Wood Mattson Comment Dec. Interim Opinion on Demand Bidding Program

3. Demand Bidding Program

We make limited changes to the DBP. The revised program is contained in Attachment A.

We agree with utilities that relatively minor modifications to DBP are preferable to a wholesale redesign of DBP, reactivation of VDRP, or development and adoption of a new program (such as linking OBMC with DLCP). DBP is essentially up and running. Customers have signed DBP agreements, are familiar with the basics of the program, and are prepared to make load curtailment bids immediately. One or more websites are in place for DBP implementation.

On the other hand, major changes to DBP, reactivation of VDRP, or development of a new program would require relatively more customer education, and may engender customer resistance (e.g., if customers view changes as providing inadequate additional value for the corresponding inconvenience or burden). Further, significant program changes would require enrollments in the revised or new program, may involve additional expenses for system modifications, and would necessitate time for implementation that is unavailable given the arrival of Summer 2002.

3.1. Time Blocks, Program Initiation, and Use During Stages 2 and 3

The original DBP employed three four-hour time blocks for bids and operation. This was in part a balance between program simplicity (e.g., known, limited parameters) and complexity (e.g., infinite possibilities to allow more precise matching of supply and demand). It is now reasonable to remove the limit of three four-hour time blocks. ISO and utilities should be permitted to seek load relief in any combination of hours that will best match supply and demand. ISO and utilities may continue to employ three four-hour time blocks if that reflects their best judgment regarding use of the program. While we do not go as far in program redesign as recommended by ORA, this modest change, to be implemented at ISO's and utilities' discretion, provides a reasonable increase in flexibility to potentially better match supply and demand for Summer 2002.

We agree with utilities that they are not in a position to determine when DBP should be called. We adopt SCE's recommendation that DBP events should be activated by the ISO. This is consistent with our transitioning DBP to a reliability program, as discussed more below, given ISO's role in monitoring operating reserves.¹ To promote clarity, the revised DBP will specifically state that ISO will notify utilities when additional load relief is needed.

We accept the recommendations of ISO and utilities that DBP is best triggered by an ISO Alert Notice. According to ISO, a 24-hour Alert Notice is issued if "there is a potential for firm load curtailment within the next 24 hours based on forecasted load and resources." (ISO Procedure E-508, page 3, Exhibit A to June 21, 2002 ISO Comments.) ISO recommends that the DBP timetable be modified to permit more flexibility, however, since alerts might be issued after 2 p.m. the day before.

We agree that more flexibility is needed. In particular, we adopt use of an ISO Alert Notice to trigger DBP, but do not limit the solicitation of bids to the afternoon of the day before. Rather, bids may be solicited on shorter timeframes if real time operations by ISO do not permit more notice to utilities and customers. We adopt a one-hour timeframe for utilities to solicit bids, with an additional hour to evaluate bids and notify customers of the results. We do not require automatic rejection of bids that might be submitted after the one-hour deadline, but utilities are not obligated to evaluate late bids equally with timely bids, and should take current conditions into account in evaluating late bids.

We continue program focus on Stage 2 and 3 events. (See, for example, Executive Order D-39-01 dated June 9, 2001, revised June 11, 2001, first ordering paragraph; also D.01-07-025, mimeo., page 1.) We specifically limit DBP use to periods of forecast or actual Stage 2 or Stage 3 emergencies to the fullest extent reasonably possible, thereby promoting targeted use of the program. We decline to authorize its use during normal operations or Stage 1 events since, as discussed more below, we intend DBP to fill reliability needs and not be used as a price response/mitigation program. Moreover, implementing DBP during Stage 1 when potentially less costly resources are available would not be reasonable.

ISO states that it does not predict Stage 2 and 3 events the day before and is troubled by any requirement that it estimate the amount of DBP resources that each utility should accept. We recognize that an ISO Alert Notice only provides notice of the potential for firm load curtailment within the next 24 hours. We understand that the 24-hour Alert Notice neither specifies whether the event is expected to be a Stage 1, 2 or 3 emergency, nor estimates the amount of resource shortage. Nonetheless, we expect utilities to use reasonable judgment to solicit and accept bids only when Stage 2 or 3 are likely. For example, after an ISO Alert Notice, utilities may delay bid solicitation and evaluation until Stage 2 or 3 are forecast or imminent in order to permit proper focus of DBP on Stage 2 and 3 events.

Further, as part of bid evaluation we expect utilities to accept DBP bids only after all other less expensive resources are used to the fullest extent feasible and reasonable. For example, traditional interruptible programs (where capacity payments are incurred whether or not curtailments are initiated) should be used before relatively more expensive programs, such as DBP.

Finally, we expect utilities to use their best judgment to accept bids only within estimated need. Utilities should reject some or all bids if DBP resources are otherwise unnecessary to reasonably balance supply and demand to satisfy ISO reliability criteria.

3.2. Transition to Reliability Program

We agree with utilities that a modified DBP can fill a niche for a voluntary, non-penalty-based, day-ahead, reliability program. DBP initially served many goals. One goal was as a price responsive program that could potentially mitigate against high wholesale prices. As SCE points out, however, DBP has not operated as originally intended because the market has not exhibited the price volatility that makes a price response/mitigation program necessary and desirable. Nonetheless, DBP can still deliver value in a portfolio of load management programs by transitioning to a reliability program.

In making this transition to a reliability program, we also seek alternative funding and a utility role consistent with that funding. We continue utility monitoring of DBP curtailments as provided in the current program, but add utility evaluation of bids and payment to DBP participants based on performance. Utility funding will provide resources to promote program use, while utility evaluation of bids will increase the utility's role. Each utility may record DBP payments in its interruptible program memorandum account for subsequent recovery. We modify the pricing structure to provide necessary feasibility for utility evaluation of bids.

We agree with SCE that a single incentive level will promote transforming DBP into a reliability program. A range of prices focuses the program on price response and price mitigation, while a single price promotes using the program for system reliability. A range of DBP bids at different prices also requires bid evaluation at each price in relation to all other options at each price. DWR has information on all resources, but, as utilities point out, utilities currently do not have access to sufficient information to make that judgment regarding all possible options. A single price, however, will allow each utility to determine which DBP bids to accept or reject for reliability on each system, consistent with our goals of transforming the program and increasing each utility's role in the program. At the same time it will permit utilities to use cost information relative to the programs they operate for the purpose of implementing the least costly options (e.g., dispatching programs with a fixed capacity payment when those programs are less costly for incremental operation than DBP operation).

Further, ISO does not have the same incentives to minimize total costs as does each utility. Ratepayer funding of this program requires that utilities have the ability to exercise some judgment about its use.

Therefore, we adopt SCE's recommendation to employ a single price. We set that price at $0.35/kWh, the same level we adopted for the VDRP. (D.01-04-006, mimeo., page 31.) As with the VDRP price, this balances a range of possible prices addressed by parties, from the low end (the level of the current FERC wholesale spot market price cap ($0.09187/kWh) recommended by ORA) to the high end (prices and penalties for mandatory curtailment programs).² It reflects the voluntary nature of the program, the benefit of advance notice provided by this program compared to other programs, the absence of penalties, and a price level below that of existing mandatory curtailment programs.

Moreover, a single price at a reasonable level removes the opportunity for participants to manipulate the system to their advantage (e.g., by participants limiting offers to only those at the highest price). A single price at a reasonable level balances competing interests and promotes efficiency. Parties may use the expedited methods discussed in our Phase 1 order to seek adjustment of the price, if necessary. (D.01-04-006, mimeo., pages 31-32.)

Utilities should use first-come first-served as a primary criterion for accepting a bid, taking past non-performance or non-compliance by the customer into account. We adopt utilities' proposal for implementing a fair mechanism for non-performance and non-compliance measurement based on preliminary meter data for a series of consecutive events. As discussed above, utilities must also apply reasonable judgment to accept bids only within estimated need, as well as employ less expensive programs first, to the extent feasible.

We also adopt utilities' recommendation to limit customer bids to one per day in consecutive hours, with a minimum duration of 2 hours. A multitude of disjointed bids from a single customer would otherwise unreasonably complicate the program.

Further, we agree with utilities that accepted bids should not subsequently be cancelled. Customers with accepted DBP bids commit to a demand curtailment. They should be compensated for that commitment based on their actual performance regardless of whether the ISO later cancels the Alert Notice.

Finally, we agree with utilities that customers should not be permitted to simultaneously participate in multiple programs with the potential of being paid twice for a single event. Thus, just as we preclude DBP customers from participating in the ISO's Demand Relief Program and Ancillary Services Load Program, we similarly preclude their participation in the California Power Authority's new Demand Reserves Program.

3.3. Interruptible Program Cap

SCE proposes that DBP incentive payments not be included in the interruptible and curtailment program total funding cap. SCE argues that the Commission did not consider these payments when the cost cap was set, and that SCE projects it will be close to, or exceed, the cap before the conclusion of Summer 2002. SCE asserts that if DBP is called on frequently this summer, SCE could be forced to suspend all interruptible program activities during a time of critical need as the cost cap is reached.

We decline to adopt SCE's proposal. SCE's proposal is effectively an "infinite" cost cap for one program. This could have the undesirable effect of encouraging use of one program over others unrelated to the merits or individual costs of each program. Further, the cost cap is a "method to apply some guidance and control to these programs without adopting unreasonable expectations or constraints." (D.02-04-060, mimeo., page 21, footnote 9.) The cap prevents "these programs from spiraling out of control if conditions unexpectedly and dramatically change..." (D.02-04-060., mimeo., pages 20-21.)

VDRP was included in the original cost cap. (D.01-04-006.) VDRP was replaced by DBP, but the cost cap was not reduced to reflect DWR funding of DBP. (D.01-07-025.). The cost cap was subsequently reduced for all utilities consistent with a revised overall program goal of 2,500 MW. (D.02-04-060.) PG&E and SDG&E do not argue that there was a failure to consider DBP in the original or revised cost cap. SCE does not convincingly show that there was such failure.

Nonetheless, SCE is concerned that it may approach its annual cost cap of $137.5 million.³ To address this limited concern, we raise SCE's cost cap by $10 million, to a total of $147.5 million. This increase will fund approximately 47 MW of DBP resources for 10 hours per day for 60 non-holiday weekdays.⁴ This is a reasonable amount for Summer 2002 without being excessive.

We remind parties "that any party may file a timely pleading if, in the party's judgment, program limits should be adjusted upward or downward (e.g., a utility may file an application; a utility or party may file a petition for modification)." (D.02-04-060, mimeo., page 21.) We adopted a requirement for the filing of monthly reports by utilities to help utilities, parties and the Commission monitor whether cost caps are being approached, and we allowed for acting on an emergency basis to increase megawatt or dollar limits if necessary. (D.01-04-060, mimeo., page 80.)

Under no circumstances should a utility be forced to suspend all interruptible program activities based on its reaching the cost cap. Rather, a utility must file a timely pleading seeking a further increase if it forecasts that it may reach the cost cap. The utility should file that pleading with adequate time for parties to comment and the Commission to act in the normal course of Commission business. If necessary, however, the Commission will act on an emergency basis. Any utility's failure to follow this procedure in a timely way, resulting in the utility suspending interruptible programs during a system emergency and thereby jeopardizing the health, safety and welfare of the state's citizens, would be unreasonable absent a very compelling reason to the contrary.

SCE does not request an increase in its interruptible program limit of 1,375 MW. No party comments on any necessary change in the capacity limit. We do not adopt an adjustment in SCE's total interruptible program megawatt limit.

3.4. Cost Recovery

SCE also recommends that the Commission make an explicit finding that all incentive dollars paid by utilities are per se reasonable upon verification of the customer's actual load reduction. This would be reasonable, according to SCE, since ISO triggers program activation and event scope rather than the utility. We decline to make this finding. Rather, we expect utilities in the revised DBP to take more than a purely passive role in DBP operation.

Moreover, we have already provided that reasonable implementation costs not otherwise recovered through existing rates, or offset by revenues, are subject to later recovery. As we said in both the Phase 1 and Phase 2 orders, during this continuing State of Emergency in the California electricity market:

"We will review the balance in each memorandum account for reasonableness before authorizing recovery but, absent incompetence, malfeasance, or other unreasonableness, we would expect to authorize full recovery of all dollars spent by the utilities for these programs to get California through this crisis." (D.01-04-006, mimeo., page 78; also see D.02-04-060, mimeo., page 21.)

Utilities need no additional assurance of recovery at this time.

¹ The ISO is responsible for monitoring the state's generation operating reserve, and notifying market participants and state agencies when an emergency is likely, or is called. The ISO declares a Stage 1 emergency when forecast or actual operating reserves are less than 7% of available capacity. A Stage 2 emergency is declared when forecast or actual operating reserves are less than 5% of available capacity. A Stage 3 emergency is declared when forecast or actual operating reserves are less than 1.5% of available capacity. The ISO may call for rotating outages during Stage 3 emergencies. ² As ORA observes, paying more than $0.092/kWh is moot if supply-side resources are available at the price cap or less. On the other hand, if the cap results in a shortage, it is reasonable to pay customers more to use less (which ORA analogizes to the 20/20 conservation program). ³ SCE's monthly reports include estimates of total expenses for 2002 and the total program cost cap. In three out of the last four months the estimates have been in the range of $120 million. For example, SCE's monthly report dated February 7, 2002 estimates total expenses for 2002 of $120.0 million with the original total program cost cap of $275.0 million. SCE's monthly report dated March 7, 2002 estimates 2002 expenses of $121.7 million with a cost cap of $275.0 million. SCE's monthly report dated April 8, 2002 estimates 2002 expenses of $133.8 million with a reduced cost cap of $137.5 million. (The cost cap was reduced in D.02-04-060.) SCE's monthly report dated May 21, 2002 estimates 2002 expenses of $119.3 million with a cost cap of $137.5 million. ⁴ 47 MW for 10 hours per day for 60 non-holiday weekdays (12 weeks) is 28,200 megawatt-hours. At a payment of $0.35/kWh, the total cost would be $9.87 million. SCE currently has 96 customers representing 133 service accounts subscribed to DBP. The aggregate maximum demand of these participants is 211 MW. The minimum potential load reduction for these customers, under the terms of the DBP tariff, is 16 MW.