned to provide thoroughly detailed recommendations. For example, if the CEC proposes products like a day-ahead market operated by the ISO, it should specifically address whether the Commission should presume the ISO market price reasonable, and how the Commission should judge the utility decision to purchase in the ISO market rather than through other options as may be approved. Parties should detail how the Commission should evaluate whether any specific purchase of any product type - new or old - is reasonable.

Additionally, in testimony regarding short-term physical power products, I would like parties to comment on whether all authorized transactions should be required to have a link to a specific generation facility.

4.2 Transition Issues Need to be Understood and Resolved

DWR was directed to step in to ensure Californian's continued to receive reliable electric service at a time when generators refused to sell energy to the utilities owing to the rapid depletion of their cash and credit. Now, SDG&E's cash and credit situation makes it able to procure the full power needs of its customers. SCE is working to soon be in a restored cash and credit situation, enabling it to also resume procuring its customer's full power needs. All three investor-owned utilities must resume procuring their net short by no later than January 1, 2003, when the DWR authority expires.

I am inclined to propose to my colleagues a decision that directs SDG&E and SCE to resume procuring their full net short in advance of the January 1, 2003 outside date set in statute. Toward that end, I direct the respondent utilities and invite interested parties to file legal briefs that address the required actions, if any, that must be undertaken by the Commission for the individual utilities to resume procuring the net short. I also direct the filing of comments on any actions parties believe the Commission should take to ensure a successful transition of this responsibility from DWR to the utilities at the earliest possible date. In any comments, I ask parties to discuss what sequence of DWR/respondent utilities actions need to take place to allow for an early transition, and how to best manage this transition process in a setting where specific contracts are being renegotiated. I understand that the utilities request a 60 to 90 day lead time between the date the Commission orders them to resume full procurement and the date they implement full procurement. I am not convinced it is, on balance, in the ratepayers' interest to delay the transition further. Parties should address the advantages and disadvantages of building in such a lead time.

I agree with those parties who note in their comments the critical need for the PUC to resolve two outstanding issues before the utilities may submit meaningful resource procurement plans or resume procuring the net short: 1) allocation among the respondent utilities of the load contracted for by DWR, and; 2) the parameters of Direct Access. Both of these issues have a strong impact on the quantity of energy services that must be procured by the utilities. The parameters for projecting the amount of load to be met under the Direct Access program have been resolved in D.02-03-055. I will pursue resolution of the allocation of load contracted for by DWR in proceedings where a record has already begun to be developed.

In the meantime, for utilities to prepare a procurement plan, I provide the assumptions each should use with respect to allocating the load contracted for by DWR:

SCE SDG&E

Summer On-Peak 66% 34%

Summer Off-Peak 67% 33%

Winter On-Peak 58% 42%

Winter Off-peak 42% 58%

In addition to using the above assumptions, the utilities should propose their preferred method for allocating the load contracted for by DWR in their testimony. The utilities should each include their procurement plans for the period beginning with their resumption of their responsibility for procuring the full power needs of their customers to January 1, 2004, in their testimony. These procurement plans should integrate the projected load levels and load characteristics of each respondent utility with their specific procurement strategies for meeting their projected load with both demand and supply-side procurement options.

Each utility's procurement plan should include, at a minimum:

1) A comprehensive and clearly articulated policy and strategy which would justify a selection of any particular energy product or contract at a specific point in time;

2) A definition of the electricity products and related financial products including a justification for the product type and amount to be procured under the plan;

3) The duration, timing, and range of quantities of each product to be procured;

4) An assessment of the price risk associated with each utility's total resource portfolio, including its URG, the products to be procured, demand-side options, and spot market exposure. Each utility should explain what level of price volatility/stability will result from the its procurement plan. The utilities shall also discuss why that level of volatility/stability is appropriate for providing reliable service at reasonable cost;

5) A description of the utility's risk management policy, strategy, and practices including specific measures of price stability;

6) An open and competitive process by which the utility would solicit bids for procurement services;

7) Proposals detailing how the Commission should evaluate whether specific purchases of a particular product type are reasonable;

8) A process for updating the plan in order to respond to changing market conditions; and

9) A description of demand-side options.

The DWR contract allocation issue discussed by parties is before us in our Rate Stabilization Proceeding (RSP), Application (A.) 00-11-038, A.00-11-056, and A.00-10-028. On February 21, 2002, we adopted a decision in the RSP docket, D.02-02-052, that implements cost recovery of the revenue requirements of DWR of amounts to be collected from the customers of the respondent utilities for the period January 17, 2001 through December 31, 2002. That decision establishes a schedule and procedure for an annual DWR update proceeding, with the next update of the DWR revenue requirement to be submitted to the Commission on June 1, 2002, and revised DWR charges to take effect on January 1, 2003.

4.3 Renewables Should be Part of California's Resource Mix

I now turn to how the Commission will address our mandate under Section 701.3 to promote the development of renewable electrical generation in California. As stated earlier, it is my intention to address these issues to the fullest extent possible within the confines of this proceeding and the accelerated timeframe under which we must work, explicitly emphasizing decisions that must be taken to meet the state's needs for 2003.

I have discussed above the Commission's expectation regarding the procurement methods and mechanisms that will be authorized in the interim procurement process. The challenge is to stimulate the purchase of renewable generation utilizing these limited and short-term options, respecting the need for both system reliability and appropriate procedures for reasonableness review. To that end I invite testimony on the following issues:

· Should the Commission adopt a mandatory set-aside for renewable purchases by the investor-owned utilities in short-term transactions and if so, how large should it be? If not, what should be the method whereby the Commission promotes renewable purchases in the interim procurement process?

· How can these purchases be integrated into the generation portfolio of the utilities to ensure system reliability?

· In light of parties' concerns with reasonableness review procedures, how can the Commission establish a mechanism that will facilitate the orderly and expeditious review of short-term renewables purchases?

While I do not anticipate that the Commission would authorize purchases of non-renewable energy or capacity under long-term contract in the interim procurement process, the record in this proceeding should allow the Commission to consider whether or not to authorize such contracts for renewable generation as another method of support pursuant to Section 701.3. I note that ten years ago in the BRPU, the Commission ordered the utilities to acquire over 300 MWs of new renewable resources. In the intervening years, neither those resources nor any appreciable amount of other renewable resources have been added to California's resource supply. I invite testimony on this approach in general and on the following issues in particular:

· How can the Commission establish appropriate reasonableness review procedures in evaluating long-term contracts for renewable generation products of the type and quantity needed for 2003? Are there particular price or contract structure benchmarks the Commission should favor?

· As above, how can system reliability be promoted in this process?

· How can parties best leverage other programs that support renewable generation in California, such as the CEC Renewable Energy Program and the programs under consideration by the Power Authority?

I remind parties that this proceeding explicitly emphasizes interim procurement methods for the immediate issue of restoring the utilities' obligation to serve and meet the needs of their customers no later than January 1, 2003, and that consideration of procurement practices post-2003 will likely involve larger quantities of purchased power and hence greater opportunity for support of renewable generation. Policy proposals should not foreclose options that may be available in later proceedings nor prejudge the outcome of any action underway at the Commission, in the legislature, or elsewhere. My principal objective is to stimulate development of a viable market for the output of renewable generation located within the state of California, and I invite testimony that would aid the Commission in pursuit of that goal in the very near term.

4 The Commission is currently addressing cost recovery mechanisms for other procurement products in related proceedings. For interruptible programs, the Commission has authorized the utilities to track program costs in excess of those already recovered through existing rates in a memorandum account that is reviewed for reasonableness under a standard of review that "absent incompetence, malfeasance, or other unreasonableness, we would expect to authorize full recovery of all dollars spent by utilities for these programs" (D.01-04-006, mimeo. At page 78); the memorandum accounts are reviewed and recovered in each utility's Annual Earnings Assessment Proceeding (D.01-07-029, Ordering Paragraph 2(b), mimeo. at page 11). A commission decision on the cost recovery mechanism for demand-side management programs is pending in R.01-08-028.
5 The Commission has been participating in discussions on the ISO Market Redesign. The record the Commission develops here would benefit from the participation of the ISO, and I strongly encourage the ISO to become an active party to this proceeding.

Previous PageTop Of PageNext PageGo To First Page