5. Comments on Draft Decision
On June 18, 2002, the draft decision of Presiding Officer and Assigned Commissioner Wood on this matter was filed and served on parties in accordance with Section 311(g)(1) of the Public Utilities Code and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed and served on June 21, 2002 by ISO and jointly by PG&E, SCE and SDG&E. Reply comments were filed and served on June 25, 2002 by ISO and jointly by PG&E, SCE and SDG&E. We incorporate changes based on comments and reply comments. In particular, we incorporate day-of features in the program, and include joint utilities recommendations regarding nonperformance measurement, limiting submission of bids to one per day, decline simultaneous participation in the California Power Authority's Demand Reserves Program, and provide five days for utilities to file and serve advice letters with tariffs in compliance with this order.
On July 2, 2002, the revised draft decision of Presiding Officer and Assigned Commissioner Carl Wood on this matter was filed and served on parties. Comments were filed and served on July __, 2002 by ____. Reply comments were filed and served on July ___, 2002 by ____.
1. Relatively minor changes to DBP are preferable to a wholesale redesign of DBP, reactivation of VDRP, or development and adoption of a new program since DBP is up and running, agreements are in place, customers are familiar with DBP, and customers are prepared to make load curtailment bids immediately while, in contrast, major changes or a new program would require education, may face resistance, would require new enrollments, may involve new costs, and would require time that is unavailable.
2. Utilities are not in a position to determine when DBP should be called.
3. Flexibility to balance supply and demand is increased by (a) removing the limitation that ISO and utilities must employ three four-hour time blocks for DBP, and (b) allowing implementation on a day-of as well as day-ahead basis.
4. DBP has not operated as a price response/mitigation program because the market has not exhibited substantial price volatility since DBP was adopted.
5. A modified DBP can fill a niche for a voluntary, non-penalty-based, day-ahead, reliability program.
6. A single incentive level promotes transforming DBP to a reliability program.
7. Utility funding will provide resources to promote feasible program use, while utility evaluation of bids will increase the utility's role consistent with utility funding and transition of DBP to a reliability program.
8. A single DBP price at $0.35/kWh balances a range of possible prices, reflects several factors (e.g., the voluntary nature of the program, the benefit of advance notice, the absence of penalties, and a price level below that of existing mandatory curtailment programs), and removes the opportunity for participants to manipulate the system to their advantage.
9. DBP customers should not be permitted to simultaneously participate in multiple programs with the potential for being paid twice for a single event, such as ISO's Demand Relief Program, ISO's Ancillary Services Load Program, and California Power Authority's new Demand Reserves Program.
10 SCE is concerned that it may approach its annual cost cap of $137.5 million.
11. A cost cap increase of $10 million for SCE will fund about 47 MW of DBP load relief for 10 hours per day for 60 non-holiday weekdays.
12. Any utility's failure to follow adopted procedures to increase the interruptible program cost cap 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, is unreasonable absent the utility presenting a very compelling reason to the contrary.
13. Utilities need no further assurance of cost recovery at this time.
14. The public interest in quickly modifying the DBP outweighs the public interest in having a full 30-day comment cycle on the draft decision.
1. The DBP should be revised to permit ISO to employ DBP as needed in other than three four-hour time blocks on either a day-ahead or day-of basis.
2. DBP should be transitioned to a reliability program at a single incentive payment level of $0.35/kWh.
3. DBP should be funded by utilities and DBP expenses should be allowed to be recorded in each utility's interruptible program memorandum account.
4. Each utility should evaluate DBP bids within its service area and accept bids from reliable customers (taking past performance into account) on a first-come first-served basis, also considering need and cost.
5. SCE's interruptible and curtailment program cost cap (D.02-04-060, Ordering Paragraph 19) should be increased by $10 million, to a total of $147.5 million.
6. The period for public review and comment on the draft decision should be reduced.
7. This proceeding should remain open.
8. This order should be effective today so that the revised DBP may be implemented without delay to protect public health, safety and welfare.
DEMAND BIDDING PROGRAM
IT IS ORDERED that:
1. Within five days of the date of this order, respondent utilities Pacific Gas & Electric Company, Southern California Edison Company (SCE), and San Diego Gas & Electric Company shall each file and serve an advice letter with revised tariffs. Each advice letter with revised tariffs shall implement revisions to the demand bidding program described in this order and in Attachment A. Each advice letter with tariffs shall be in compliance with General Order 96-A. Each advice letter with tariffs shall become effective five days after filing, unless suspended by the Energy Division Director. If any advice letter with accompanying tariffs is suspended by the Energy Division Director, the advice letter and tariffs shall become effective upon the date the Energy Division Director determines that the tariffs comply with this order. The Energy Division Director may require a respondent utility to amend its advice letter and tariffs to comply with the orders herein. Respondent utilities shall work with the Energy Division Director and staff to prepare advice letters and tariffs that are consistent with the orders herein, and reasonably consistent among utilities.
2. The total annual program dollar limit for SCE (Decision (D.) 02-04-060, Ordering Paragraph 19) is increased by $10 million to a total of $147.5 million.
3. This proceeding remains open solely to address the February 20, 2002 petition for modification of D.01-09-020 filed by Dr. Lee F. Walker and the
May 22, 2002 petition for modification of D.02-04-060 filed by California Industrial Users and California Large Energy Consumers Association.
This order is effective today.
Dated _______________, at San Francisco, California.
ATTACHMENT A
DEMAND BIDDING PROGRAM
The Demand Bidding Program (DBP; see Decision 01-07-025; Attachment A) is replaced with the following program:
2.6 Demand Bidding Program (Revision 1.0)
2.6.1 The Offer
2.6.1.1 The California Independent System Operator (ISO) shall notify each utility distribution company (UDC) when demand bidding program (DBP) load relief may be needed. For purposes of this program, the triggering event will be an ISO 24-hour Alert Notice, which is the first indication that there potentially will be less than 7% operating reserves within the next 24 hours. UDCs will trigger a day-ahead event based on receipt of this Alert Notice from the ISO by 2pm on the day preceding an event, and either a day-ahead or a day-of event based on an Alert Notice from the ISO after 2 pm on the day preceding or day of an event. UDCs shall not solicit bids from DBP participants until the UDC reasonably expects Stage 2 or Stage 3 to be forecast or implemented sometime within the 24-hours following the ISO Alert Notice.
2.6.1.2 Participating customers shall submit bids to a DBP website. UDCs may also notify customers via the internet and other means of communication as needed of DBP events on a day-ahead basis.
2.6.1.3 Each DBP participant shall have one hour from notification of DBP bid solicitation to submit a bid. A bid may be submitted beyond one hour after notification of bid solicitation, but the utility need not give equal consideration to late and timely bids. In evaluating late bids, the utility must consider then current conditions, including previous acceptance or rejection of timely bids submitted within the first hour. Bidding shall be accepted for non-holiday weekdays only.
2.6.1.4 Participants shall indicate the amount of kilowatt (kW) curtailment they are offering and the specific times. Bids shall be submitted with a minimum duration of two hours, with no more than one bid per day.
2.6.1.5 DBP load reductions shall be paid at the rate of 35 cents ($0.35) per kilowatt-hour.
2.6.2 DBP Offer Evaluation and Confirmation
2.6.2.1 Within one hour after the bid submission deadline, each UDC shall evaluate each bid timely submitted within its service area, accept or reject each bid, and notify each bidder of the result.
2.6.2.2. A primary criterion for accepting bids shall be reliable offers (taking bidder past performance and compliance into account) on a first-come first-served basis. If preliminary meter data indicates that a customer is not entitled to receive compensation for three consecutive events, such customer should thereafter be precluded from participating in the following two operations of the DBP.
2.6.2.3. To the fullest extent reasonably possible, each utility shall also limit bid acceptance to use of DBP curtailments only during forecast or actual Stage 2 and 3 events, shall not accept DBP bids unless and until all resources reasonably known to be less expensive are first employed (e.g., traditional interruptible programs), and shall limit bid acceptance to only the amount of kW needed to satisfy ISO reliability criteria.
2.6.3 DBP Performance Verification and Payment
2.6.3.1. The UDC will track the curtailment of participating customers. The UDC will review the performance meter data against the accepted bids and calculate the payment due to the participating customers, with payments based on actual performance.
2.6.3.2 Each UDC shall pay the incentive amounts due to individual participants within 90 days of the DBP curtailment event.
2.6.3.3. Program expenses may be tracked in the memorandum account authorized to track interruptible program expenses. (Decision (D.) 01-04-006, Ordering Paragraphs (OPs) 15 and 16; D.01-07-029, OPs 2 and 3; D.02-04-060, OP 19.)
2.6.3.4. Participants will only be paid for a maximum of 150 percent of their accepted bid kW load drop measured on an hourly basis. Participants must drop at least 50 percent of their bid load drop to qualify for any payment in any hour. In no case will a customer be paid an incentive if load drop does not meet 10% of the customer's average annual demand but not less than 100 kW.
2.6.3.5 Baseline load for measuring load drop will be computed pursuant to the Voluntary Demand Response Program (VDRP) methodology.
2.6.3.6 Once a bid has been accepted, the accepted bid shall not subsequently be rejected by the utility, but payment shall continue to be based on the customer's actual performance.
2.6.3. Participation Requirements
To participate in the program, customers must meet the following minimum requirements:
2.6.4.1. Individual bids should be a minimum of 10 percent of each customer account's average annual demand, but not less than 100 kW per customer account. No aggregation of customer accounts will be allowed.
2.6.4.2. Customers must have an interval meter. For customers over 200 kW the meter will be provided pursuant to the CEC's real time electric meter (RTEM) program, based on available funding. For customers under 200 kW the meter will be provided pursuant to VDRP procedures under which expenses are recorded in a memorandum account for future rate recovery. Customers who receive meters at "no charge" will be obligated to perform in at least 10 events, if bids are requested and the customer's bid is accepted, and remain on the program for one year consistent with existing tariff provisions of the VDRP.
2.6.4.3. DBP customers may not also be enrolled in the ISO's Demand Relief Program, the Participating Load Program, also known as the Ancillary Services Load Program, or the California Power Authority Demand Reserves Program. Customers may achieve load drop by operating back-up or onsite generation. The customer will be solely responsible for meeting all environmental and other regulatory requirements for the operation of such generation.
(END OF ATTACHMENT A)
