5. Adopted Improvements to Current Interruptible Programs and New Programs

Parties' comments and reply comments on the Energy Division Report, plus the March 16, 2001 DD, were extensive and constructive. We concentrate in the following sections on our adopted programs and the chief points of contentions. We do not try to summarize or address every argument or nuance in the comments and reply comments.

5.1 Opt-Out and Realignment of Firm Service Level

Probably the most contentious issue is whether or not to continue the temporary suspension adopted in D.00-10-066 of the portions of SCE's interruptible tariffs that would otherwise allow customers to either opt out of the program or change their firm service level. For the many reasons stated by nearly all parties who addressed this issue, we are persuaded to allow SCE's customers to opt-out or change firm service level without complicated conditions. We allow customers to select an effective date for this change of either November 1, 2000, or the date consistent with the beginning of their next billing cycle.⁵

The underlying premise of SCE's program was that interruptible customers were allowed to opt out or change firm service level with advance notice of five years. This five-year notice was modified in 1998 to an annual opt-out or change in firm service level because of the transformation of the electricity market (e.g., deregulation, creation of ISO and Power Exchange). Customers began to rely on the ability to reassess their situation annually.

We temporarily suspended the annual opt-out or change in firm service level option in D.00-10-066 while we considered matters further. We are now persuaded to lift the suspension.

Interruptible customers say they used reasonable and realistic assumptions in their analyses, and made careful judgments of risks and rewards, before making decisions about opting out or adjusting firm service levels. They argue that the electricity system is now operating outside any reasonable bounds that could have been used in their analyses, and that this fact justifies allowing customers to opt-out or readjust.

We agree. The electricity system is operating outside any reasonable bounds, or any realistic assumption customers could have been expected to use.

For example, on January 17, 2001, Governor Gray Davis proclaimed a State of Emergency. This proclamation is based on electricity shortages resulting in blackouts for millions of Californians, and dramatic increases in electricity prices threatening the solvency of California's major public utilities. The Governor also found that the imminent threat of widespread electricity disruption constitutes a condition of extreme peril to the safety of persons and property within the state. Among other things, he directed the California Department of Water Resources (DWR) to begin procuring electricity to mitigate the effects of the emergency. It is unlikely that any customer could have realistically foreseen such dramatic events as those that led the Governor to declare a State of Emergency.

Nine days later, the threat to public health and safety justified our suspending penalty provisions for failure to curtail when requested by the utility, along with the tolling of hours and number of curtailment events. (D.01-01-056, January 26, 2001.) We said:

"Interruptible customers now face increasingly serious consequences of being on interruptible tariffs, despite their voluntary choice to have subscribed for interruptible service, and their obligation to abide by the terms of the tariff...The continuing electricity crisis, however, requires that we reassess the operation of our interruptible programs.

"These customers face the ongoing choice of curtailing electric service, or paying significant penalties. If they curtail service, for many customers this means closing their operations or businesses, with deleterious effects on themselves and the California economy. The harmful effects include lost sales, lost revenues, lost productivity, foregone wages, layoffs, unemployment, business not expanding in California, and businesses moving out of California. For some customers, such as hospitals and prisons, this choice threatens public health and safety. Alternatively, customers can continue to operate and incur large penalties. These penalties may threaten the financial integrity of their operations and businesses, and have the same deleterious effects on the California economy.

"Neither alternative is acceptable. Customers essentially face an irreconcilable dilemma." (D.01-01-056, mimeo. page 5.)

Thus, market conditions have dramatically changed from those that existed in prior years.

Normal changes also justify lifting the suspension. That is, businesses and other customers (e.g., universities) grow, modify processes, and make other changes over time. It is reasonable to allow customers to periodically reassess their situations and either opt-out or change firm service levels to better match current market and business realities with their abilities to interrupt load.

Lifting the suspension now will allow customers to make necessary and reasonable changes. Among other things, this will permit respondent utilities and the ISO to have a more reliable base of interruptible load for Summer 2001. We believe that this will give utilities and the ISO more knowledge of the truly available interruptible resources from which to manage conditions this summer, without relying on or expecting penalties to drive customer compliance. We believe perfecting the base for Summer 2001 is further justification for lifting the suspension now.

We are also persuaded by several customers that SCE marketed its interruptible program differently than did PG&E or SDG&E. Addressing these differences now simply distracts us, SCE and its customers from the immediate task of finding workable solutions for Summer 2001. We think lifting the suspension now promotes the best opportunity for current and future participation.

We decline to adopt the limited opt-out or adjustment in firm service level proposals in the Assigned Commissioner's March 16, 2001 DD. Those proposals would allow opt-out or readjustment based on one of four methods.⁶ The methods are creative, and would seek to promote desirable and equitable outcomes for Summer 2001. We choose, however, to focus on new programs and solutions for Summer 2001 rather than restructuring prior obligations to meet current market realities.

Moreover, each particular method presents complications. For example, the first three methods involve potentially complex and controversial calculations. In addition, some parties point out that option one creates inequities between a customer who has complied with interruptions and one who has not. Other parties point out that under the second option the equipment which is or is not certified as energy efficient for this purpose is not well defined, and it is unclear what happens if the customer fails to invest to the required level by July 1, 2001. Further, they state that it will take time to engineer, order and install such equipment, and some, if not many, customers cannot meet the July 1, 2001 deadline.

According to some parties, calculation of the equivalent kWh for another program based on what would have been required under SCE Schedule I-6 presents opportunity for interpretation and disputes under the third option. Finally, other customers might realistically ask to be included in the unconditional fourth option.

While more precise formulas, additional rules, deadline extensions, and other remedies, might be devised, we decline to try to perfect the four options. Rather, we believe the limited time and resources of the parties and Commission are best devoted to more positive solutions for Summer 2001.

As a result, we lift the suspension of the opt-out or change in firm service level options. We allow customers to elect to opt-out or change firm service level during a 15-day window beginning upon service of notice to customers of this option. SCE must provide written notice to each affected customer within 10 days of the date the tariff becomes effective, including a calculation of the effect of selecting the November 1, 2000 date. In addition to this opt-out or readjustment, lifting the suspension means customers may annually reassess and make changes as necessary beginning in November 2001.

We allow the customer to choose the effective date of the current opt-out or adjustment. The date may be either November 1, 2000, or a date consistent with the beginning of the next billing cycle.⁷ We allow the choice back to November 1, 2000 since many customers would have selected this time period in November 2000 if it had not been temporarily suspended by D.00-10-066. Moreover, the market became particularly chaotic in November 2000, when the number of Stage 2 and Stage 3 events began to increase.⁸ The November 1, 2000 date, however, requires that the customer repay the discounts received from November 1, 2000 through the present, but not pay any otherwise incurred penalties for failure to curtail when asked during that time.

An election in November 2000 to opt-out or change firm service level would not have resulted in a change until shortly after November 1, 2000. While we could order the date that would have otherwise resulted, such approach would make this option unreasonably complicated. A uniform date will promote administrative ease, customer understanding, and minimization of disputes. On balance, it is desirable to essentially let customers undo the temporary suspension if they wish, but not make it unnecessarily complex. For the same reason, we decline to order collection or payment of interest.

Alternatively, the customer may opt-out or change firm service level effective with the beginning of the next billing cycle. This is consistent with SCE's current practice, and will promote consistency and simplicity. A customer electing this option will retain the rate discount for interruptible service through the date of any change in schedule or firm service level. The customer will, however, be obligated to pay any penalties incurred for failure to interrupt when asked by the utility under the interruptible schedule through the time the opt-out or adjustment in firm service level is effective.⁹ As described below, penalties that might otherwise occur from the reinstatement of penalties with this decision until the effective date of the opt-out or change in firm service level will be waived.

Further, for reasons explained below, we do not allow customers who opt-out during this 15-day window to participate in the ISO's DRP and Ancillary Services Load Program. We also decline to allow such customers to participate in any other respondent utility program that pays a capacity payment (i.e., the new base interruptible program described below). This limitation will prevent unreasonable turnover between similar programs without benefit to the state.

5.2 Other Modifications to Existing Programs

We make other modifications to existing programs, largely as recommended by Joint Parties. First, we extend the programs of PG&E, SCE and SDG&E to December 31, 2002. Existing tariffs are otherwise scheduled to expire (sunset) on March 31, 2002. We agree with Joint Parties that the need for these programs is unlikely to end in 2001, or by March 31, 2002. To the extent these programs are successful, they should be continued at least through the Summer of 2002, and we think reasonably to December 31, 2002.

At the same time, many structural changes are being made to the electricity market. We hope these changes will soon be successful in realigning demand and supply, and bringing prices back to just and reasonable levels. Interruptible programs are very expensive. We cannot reasonably extend expensive programs without limit. Rather, we extend the sunset for a specific, limited duration to December 31, 2002, and will reconsider extensions and program redesign as necessary for use beyond December 31, 2002.

We also limit program use to one 6-hour event per day, 4 events per week, and 40 hours total per month. We do this to reasonably extend the programs in light of the experience in January 2001. In January 2001, interruptible customers were asked to curtail load almost continuously. As a result of that experience, in late January 2001 we suspended interruptible program penalties, along with the tolling of events and hours. (D.01-01-056.) PG&E's program was almost completely exhausted before it was suspended.

PG&E and SCE customers were in particular pressed to the limit by the number and duration of interruption calls. Customers faced an irreconcilable dilemma of choosing to curtail electric service almost continuously, or paying significant penalties. (D.01-01-056, mimeo., pages 5-6.) This is simply not acceptable. It places unreasonable expectations on customers, and too quickly exhausts programs in a manner not necessarily in the best interests of the State. As a result, we limit exposure to interruptions to reasonable limits per day, week and month so that the remaining portions of these programs are useful for the remainder of 2001 and 2002, without unreasonable burdens on customers.

Joint Parties propose that the utility may terminate the customer's subscription under the interruptible tariff and return the customer to the otherwise applicable rate schedule if the customer does not achieve its firm service level for three consecutive curtailment events. We decline to adopt this proposal. This vehicle could otherwise be used strategically by a customer to transfer to another rate schedule without reasonably fulfilling its obligations. We think the better approach is to make existing programs more reasonable, as we do above, including limited opt-out and firm service level adjustments available during a 30-day window.

SDG&E asks that we adopt reasonable limits on interruptions for Schedules AV-1, A-V2, and RTP-2. In support, SDG&E says a unique provision in its interruptible tariffs requires SDG&E to interrupt customers during a system emergency even when the customers have reached their maximum hourly limit. For example, in January 2001, SDG&E says customers on its Schedules A-V1 and A-V2 were notified of the need to interrupt almost every day. According to SDG&E, this notice led many customers to terminate service on these schedules because of the undue hardship.

SDG&E points out that Schedules A-V1 and A-V2 now contain an annual limit of 80 hours of interruptions when SDG&E's system load exceeds a prescribed level. According to SDG&E, however, none of the interruptions this year have been due to SDG&E system load exceeding the prescribed level. Rather, SDG&E says all curtailments were called in accordance with the system emergency clause in SDG&E's tariffs, which requires SDG&E to curtail interruptible customers when the ISO calls for such interruptions during Stage 2 and 3 events. SDG&E asserts that this clause is unique to SDG&E's interruptible tariffs.

SDG&E says customers have simply begun to shift off of these interruptible tariffs because there are no limits to the amount of curtailments that SDG&E can call in the event of a system emergency, and there seems to be no end in sight for ISO-called emergencies. SDG&E interruptible customers can opt out from interruptible service at any time after being on the rate for 12 months. As a result, SDG&E says more customers will move to firm service absent a fixed annual limit to curtailments. SDG&E recommends that the Commission delete the "emergency circumstances" exception and adopt fixed annual limits. We agree in part.

We retain the emergency circumstances exception in SDG&E's tariffs to allow response to statewide emergencies. At the same time, however, we limit the customer's exposure to all interruptions, including the emergency circumstances, to 120 hours per year. We increase the limit from 80 hours because the emergency circumstances exception allowed more exposure than 80 hours, and we think reducing the exposure to 80 hours now in the face of a possibly difficult Summer 2001 would be unreasonable. PG&E's program is limited to 100 hours of interruptions, and SCE's program is limited to 150 hours. We think 120 hours is, on balance, a reasonable maximum for SDG&E customers, bringing the exposure from an unlimited amount to a level comparable to that faced by other respondent utility customers. This is also reasonable in light of the limits we adopt above on the exposure per day, week and month.

SCE asks that we clarify that the extension of existing programs means they are reopened for all customers. We decline to do that. Rather, for example, existing and new customers not in an existing program should consider the new base interruptible program, or other programs described below. On the other hand, we specifically identify the programs herein when they are reopened to existing and new customers (e.g., SCE's air conditioning cycling program).

5.3 Insurance

We also address the issue raised by Caliber One Indemnity Company (Caliber One). Caliber One requests a Commission determination of whether or not interruptible customers have the option of willfully refusing to comply with interruption notices without breaching their obligations. Caliber One contends that willful refusal to curtail undermines or defeats the goals of the interruptible service program, or renders an interruptible tariff and its rate structure unlawful, unjust, unreasonable, or discriminatory. Caliber One raises this concern in particular with SCE's Schedule I-6. Additionally, if the Commission finds such behavior constitutes breach or violation, Caliber One requests that the Commission act to fix the Schedule I-6 tariff, interruptible rate contracts, and, if deemed appropriate, the insurance policies between SCE's customers and Caliber One.

We agree with PG&E's response on these issues. (February 26, 2001, page 4.) There is nothing in current interruptible tariffs that limits a customer's right to continue using electricity during curtailment periods. The customer makes the choice to curtail or not curtail based on any number of factors, including safety and economics. Customers are subject to substantial penalties for failing to curtail, however, and apply appropriate caution when making such decisions.

Caliber One asks that the Commission "determine, at a minimum, whether willful refusal to comply with Interruption Notices constitutes a breach of the Interruptible Service Contract and renders the I-6 Tariff and its rate structure unlawful, unjust, unreasonable or discriminatory." (Opposition of Caliber One, March 2, 2001, page 2.) We find that under current interruptible tariffs it does not.

Moreover, we agree with PG&E that the existence of this contract right not to curtail has been crucial to the efficient and effective administration of this program. For example, the existence of this provision has forestalled a great number of separate petitions for individual tariff deviations that might otherwise have been engendered over the course of each summer during which these programs have been operated.

Caliber One cites Public Utilities Code Sections 701, 728 and 743(f) in support of its position, alleging that these sections give the Commission jurisdiction over the insurance agreement between an SCE customer and Caliber One. We disagree for the reasons stated by SCE and the Internal Services Department of County of Los Angeles (ISD/LAC).¹⁰ These code sections give the Commission authority to regulate public utilities. Customers of SCE are generally not public utilities.¹¹ Caliber One does not claim to be, and is not, a public utility.

We also regulate contracts between utilities and customers to ensure that:

"...utility management has not agreed to provide service under unreasonably favorable terms and conditions to the contracting individual or entity. Such an agreement, potentially subsidized by customers subject to regulated rates, would indicate management was acting to violate Pub. Util. Code §§ 451 and 453 which, respectively, prohibit unjust and unreasonable rates and undue discrimination among customers." (D.99-07-014, 1999 Cal. PUC LEXIS 481.)

We may require a public utility to file contracts between the utility and its customers. We may examine a private contract to the extent it is between a utility and a customer and might involve utility violations of the Public Utilities Code. The contract between a utility customer and an insurance company, however, even if it incorporates a regulated tariff, does not fall into this category.

Caliber One contends that the Commission must determine whether the Schedule I-6 tariff is unlawful, unjust, unreasonable, discriminatory or preferential when customers willfully refuse to curtail, including "rules, practices or contracts affecting such rates or classifications..."(Pub. Util. Code § 728, emphasis added). Caliber One argues that the insurance policies and agreements incorporate the Schedule I-6 tariff, and thereby bring the insurance contract under Commission jurisdiction. We disagree. We regulate the terms and conditions of interruptible tariffs, and contracts between utilities and customers. We do not regulate agreements between a customer of a public utility and another party, third party contracts not involving a public utility, or agreements between non-public utilities, whether or not the agreement references a regulated rate or tariff.

Caliber One asks that parties be given a chance to submit written comment on the issue framed by Caliber One's intervention. While we could give additional notice and opportunity for comment, we will not burden parties and the Commission further on this matter. Parties had the opportunity to file responses to the December 14, 2000 Caliber One motion to intervene and statement of issues. Parties had the opportunity to address Caliber One's issue in additional comments filed and served on December 21, 2001.¹² Caliber One raised its issue in comments filed on the Energy Division Report. Parties had the opportunity to file reply comments on February 26, 2001.¹³ Moreover, ISD/LAC filed a motion on February 20, 2001 to strike Caliber One's statement of issues, Caliber One responded in opposition on March 2, 2001, and LAC replied on March 8, 2001. Adequate notice and opportunity to comment have been given on this issue. We need nothing further from parties on either our jurisdiction or their recommendations before we make our decision.

We address one aspect of this issue going forward. There is no dispute that the Commission has jurisdiction over interruptible tariffs, and eligibility for those tariffs. We find that current tariffs do, and future tariffs should, allow customers to make the decision whether or not to curtail.

We agree with Caliber One that willful refusal to curtail, however, may defeat the public purpose goal of the interruptible program in the specific instance where the customer shifts the risk of penalties from itself to others by use of an insurance policy. We do not expect customers to subscribe to an interruptible tariff for the purpose of obtaining a rate discount but with no intention of honoring an interruption request. Customers now and in the future may willfully refuse to interrupt for any number of reasons, and pay the penalty. Unless there are reasonable eligibility restrictions, however, some customers might buy insurance against non-compliance penalties. This could result in the interruptible customer failing to interrupt to the detriment of all other ratepayers.

To cure this possible defect, we adopt SCE's proposal to modify eligibility for interruptible tariffs by way of a declaration. Existing and new customers will not be eligible for continued or new subscription to interruptible tariffs unless they file a declaration under penalty of perjury with the utility. The declaration must state that the customer does not have, and will not obtain, any insurance for the purpose of the insurance paying non-compliance penalties for willful failure to comply with requests for curtailment. Any customer with this insurance after the effective date of this tariff eligibility condition will be terminated from the tariff, and will be required to pay back the rate discount for the period covered by the insurance. If the period cannot be determined, the recovery shall be for the entire period the customer was on the tariff.

Respondent utilities shall provide written notice to each potentially affected customer of this condition within 10 days of the effective date of the tariff. The declaration will be due to be filed with the utility within 30 days of the service of notice, and this tariff condition shall become effective 30 days after service of notice to the customer.

There may be situations where insurance is still reasonable, however, such as loss of business, or damage resulting from a curtailment. Insurance may be obtained for such other purposes.

5.4 Lift Suspension of Penalty Provisions

With these modifications and improvements to the interruptible tariffs, we lift the suspension of penalty provisions imposed by D.01-01-056. That is, the tariffs filed pursuant to this interim order shall include penalty provisions for interruptible electricity service customers when a customer fails to curtail for any reason at the request of utility. The tariffs shall include the tolling of hours and number of curtailment events against program maximums, and any other related elements of the tariffs, which were suspended by D.01-01-056. Each respondent utility shall notify each affected customer within 3 days of the date the tariff becomes effective. The penalties, tolling of hours, tolling of numbers of curtailment events, and other provisions, will become effective 3 days after the date of service of the notice.

These reinstated penalties will not apply, however, for any customer who opts-out effective November 1, 2000 and repays discounts. Similarly, these penalties will not apply from November 1, 2000 forward to the extent the change in firm service level negates penalties, and discounts are repaid.

Further, reinstated penalties will not apply, or will be waived, for any customer who opts-out or changes firm service level (to the extent the change in firm service level negates the penalty) going forward. This is, reinstated penalties will not apply from the date reinstated (e.g., 16 days from today) through the date the opt-out or change in firm service level is effective (i.e., the beginning of the next billing cycle).

5.5 New Base Interruptible Program

The Energy Division Report shows that traditional interruptible programs give reliable load reductions, and important benefits to both interruptible customers and the State. For example, PG&E's program has a very high compliance rate with about 400 MW of interruptible load. SCE has had a lower compliance rate, but has produced about 1,200 MW of dependable interruptible load. SDG&E has had good compliance with about 40 MW of interruptible load. Interruptible customers have enjoyed about $220 million per year in reduced rates or payments, and the State has had the benefit of over 1,600 MW of performing interruptible load.

PG&E's program has been nearly fully exhausted for 2001, however, based on its extensive use in January 2001. Similarly, SCE's program is about half exhausted, and may be fully exhausted in a few months. Further, a new program may be more attractive to some new customers than the existing program. Thus, a replacement program is necessary.

Therefore, we adopt a modified version of the "enhanced interruptible program" proposed by Joint Parties. (Item II.B.4 in the February 14, 2001 Joint Proposal.) To distinguish this from other programs, we call this the new Base Interruptible Program (BIP). This program will be operative all year. Program details are stated in Attachment A.

Among other benefits, this program provides some security of monetary benefit (i.e., a fixed capacity payment in dollars per kW-month). This type program has a place in an overall portfolio of programs. For example, customers who incur up-front costs for program participation (e.g., investment in equipment or facilities to produce load reductions) are assured of at least some financial return for making their resources (i.e., load reduction) available.

We decline to adopt the provision that three consecutive failures to comply will result in the participant being removed from the program. For the reasons stated above, we believe this provision may be used strategically by a customer to transfer to another rate schedule without reasonably fulfilling its obligations. That is, after obtaining several months of benefits, a customer might fail to comply in order to be transferred. Under some conditions, the customer would benefit, but other ratepayers would not. As a result, we do not adopt this provision absent further information to assure us of its reasonableness.

5.6 Voluntary Demand Response Program

We also adopt a modified version of the "day ahead" and "day of" programs proposed by Joint Parties. (Items II.B.1 and II.B.2 in the February 14, 2001 Joint Proposal.) To identify this program from other programs, we call this the Voluntary Demand Response Program (VDRP). This program will be operative all year. Program details are stated in Attachment A.

Among other benefits, this program provides flexibility for customer participation, with payments based on performance. This type of program also has a place in an overall portfolio of programs.

This program will be implemented by respondent utilities. We decline to adopt a price determined by the "market" (e.g., bidding by participants, or reliance on a "market maker" such as an entity like the former Power Exchange). We do not use a market approach since we are not convinced we have an efficient market which will result in just and reasonable prices.

At the same time we are convinced by parties that we need a reasonably simple approach for this program to be successful. Most customers, even big customers, state that their business is conducting their business, not buying and selling electricity, and not constantly monitoring the electricity market to make decisions about buying electricity or curtailing their operations.¹⁴ We determine that a fixed rate is necessary, subject to modification as needed, to balance efficiency and simplicity.

We decline to adopt Energy Division's recommendation of $0.15/kWh as too low given the reality of prices in the currently dysfunctional market. We similarly decline to adopt Joint Parties recommendation of $0.50/kWh to $0.75/kWh as too high. While prices are in this high range (or even higher) at some times in today's broken market, we cannot sanction continuation at these unacceptable levels. Moreover, we reject Joint Parties recommendation of $0.50/kWh for day ahead, and $0.75/kWh for day of, markets. A dual rate is needlessly complex, and will unreasonably encourage customers to withhold supply, waiting for the higher rate.

We balance competing proposals and adopt a rate of $0.35/kWh. This rate may be offered on a day ahead, or day of, basis as respondent utilities determine necessary, reasonable and useful. Respondent utilities may accept or reject bids based on need, order received, and experienced reliability with the customer.

Participating customers will enjoy not only the $0.35/kWh, but also the savings for the amount of electricity they do not buy from the utility. If an energy rate otherwise not paid is $0.05/kWh, for example, the customer enjoys a total of $0.40/kWh.

Respondent utilities may file advice letters as necessary to adjust this rate. Because we need to respond with some dispatch, we will reduce the protest period to 10 days. Based on the urgency for a rate change, we may also reduce the comment period on the draft resolution at the time it is issued.

If particularly urgent conditions exist, a party may file an urgent or emergency petition for modification. The petition may seek an immediate order increasing or decreasing the adopted $0.35/kWh rate. If necessary, the Assigned Commissioner may rule on the petition by ACR, with Commission approval or confirmation as soon as reasonable thereafter.¹⁵

We will not authorize rate adjustments often, however, absent exceptionally compelling justification. Rather, we seek to promote stability at a reasonable rate in this market. If anything, we think $0.35/kWh may be unreasonably high, and we look forward to the market stabilizing at a lower rate, with utilities or parties filing advice letters or petitions to lower the rate. We will consider rate increases, however, if the market continues to be dysfunctional, and higher rates are needed to promote public health, safety, welfare and system reliability.

Customers incur cost and inconvenience for participating in this program. As a result, we adopt a modified version of Joint Parties recommendation for a minimum payment to promote equity and efficiency. It is equitable to compensate customers for at least some of their cost and inconvenience for participation. Moreover, without some minimum payment, we are persuaded by parties that fewer customers will participate, and some efficiency would be lost. Thus, once a bid is accepted, we authorize respondent utilities to pay the customer even if the interruption is cancelled at the lesser of the hours bid, the hours requested, or 2 hours.

SDG&E expresses concern that the criteria for VDRP (as well as BIP) require a minimum of 670 kW of average demand (i.e., a reduction of at least 15% of load, with a minimum load drop of 100kW). SDG&E points out that the minimum demand requirement in the Joint Proposal is 300 kW, with the

minimum load drop the higher of 100 kW or 15% of demand. Further, SDG&E says the Joint Proposal allows utilities to lower the minimum at their discretion. SDG&E asserts that limiting participation to customers larger than 670 kW means the programs will be available to fewer than 500 customers in SDG&E's territory, severely reducing the potential for program success. SDG&E seeks modification of the March 16 DD to reflect its smaller customer base.

We clarify that the adopted programs allow a minimum of 100kW, not 300 kW or more. Application of the 15% minimum means that a 100 kW customer would need to drop 100% of its load to participate, and a 300 kW customer would need to drop 33% of its load to participate.

Moreover, we go beyond the 300 kW minimum recommended by Joint Parties, and reduce the minimum to 100 kW to seek maximum participation. We decline to allow utilities to further modify the threshold at their discretion. Rather, we seek some uniformity in programs, and will adjust minimums based on experience as petitions, motions, proposals and other pleadings are brought to our attention.

5.7 Air Conditioner Cycling Programs Plus Agricultural Pumping Programs

We adopt Joint Parties recommendation to allow respondent utilities to reopen and expand current air conditioner cycling programs for residential and commercial customers. Since only SCE has an existing program, we authorize SCE to reopen its current program to all residential and commercial customers at all cycling options.¹⁶ (See Attachment A.)

SCE's current program is limited to 15 interruptions of up to 6 hours. We are persuaded that additional options are necessary. Therefore, we adopt Energy Division's recommendation and authorize SCE to offer a new program.

The new program will pay double existing rates for an unlimited number of events, but no more than 6 hours of interruption in any one day. It will offer the same cycling options now offered (i.e., 50%, 67%, and 100% for residential; 30%, 40%, 50% and 100% for commercial).

We adopt the 6 hour limitation because we are convinced by TURN and others that satisfaction and participation will decline if the program is overused. At the same time, we balance competing interests and decline to adopt a limitation that the program cannot be used more than 3 days in a row for any one customer. If the program is needed, it must be available to the State. We rely on customers electing the cycling option (e.g., less than 100%) with a limitation of 6 hours per day as a reasonable balance.

We decline to adopt Energy Division's recommendation that a customer may increase, but cannot decrease, the commitment. Rather, if a customer enrolls in 100% cycling but is unable to meet that commitment, we allow the customer to downgrade once at no cost within 12 months, just as allowed in SCE's existing program. A customer may increase the cycling percentage at any time without cost.

We decline to adopt TURN's recommendations to limit the number of events to 10 per month. Customers who desire limits can subscribe to the current program, which we reopen. The higher prices offered in the new program justify this variation, which complement the limits in the existing program at lower prices.

Similarly, we do not eliminate the 100% cycling option as TURN recommends. We recognize TURN's concern that 100% cycling may be too severe for some customers, and result in poor customer satisfaction and retention. In response, we provide the option to downgrade once at no cost within 12 months. Moreover, we direct SCE to make a reasonable effort to inform customers of the effect of the 100% option, and how that may or may not be compatible with other requirements. For example, many buildings have closed air circulation systems. The 100% cycling option may compromise air quality in relation to state standards. SCE must raise this issue with customers when marketing the program, and let the customer determine which, if any, cycling options will produce a satisfactory result.

PG&E and SDG&E continue to object to air conditioner cycling programs, claiming they are not cost-effective, and that neither utility has the necessary infrastructure for program rollout. We are not convinced.

The CEC estimates that 14,000 MW of air conditioning load (28% of total load) occurs during the state's summertime peak demand of 50,000 MW, with about 7,000 MW (14% of total load) commercial, and about 7,000 MW (14% of total load) residential. Nearly 5,000 MW of reduced load could be achieved at peak if all air conditioners could be cycled at 33%, or if 33% of air conditioners could be cycled at 100%.

TURN strongly advocates air conditioner cycling programs as a cost-effective option. Comverge Technologies, Inc. reports that it can provide full responsibility for turnkey projects. Comverge says it can take the financial risk on a pay-for-performance basis, and can use existing paging companies for radio

communication. Moreover, signals can be used with a wide range of appliances, from air conditioners to electric water heaters, pool pumps, or other electric motors in residential, commercial or industrial settings.

This is a potentially vast, untapped source of interruptible electricity. Properly partnered with companies such as Comverge, respondent utilities and ratepayers can enjoy benefits with the providing company taking the financial risk. This opportunity needs further exploration.

Therefore, we order PG&E and SDG&E to explore reasonable options for implementing air conditioner cycling, and other electric motor interruption, programs targeted to residential and commercial customers. We similarly order SCE to explore reasonable alternatives for implementing an electric motor (in addition to air conditioner) interruption program, targeted to residential and commercial customers.

PG&E, SCE and SDG&E shall each file and serve an advice letter no later than May 1, 2001. The advice letter shall analyze and report on alternatives, and seek approval of the most reasonable alternatives, including proposed tariffs for implementation. The analysis of each alternative shall include cost, amount of load reduction, means to verify load reductions, and timeliness of implementation.

We caution PG&E and SDG&E that we are convinced one or more air conditioning cycling programs should be approved in each service area. This is the opportunity for PG&E and SDG&E to propose what each believe are the best options for their areas. That is, the advice letters of PG&E and SDG&E should seek approval of the options that each utility finds most reasonable.

We similarly adopt Joint Parties recommendation to reopen current interruptible tariffs for agricultural and pumping customers. SCE's tariff was generally closed to new customers in November 1996. We reopen SCE's interruptible tariff to all agricultural and pumping customers. Further, it is due to expire March 31, 2002. We extend it to December 31, 2002, just as we do above for all existing interruptible programs.

5.8 Optional Binding Mandatory Curtailment Program

Parties generally support an Optional Binding Mandatory Curtailment (OBMC) program if it is properly designed and operated. We adopt the OBMC program stated in Attachment A.

An OBMC program exempts customers from Stage 3 rotating outages in exchange for partial load curtailments during every rotating outage period. The customer is required to file an acceptable binding energy and load curtailment plan with the utility in which the customer agrees to curtail electricity use on its entire circuit by specified amounts. The customer's plan must show how reduction on the entire circuit can be achieved in various increments, and how compliance can be monitored and enforced. The burden is on the customer to demonstrate that the proposal is realistic, workable, measurable, and enforceable. At the same time, we direct respondent utilities to use the OBMC program as an opportunity to work with each interested customer to reach a solution not only in the best interest of that customer, but in the overall best interest of the electrical system.

The program protects large customers from the significant economic harm they might otherwise experience during a rotating outage. OBMC customers receive no payment. Rather, they benefit by exclusion from rotating outages. While this does not eliminate exposure to all outages (e.g., an unplanned or forced outage such as from a transmission line or transformer failure), it does eliminate exposure to Stage 3 rotating outages.

The current OBMC requires a plan showing load reductions by increments of 5% percent, up to a total of 20%, on the entire circuit. The 20% level corresponds to the total load that might be subject to rotating outage at any one time under our existing program.

We are persuaded by many parties, however, that 20% for OBMC is simply too onerous, and will substantially reduce the ability of customers to use this program. We must balance our overall system goal of up to 20% with a percentage that makes this program desirable and useful for as many customers as possible, and thereby incrementally more successful for customers and the state. The CMTA recommends 10%. We find this is too low. We adopt 15%, as recommended by Sun-Maid Growers of California.

Since the goal is load reduction on an entire circuit, several customers on a single circuit may file a joint binding plan guaranteeing the required curtailment on the entire circuit. We require utilities to facilitate joint curtailment plans by notifying customers of the program, and coordinating communication between customers on the circuit when any one customer expresses its intent to participate. Notification shall be performed within 21 days of this order to customers of 500 kW or more average peak demand.

SCE asks that utilities be permitted to release confidential customer information, such as customer names, to other customers on a circuit to facilitate customer communication and development of circuit-wide OBMC plans. We are not persuaded that other means are unavailable, however, and that a blanket order to release otherwise confidential information is reasonable.

For example, the notice to customers within 21 days of today may include the question whether or not the customer authorizes the release of its name, or other confidential information (e.g., average usage) to other customers on the circuit if any customer expresses interest in the OBMC. This may allow exchange of most, if not all, otherwise confidential information by the utility. Alternatively, one or more interested customers (or the utility) can arrange a

meeting, and prepare an invitation. The utility can mail the invitation to all customers on an individual circuit. The utility can attend the meeting to help explain OBMC and, as we direct above, use the OBMC program to meet the needs of both its customers and the overall electric system. Therefore, because we are not persuaded that reasonable alternatives are unavailable, we decline to adopt SCE's request.

The current OBMC program requires that a customer meet the criteria for economic damage. Those criteria are over 300 kW in size, major economic damage, or danger to health and safety. At least one party recommends reducing the economic damage amount to $50,000. We are persuaded to eliminate the criteria altogether.

Any customer, or group of customers, on a circuit should be eligible to participate in OBMC. We do not seek to limit them by size, potential economic damage, or possible danger to health and safety. Our goal is to make OBMC a viable choice for as many customers as possible. Eliminating the economic damage criteria in the face of the current State of Emergency best accomplishes that goal.

Parties raise concern over measurement of the baseline. For example, it may be measured over the last 10 days, or compared to consumption one year earlier. Failure to account for conservation efforts reduces the incentive to participate, while failure to recognize reasonable growth in demand from any number of factors may similarly penalize participation.

No single baseline measure is perfect. We balance competing interests by measuring 5% increments against usage over the last 10 days. This is the most up-to-date measurement reflecting current conditions when actual system conditions otherwise require mandatory curtailments. On the other hand, we measure the 15% total required reduction against the prior year's usage for the same month, average peak. As CMTA points out, this allows for some recognition of yearly variations and does not penalize customers for near term demand reduction efforts (e.g., conservation and efficiency in response to the Governor's February 2001 request for 10 percent conservation).

We also adopt a variation of language proposed by PG&E to clarify the baseline. The baseline used to determine if the required load reduction has been obtained will be the average demand for the same period using the most recently available past 10 similar business or weekend days. This will prevent comparison of off-peak with on-peak hours, or an average of low load early morning hours with other hours.

PG&E states it intends to apply an hourly comparison. This appears reasonable. We think that the comparison may be made on an hourly basis, or over the same consistent several hour period (e.g., several hours in a Stage 3 event). The basis for the comparison, however, must be specified by OBMC participants in their circuit plan, and must be accepted by the utility.

Finally, we clarify that OBMC participants are not foreclosed from contributing load reductions during Stage 1 or 2 events through the VDRP program, but are not eligible to be paid during an OBMC event. That is, during an OBMC event, their OBMC commitment supercedes participation in any other program.

5.9 SDG&E HVAC Program

There is broad theoretical appeal and interest in using market-based approaches to balance supply and demand, including real time meters and real time prices. In particular, the CEC supports wide use of market-based solutions.

When markets are dysfunctional, however, there are equity and efficiency problems with this approach. Moreover, there are other unresolved problems, such as the balancing of earned revenues with the revenue requirement.

Nonetheless, there is room in our adopted portfolio of approaches addressing the current crisis for the SDG&E heating, ventilation, and air conditioning (HVAC) program, as a variation on market based solutions. As such, we adopt Energy Division's recommendation for further study of SDG&E's potentially useful HVAC program. To facilitate this further study, we will provide meters and communication equipment without charge to customers who participate in the VDRP.

5.10 ISO Programs

Some parties advocate Commission reliance on ISO programs. Further, some parties recommend allowing respondent utilities to act as aggregators for ISO programs. We decline to adopt these proposals. Rather, we implement close coordination with ISO programs to maximize the benefits for the State.

We authorize programs in this decision that are similar to some programs offered by the ISO, but generally at a lower price. There is no net benefit to California for similar programs competing for subscribers at different prices. Rather, to the extent a participant chooses between programs (i.e., a customer who will participate but is simply selecting one program or another), the customer will select the program that pays the higher price. That does not result in any additional load reduction, only a higher cost to ratepayers.

As a result, we decline to allow a customer enrolled in a respondent utility program from enrolling in a similar ISO program, until the customer has fully exhausted the utility program.¹⁷ We will continue the current policy of prohibiting interruptible customers from participating in the ISO's Ancillary Services Load Program. Once the customer has exhausted the utility program, however, the customer may participate in the ISO similar program.

Customers may not opt-out of existing programs to enroll in an ISO program, or enroll in a similar new utility program. As explained above, this limitation prevents unreasonable turnover between similar programs without benefit to the state.

Where programs are different, the customer may join either the utility or ISO program without condition. For example, if the customer is in a utility capacity program, the customer may select either the utility or the ISO pay-for-performance program.

Finally, respondent utilities should spend their limited time and resources making programs adopted herein successful and fully utilized. Thus, we prohibit respondent utilities to act as aggregators for ISO programs. We will authorize the respondent utilities to act as aggregator for bids in the ISO's DRP accepted as of today.