IV. Demand Response Programs For Large Customers

Throughout this rulemaking we have stressed the importance of the policymaking vision and goals that serve as the foundation for building demand response programs that are sustainable over the long term. At the outset we noted that a perfectly functioning wholesale and/or retail electricity market was not a precondition for development of demand response, and we explicitly stated the value of demand response as "...a tool in mitigating the effects of a dysfunctional market, as well as for controlling costs, even in a completely vertically integrated and regulated market."16 However, adding this tool to our regulatory tool chest is not an easy task, and will require an iterative process as well as a multi-year commitment on the part of regulators, customers and utilities that involves the following: taking care to develop the programs that are workable and suitable for their intended purpose; listening to what the members of different customer classes tell us about their needs both explicitly and by their reaction to the programs we adopt; and both fine tuning and significantly adjusting these programs over the years, in a manner consistent with the need for stability in these programs. We cannot accomplish everything on our policy agenda in one decision, or even in a series of decisions. Instead, we must take the long-term view, even as we begin with a series of discrete steps. The challenges posed by large customer demand response are daunting and quite complex, requiring that we proceed deliberately, but with great care.

Although the WG2 participants agree on many principles, they have been unable to develop a consensus tariff proposal, given the diversity of views among large customer interests, respondents, and the other parties. As one party characterizes the situation, "to date, customer support for utility designed programs has been tepid, and utility support for third party proposals has been nonexistent."17

It is clear that large customers use electricity in ways that differ fundamentally from the ways in which other customers use it. For example, their electricity usage may be an essential component of an industrial or agricultural process. This means that as they consider load shifting or load reduction, such customers must also consider distinct and significant cost issues relative to their operating requirements, whether they be manufacturers, agricultural users, or building owners.18 All of these factors require us to make a careful assessment of the impacts of our decisions on these customers.

In retrospect, our focus on achieving a "quick win" may have made it more difficult for these customers to find common ground. At the outset, we encouraged the parties to focus on tariffs/programs that would achieve a "quick win" because we wanted to take advantage of the fact that many >200 kW customers already have advanced meters in place (due to AB29X) in order to learn how such customers would react to dynamic tariffs during Summer '03 and Summer '04, when system conditions for such a test should be ideal. However, we now know that some parties were reluctant to consider third party proposals, such as an innovative two- part RTP tariff, due to concern that such proposals could not be in place within a matter of months.19 As a result, in Phase 1 we address a relatively limited number of demand response options. However, as we shift focus beyond 2003, we will confront some of the structural and regulatory obstacles that may be impeding customer acceptance of demand response programs, and we will carefully refine our initial efforts and design new programs that will garner long-term customer support.

For now, this decision considers the merits of adopting CPP tariffs and a limited RTP tariff presented by SDG&E, as well as demand bidding programs - and the authorization of funding for these tariffs and programs through 2004. As these tariffs and programs will be in place well beyond 2004, our goal is to encourage as many large customers as possible to participate in them as a first step in a longer-term effort. This first step also involves careful recruitment and encouragement of participating customers, using modest incentives in the near term. The customers who participate in the tariffs/programs adopted in this decision are the vanguard of the customers who will participate in demand response programs during the coming years.

In its November 15th report, WG2 developed several design objectives that take into account the fact that no single program satisfies all large commercial customers.20 Some customers can use demand bidding programs to bid load reductions into the day ahead market, thus providing the electric system with an alternative source of supply. Other customers can reduce or shift their usage in response to posted day-ahead prices or critical peak signals, both of which are embodied in dynamic tariffs. While quite different in the degree of customer commitment, each response may yield market price and reliability benefits and more efficient energy usage decisions. This is the rationale for having a "portfolio," or mix, of demand response programs that will appeal to the greatest number of customers.

For example, in Phase 1 we are considering two demand bidding programs. Both are similar in allowing customers to shed load when market prices reach a set threshold. However one, the IOU DBP, is designed for customers not willing to make a firm commitment, who are paid solely for the energy reductions they actually choose to make. The other, the CPA DRP, has reservation payments scaled to firm commitments to shed load, measurement protocols to be sure that load reductions can be accurately measured, and penalties for failing to meet load reduction commitments. Some customers prefer the freedom of the former approach, while others prefer the security of a known payment stream provided by the latter. Under the design principles we adopt, it is conceivable that both features could be combined in a single offering for large customers.

Given the nature of large customer electricity usage, as discussed above, WG2 recommends that the 2003 tariff offerings should be voluntary. This could not have been an easy call, for mandatory programs avoid several problems endemic to voluntary programs. For example, in a voluntary setting, certain customers may elect to participate in a demand response program that benefits their particular load profile without motivating them to shift or reduce demand in any way. Other customers may simply choose not to participate in a voluntary demand response program, thereby diminishing overall demand response capability. However there are strong arguments against mandatory tariffs for large customers. Some of these customers simply are not able to respond to price signals because of the nature of their production methods. To force them onto a tariff that essentially raises their rates as they fail to respond seems unfair. And to raise their rates without a hearing is highly questionable.21 In view of these competing factors, the WG2 participants believe that there are too many complications to consider imposing a mandatory program on large customers in the near term.

Although TURN states that it lacked the resources to participate fully in WG2, it did file comments on the WG2 Reports, opposing the WG2 recommendation for a voluntary program for large customers. TURN cites the interruptible programs in place during 1992-2000, where customers who were confronted with the probability of interruptions after 2000 left the program in large numbers. TURN argues that large customer behavior has not changed in the past two years, and there remains a significant drop off in subscription for industrial demand reduction programs, especially for Edison, notwithstanding the utility's payment of millions of dollars of incentives over many years.22 TURN argues that this experience demonstrates that policy makers will never be able to attract large customers to demand side programs without guaranteeing these customers both an upside financial benefit and little or no downside risk. TURN believes the Commission must adopt a mandatory program for large customers, and proposes that all customer with demand greater than 200kW who have received free advanced meters from AB29X funds, be transferred to critical peak pricing on a mandatory basis.

TURN acknowledges that some of the details of this proposal, which was first detailed in its written comments and has not been vetted in WG2, remain somewhat general. Nonetheless it believes that the proposal, along with the Commission's June 1, 2001 rate increase, which allocated significant rate surcharges to the large customer class via surcharges for on-peak energy charges, will significantly improve the Commission's chances of achieving its demand reduction goals. It believes the Commission will find, upon investigation, that there is considerable evidence that the current rate design, which includes on-peak energy surcharges in the range of $0.20/kWh, is already providing large customers with meaningful price signals to reduce demand during these periods.23

We are at a very early stage in looking at price responsive demand reduction programs for large customers. The experience TURN cites comes from mandatory load curtailment programs, not price responsive programs, and it is not entirely clear that large customer behavior in the one area can be extrapolated to the other. There simply is no record at this point in the proceeding to reject the WG2 consensus view and impose a mandatory CPP on large commercial customers in the near term. Further, it is unclear in the context of price-responsive programs that mandatory response is even needed, unlike emergency programs that are designed to ensure reliable system operations.

In its November 15th report, WG3 presented six tariff and program proposals for our consideration, without recommending adoption of any specific one. Rather WG 2 recommended selection of a mix of the programs, consistent with the design objectives discussed earlier. Thereafter, on December 23, 2002, the respondent IOUs informed the ALJ that they wished to withdraw two of the earlier tariff proposals and substitute a new CPP proposal they felt would garner more customer acceptance. The ALJ permitted withdrawal of the two earlier IOU proposals and the submission of these new proposals in late December, and WG2 subsequently met to consider them, and then filed its third report on January 16, 2003. As a result, at the conclusion of Phase 1 we consider three dynamic pricing proposals: two are critical peak pricing tariffs (one presented by ACWA and the other known as the "Joint Utilities' CPP Proposal" or the "Joint Proposal," presented by the respondent IOUs), and the third is SDG&E' variation on the Joint Proposal, including the HPO tariff. We also consider two demand bidding programs, one presented jointly by the respondent IOUs and the other presented by the CPA. And finally, we consider two pilot programs: a proposal presented by IMServ known as the "Constrained T&D Capacity Proposal"24 and an real time pricing pilot presented by Infotility.25

1. Dynamic Pricing Proposals

In general terms, a dynamic rate allows rates to be adjusted on short notice, typically an hour or day ahead, as a function of system conditions. A dynamic rate cannot be fully predetermined at the time the tariff goes into effect; either the price or the timing is unknown until real-time system conditions warrant a price adjustment. Critical peak pricing tariffs and real time pricing tariffs contain dynamic rates.26

A critical peak pricing tariff includes a dynamic rate that allows a short-term price increase to a predetermined level (or levels) to reflect real time system conditions. In a fixed-period CPP, the time and duration of the price increase are predetermined, but the days are not predetermined. In a variable-period CPP, the time, duration, and day of the price increase are not predetermined.27

A real time pricing (RTP) rate is a dynamic rate that allows prices to be adjusted frequently, typically on an hourly basis, to reflect real-time system conditions.

a. The ACWA CPP Proposal

The ACWA CPP proposal, initially presented in the November 15, 2003 WG2 Report28 is designed to present little or no risk for customers; to be easily understood; and to be inexpensive (in terms of personnel or hardware) to implement. ACWA proposes that CPP be an option available to any IOU bundled service end-use customer who qualifies for existing rate schedules A-10, E-20, GS-2, and TOU-8. The IOU will determine the Critical Peak Periods (based upon low reserves, local transmission problems, high wholesale prices, or system peak), and will call at least 6 CPP hours each summer month. Under the ACWA proposal, the billing demand calculation under the existing rates is adjusted based upon the customer's average hourly demand during the Critical Peak hours of use in a summer month. After the first 6 Critical Peak hours, an approximately $1.00/kWh ($1.50 for customers with less than 500 kW peak demand) credit accrues during all Critical Peak hours for each kWh the customer reduces below the monthly average hourly kWh use during the Peak Period. Thus participants must perform during peak periods (minimum 6 hours per summer month) to achieve savings under the CPP tariff. For customers, this is a "no lose" proposition. Customers who do not respond pay no more than their current demand charges.

In its written comments, BOMA applauds the ACWA proposal as thoughtfully fleshed out, and supports it as the proposal that best protects customers. On the other hand, the respondent IOUs object to the ACWA plan because it provides significant potential bill savings to participating customers, on a no-risk basis, with no assurance of new demand reductions. This range of views highlights the chasm we must bridge.

Our goal is to develop programs that will provide meaningful demand response. Naturally these programs must be attractive to participating customers. But there is legitimate concern that ACWA's proposal provides generous bill savings to participants who provide little demand response in return, as customers need only respond during 6 critical peak hours each summer month in order to achieve a significant reduction in their demand charge. Further, if the customer's peak demand already occurs outside the 6 hours in question, the customer receives these savings in return for virtually no response. There must be a meaningful quid pro quo. Additionally, the ACWA CPP lengthens the averaging period used in determining the customer's demand charge (from a 15 minute interval to 6 hours), thus creating a revenue shortfall for all other customers. On balance these factors persuade us against adoption of the ACWA CPP proposal.

b. The Joint IOU CPP Proposals

The Joint Proposal is designed to appeal to commercial office buildings and other similarly situated customers with large air conditioning loads. This rate will be offered to large customers (>200 kW), all of whom are already equipped with appropriate interval meters due to AB29X. It will be offered during the summer peak season, as defined in each utility's currently applicable tariffs. Critical peaks will have two pricing levels, covering the seven-hour peak period. There will be a fixed number of CPP operating days (i.e., a maximum of 12 CPP days called per summer).29 High priced CPP days will be communicated to customers on a day-ahead basis. CPP days will be selected on the basis of forecasted utility-specific weather conditions with a predetermined zone.30

As proposed, for usage between 3:00 and 6:00 p.m. on a CPP day, critical peak prices would be set at a level equivalent to five times the utility's specific otherwise-applicable total on-peak energy charge (that period most closely corresponding to the statewide system peak). For usage between Noon and 3:00 p.m. and between 6:00 p.m. and 7:00 p.m. on a CPP day, critical peak prices would be set at a level equivalent to three times the utility's specific otherwise-applicable total partial peak energy charge. Excess revenue amounts generated by CPP rates on program operating days will be used to discount on-peak and part-peak energy charges on non-CPP operating dates, such that rates are revenue neutral in comparison to each otherwise-applicable rate schedule on a class-average basis. Revenue neutral in this case will mean that if an average usage level customer is on this rate, and does not respond by reducing demand during the called critical peak periods, the customer will pay the same total bill, or same average rate, as if they had been on the default tariff.

As proposed, this program would not be available to those currently participating in an existing load reduction program. The customer group targeted for this rate accounts for approximately 6,500 MW of aggregate commercial air conditioning load on typical summer peak days. If the program is implemented voluntarily, without transitional incentives, the IOUs project totals of 35 MW in 2003, 76 MW in 2004, and 85 MW in 2005. We discuss adoption of several transitional incentives later in this decision.

There are several critiques of the Joint Proposal. For example, on January 21, 2003, the City and County of San Francisco (CCSF) requested permission to intervene in this proceeding in order to raise issues regarding the Joint Proposal's interplay with San Francisco's unique peak electric loads. CCSF supports the Joint Proposal as consistent with CCSF's Electricity Resource Plan which seeks a 16 MW reduction in peak load by 2004. However, CCSF is concerned that the statewide Joint Proposal does not adequately capture San Francisco's peak load profile. CCSF wishes to work with PG&E to develop a pilot program to ensure that 1) the program will be applicable from May through October, consistent with PG&E's electric tariff definition of the summer season; 2) the number of operating days will be increased so that program can be deployed anytime during the weekdays; and 3) the selection criteria for CPP days will be modified so that they will be based on weather conditions specific to San Francisco's climate rather than on a predetermined zone.

We agree that the load, demand, and capacity characteristics of the San Francisco peninsula are unique in the PG&E service territory and merit special consideration.31 CCSF's broader concerns about transmission constraints and local generation issues are beyond the scope of this proceeding, although the issues raised by CCSF have been acknowledged by the WG2 participants, where discussions have focused on how the CPP proposals might be modified to address these concerns in some meaningful fashion.32 Rather than create a CCSF pilot program, however, we will direct PG&E to work with CCSF to create a localized marketing and recruitment area and triggering conditions for the existing CPP tariff proposal. Our decision requires PG&E and CCSF to submit an advice letter containing the details of this localized plan.

BOMA, whose constituency is the targeted audience for the CPP offering, also regards the Joint Proposal as unattractive in key respects. BOMA is concerned that its members may not have the ability to shed the significant additional load that must be shed during the CPP periods, and that the IOUs have given insufficient attention to understanding and addressing these obstacles. BOMA also believes the Joint Proposal requires further fleshing out.33 TURN opposes adoption of the Joint Proposal, arguing that it relieves large customers from their embedded generation cost responsibilities, provides meaningless incentives, has no mathematical foundation, and is better evaluated in a traditional rate design proceeding.34 ORA also expresses some concerns about the projected participation levels and demand response from the Joint Proposal, as well as the connection between incentives and revenue neutrality.35 DGS, on the other hand, supports the Joint Proposal as a way to shave expensive, peak energy consumption.36

We understand the initial reluctance of large customer representatives such as BOMA to embrace CPP. We also understand why others such as DGS and the CCSF embrace the program. No one program appeals to all large users. That is why we have considered a variety of tariffs and programs in Phase 1 and will be considering others, such as two-part RTP tariffs, in Phase 2. At this particular time, however, it is important to provide at least some options to large customers and to encourage their participation in these various programs so that we can begin to meet the state's demand response goals. The CPP effort involves a relatively modest expenditure through 2004, provides customer choice, and also allows us to take advantage of the AB29X infrastructure that is already in place in order to increase demand response in the near term. For all of these reasons, we authorize the Joint Proposal, subject to certain modifications discussed subsequently in the "Customer Participation Issues" section of this decision. These modifications, relating to agricultural customer participation, multiple meter situations, multiple program participation, and the use of incentives, are designed to promote customer participation in the program.

SDG&E intends to maintain its previously authorized critical peak tariff (Schedule AL-TOU-CPP) while implementing a new CPP tariff based on the Joint Proposal's statewide program.37 However as a modification to the Joint Proposal, and in the interests of capturing additional demand reduction from commercial office building complexes or business industrial parks, SDG&E recommends that the customer participation threshold be reduced from 200 kW to 20 kW. If we were to accept this recommendation, the CPP rate would be available to SDG&E's AL-TOU/EECC rate schedule, which includes all commercial accounts 20kW or greater. SDG&E has over 16,000 such accounts and plans to target about 6,700 of these for CPP participation. SDG&E projects the additional metering costs at $43,750 for 2003 and at $20,000 per year thereafter.38

At this time, we will not adopt SDG&E's proposal to expand this program to customers whose usage spans 20 kW to 200 kW. There is no record for doing so, or for calculating the costs of such an expanded program. Instead we will confine the CPP program to SDG&E customers whose usage exceeds 100 kW, as this Commission has previously authorized SDG&E to procure, install and operate real time meters for each of its customers (except exempted agricultural customers) with peak demand of 100 kW or more (D. 01-05-032, mimeo p. 6).39 40

SDG&E also wishes to convert an existing pilot program, its Hourly Pricing Option (HPO), into a full-scale program to be provided in concert with the Joint Proposal. We approved SDG&E's existing HPO in Resolution E-3782 issued August 22, 2002, so that it could launch an hourly metering and pricing pilot program during the summer of 2002 to test customer acceptance, demand response, behind-the-meter energy management technologies, and billing processes associated with dynamic retail energy commodity pricing. This HPO for commercial customers was to use interval meters, and charge varying on-peak hourly rates to customers based on next-day demand forecasts. The utility was to provide participating customers with hourly commodity price information on a day-ahead basis through the Internet, allowing them to adjust their usage accordingly. As approved, the HPO was to be offered to no more than 35 commercial and industrial customers with demands of 20 kW or greater on a first-come, first-served basis. However, in anticipation of decisions to be issued in this docket, SDG&E has not been aggressively promoting the HPO tariff to customers and, as of January 31, 2003, it had not signed up any customers for this program.41 Instead, SDG&E proposes to convert the HPO into a full-scale program and modify it by expanding the hourly prices to semi-peak periods, on the rationale that customers will have greater flexibility to reduce costs by shifting or reducing load from the higher on-peak hourly periods to the semi-peak "shoulder" periods.42

The CPP tariff proposed jointly by the respondent IOUs would create a tariff with two high on-peak rates in critical situations, but leave prices in the shoulder and off-peak periods averaged as in normal TOU tariffs. Since the SDG&E proposal expands the number of hours for which hourly rates are revealed to the participant, and thus breaks new ground, we will adopt it, making the HPO a full-scale program for SDG&E and as part of that, extending its hourly pricing features to cover shoulder hours. Consistent with the customer participation levels authorized for the CPP tariff, we will permit SDG&E to offer the HPO tariff to all customers with monthly demands >100 kW. However for the time being, we will confine this outcome to SDG&E, and not impose it upon PG&E or Edison. There is a simple reason for this: while WG 2 is in the early stages of exploring the development of a two part tariff suitable for wider application, this process must involve all interested parties and the resulting work products must be thoroughly vetted in this proceeding. In preparation for the next phase of this proceeding, the assigned Commissioner or ALJ will issue a ruling providing guidance to the parties on how this process should unfold.

2. Demand Bidding Programs

In broad terms, demand bidding programs allow the customer to bid the amount of electric load they can reduce at a certain predetermined price. Such programs can be voluntary (giving the customer the choice about whether and how much to participate on any particular day in response to utility requests), or they can require the customer's firm commitment. In Phase 1, we consider each type of program: the IOU Demand Bidding Program, an example of a voluntary program, and the CPA Demand Reserves Program, which requires a firm commitment.

a. IOU Demand Bidding Program

This Commission requires that demand response programs be included in each utility's long-term resource plan43, a decision made after this rulemaking was underway, and thus causing some retooling of the IOUs' Phase 1 demand bidding proposal. The IOUs presented their original joint proposal in the November 15, 2002 WG2 report, and subsequently modified it.44

The IOUs initially proposed that a common statewide market-based DBP program (requiring a price trigger) be developed after the ISO's day-ahead market has been established, as projected in Spring 2004.45 However they now believe there is no reason to wait. The IOUs have always favored the continuation of the existing Commission-authorized reliability-based demand bidding program. However they now propose the expansion of available demand bidding options, allowing participants to reduce demand voluntarily when requested by the IOUs in one of two ways: via 1) a price trigger and 2) a system emergency trigger.

Under their current market-based DBP proposal, IOU procurement departments will use current information and historical trends to forecast an hourly "price offer" on a day-ahead basis. This is a form of utility-specific procurement avoided cost. The "price offer" will be used as a cost effectiveness check in calling the program and valuing kW reductions. Events can be called any weekday (excluding defined holidays) between the hours of Noon and 8:00 PM and the program is triggered when the price offer is $0.15 per kWh or greater.

While a recurrence of year 2000 resource scenarios may be unlikely in the near term, the IOUs believe there is value in understanding the price responsiveness of customers during emergency situations. To that end, they propose that artificial conditions periodically be put in place to obtain this data, and for this purpose they would test the DBP at "emergency incentive" levels up to twice per year, four hours total. This emergency trigger, meant to simulate a CAISO "Alert" or "Warning" notification (when system reserves are forecast to be 7% or less between Noon and 8 PM weekdays only), would serve not only as an incentive to the customer to join the program, but would also determine the extent of participant response. A customer must submit a "committed load reduction" bid, and will receive $.50 per kWh of demand reduced during a test event. For purposes of payment, minimum (50%) and maximum (150%) load reduction criteria are applied.

In order to determine performance, the IOUs will use a new variant of a customer specific 10-day rolling average energy usage baseline. There was some concern that the current methodology does not scale baseline to actual demand, and BOMA argued that it may be unfair to customers with weather-sensitive loads. The IOUs responded by proposing a new method of calculating the 10-day rolling average, "using the average of energy usage for the three highest days for the same hour during the past ten similar days prior to a DBP event."46 They assert that this new method tends to reduce any negative bias that a simple 10-day rolling average produces for temperature-sensitive customer loads, should result in baselines that better reflect the load that would have been used absent the program, and avoids the gaming opportunities provided by adjustment mechanisms that scale baselines based on usage just prior to a DBP event.47 On balance, the revision to the baseline methodology proposed in the March 11 WG2 Report appears to address concerns about the fairness of the rolling 10 day baseline calculation, and we will make no further modification to the baseline calculation in this decision.

The IOUs propose to make their demand bidding program available to individual commercial/industrial bundled service customers not otherwise on an RTP base rate, or Agricultural rate schedules, whose usage is 200 kW or above, and who have interval meters capable of recording metered data on a 15 minute interval. The IOUs propose to offer such interval meters to the customers at the utility's expense if such metering is not already available on site. Customers must take service under the provisions of their otherwise applicable rate schedule. Participating customers must commit to reduce load by at least 100 kW during a DBP event and agree to reduce their load by their committed load reduction amount in the event of an emergency DBP event. Under the proposal, there would be no aggregation of customer accounts or their associated loads.

Besides these operational modifications to the existing demand response program, the IOUs propose to offer a transitional technical incentive package to DBP participants. This incentive package is the same as that offered to CPP participants, as discussed subsequently in this decision.

We agree that there is no reason to wait for the CAISO to develop a day-ahead market in order to implement the DBP, as the IOUs' most recent DBP proposal implicitly acknowledges, and we will adopt the Joint Utility Demand Bidding Program, as presented in the March 11, 2003 WG2 Report48, subject to certain modifications. First, we do not accept the limitation proffered by the IOUs that the DBP be available only to those not on another dynamic pricing tariff. In addressing multiple participation issues subsequently in this decision, we specify certain circumstances under which customers may participate in both the CPP and the IOU DBP. Second, we will allow some participation of multiple meters at a single site, under guidelines detailed subsequently in this decision. Third, we see no reason to exclude from the DBP certain agricultural customers whose usage exceeds 200 kW and who have interval meters in place. Since agricultural customers are currently participating in the IOUs' reliability-based demand response programs,49 there can be no argument that their participation is infeasible, or that their participation, as limited above, increases costs to other ratepayers. To our knowledge no specific argument against their participation in the proposed statewide program has been made. Therefore, this order allows certain agricultural customers to participate in the adopted Joint Utility Demand Bidding Program.

b. The CPA Demand Reserves Program

In the interests of coordinating an existing program with the IOU proposals being developed in this proceeding, WG2 also assessed how the CPA's existing Demand Reserves Partnership (DRP) could be used to meet our demand response goals. The design of the CPA DRP is governed by a contract between CPA and the Department of Water Resources (DWR). In D.02-10-062 we directed the IOUs to include the available resources from the CPA DRP in their long-term procurement plans. In D.03-02-031 we approved $29 million in CPA DRP costs for inclusion in the 2003 DWR revenue requirement. In this decision, we determine how this program will assist in meeting our stated demand response goals. In that regard, one of its primary benefits is its availability to a much broader array of participants than the IOUs' DBP; any end user (bundled or direct access) of the IOUs, as well as end users of cooperating load serving entities in California may participate in the CPA DRP.

Under this program the CPA uses load reduction by end users to provide demand reserves in the wholesale market. These demand reserves can be used in two ways: 1) Ancillary Services -as ten minute response non-spinning reserves or sixty minute response replacement reserves in the ISO markets; and 2) Call Option - as energy supplied in the ISO day ahead, hour ahead or supplementary energy markets during high wholesale market price or critical demand times. CPA contracts with demand reserve providers to work with end users and be contractually responsible for delivering the load reduction when called. Demand reduction for individual end users is limited to 11 AM to 7 PM, Monday to Friday for 24 hours per month, or 150 hours per year. Two different types of baselines are used to compute load reduction, one for those participating in the Ancillary Services of Supplemental Energy Markets, and the other for Call Options delivered into the ISO day ahead or hour ahead markets.50

At present, each IOU will receive credit towards the demand response goals set in this proceeding for any CPA DRP resources that it schedules. And in the absence of further direction from the Commission, it is likely that each IOU will schedule with the CAISO those CPA DRP resources that are inside or closest to its retail service area. However we will direct the IOUs to work with the CPA and DWR to develop and file, within 120 days, a mutually acceptable alternative mechanism for allocating these resources in 2004, unless such an alternative mechanism is developed in the procurement proceeding (R. 01-10-024). This timetable is designed to allow resolution of the issue by the Commission prior to the start of 2004.

While D. 02-10-062 requires the inclusion of DRP resources in the IOUs' long-term procurement plans, it is evident that the IOUs need to coordinate their scheduling activities with the CPA more closely in order to ensure that the DRP resources are actually dispatched when it is cost effective to do so. The IOUs must coordinate their customer, meter, scheduling and settlement activities in a manner that maximizes the full potential of the CPA DRP. To that end, we will require the IOUs to submit a DRP Implementation Plan, in coordination with the CPA, detailing how they will use the DRP resource effectively.

c. Parallel Demand Bidding Programs

We are aware that the CPA DRP and the statewide IOU DBP program share many similarities and thus may compete for customers. This reality must be balanced against the fact that there are key differences in these programs as well. For example, the "call option" portion of the DRP and the IOUs' DBP offer alternative means for customers willing to curtail load on a day-ahead or day-of scheduled basis. And the DRP Call option provides a much greater payment to the program participant than does the DBP, but it also obligates the participant to make a specified load reduction. Thus there is greater certainty about the load reductions of those participating in the DRP. Considering all of these factors, and consistent with our plan to offer a variety of options to large customers, we believe both demand bidding programs, operating in parallel, should be available. This means that in the near term the IOUs will be able to dispatch from either one.

3. Pilot Programs

a. The T&D Peak Capacity Proposal

The T&D Peak capacity proposal is presented by IMServ, whose products and services include collecting and providing advanced energy information, including settlement services to utilities and energy service providers, among others, and providing metering services. The proposal is rooted in the concept that customers should receive financial benefits in the form of reduced transmission and distribution (T&D) charges when they take actions that provide benefits on constrained T&D systems, thereby ameliorating adverse impacts associated with T&D upgrades and the environmental impacts of running peaking units in transmission constrained areas. This proposal targets electric customers (both direct access and bundled) above and below 200 kW in T&D constrained areas.

IMServ proposes that this program be implemented via the CPA's Transmission Pilot Program. The utilities would be required to identify constrained T&D areas as well as cost effective incentives for reducing these constraints. Finally the program must be marketed and customer T&D reductions calculated. Proof of concept operation of the pilot would occur during summer 2003, and the program would be expanded during summer 2004.

In D. 03-03-036, we considered and rejected this program for small commercial customers because it lacked the specificity necessary for implementation in Phase 1. The result is no different here. The pilot description is simply too general and the specific concepts to be piloted are missing. By summer 2003 it is simply impossible to develop hourly prices for transmission and distribution constraint costs and to use such prices as inputs to a demand response program. Therefore we will not approve the IMServ proposal in this decision.

b. The Infotility Proposal

During the WG2 process, Infotility presented a draft real time pricing proposal which stimulated discussion, and caused the WG2 participants to recommend that testing alternative design features of a two part RTP tariff might prove useful.51 The Infotility proposal is designed to test or identify 1) customer interest and response to a real time price signal across multiple building types; 2) customer preferences for baseline methodologies; 3) specific customer education requirements prior to participation in a two-part RTP tariff; 4) technical and administrative barriers to a full roll out; 5) customer satisfaction; and 6) "lessons learned."

Under the pilot proposal, participants remain on their existing tariff schedules and are billed for actual usage. They are debited/credited at a second rate (the market price) for the difference between actual usage and their baseline usage. Baselines are negotiated and may be adjusted monthly or on a day ahead basis. At the end of each month, customers receive a statement summarizing their performance relative to the baseline method employed under the program. If there is a net positive balance, customers earn an incentive credit; if there is a net negative balance, the customer is charged a debit. At the end of the program the customer is eligible to receive an incentive payment equal to the positive balance at the end of the program. If there is a negative balance the participating customer receives nothing.

Expected participants would be recruited from those organizations whose members have expressed interest in a two-part RTP tariff in the past. These include the Silicon Valley Manufacturing Group, OBMC program participants excluded from demand response programs, CMTA, BOMA, and other business and trade organizations. The program would be available to all large bundled customers with at least 200kW of maximum demand. Nearly all of these customers have already received the interval meters that are needed to participate.

Time did not permit the full exploration of the Infotility, or similar RTP proposals during Phase 1. However given the keen interest in this issue by many participants, we will authorize the WG2 participants to develop a pilot or pilots or consider alternatives that test two-part RTP tariff design features, and they may use the Infotility proposal as a starting point.52 We will cap the cost of this pilot(s) at $2.8 million, as detailed in the December 13, 2002 WG2 report.53

Having decided to make four of the tariffs/programs presented by WG2 (the Joint IOU CPP, the SDG&E HPO, the IOU DBP, and the CPA DRP) available to large customers, we now consider certain steps designed to encourage participation in them.

1. Agricultural Customers

Initially we address respondents' proposal to exclude agricultural customers from participation in the various tariff proposals that have been submitted in Phase 1. ACWA opposes this exclusion, arguing that the Commission should order the IOUs to install interval meters (and meter data communication) on all 200 kW and above meters and allow the cost of these installations as authorized additions to plant for ratemaking purposes.

On February 21, 2003, the ALJ issued a ruling requesting information from the IOUs about the estimated costs of installing AB29X advanced metering systems that would enable agricultural customers to participate in demand response tariffs or programs. Edison reported that agricultural customers were included in its AB29X RTEM program and that no additional funding is necessary other than that requested in its current GRC filing.54 SDG&E reported that its AB29X implementation plan includes installation of such meters for its agricultural customers with demands >300 kW;55 for its 461 agricultural customers with demands <200 kW, SDG&E estimates that no more than 10 sites per year would participate in the CPP, and that estimated annual metering costs would not exceed $20,000 for these customers;56 for its 36 agricultural customers with demands between 200 kW and 300 kW, SDG&E estimates initial costs of $63,000, and ongoing annual costs of $10,000.57 PG&E reports that it currently has 908 agricultural customers with demands >200 kW. Of these, 251 already have real time meters, and 657 have kWh or time of use meters. PG&E provides a range of one-time meter installation costs ($854,000 to $1.6 million, depending upon telecommunications options) for these 657 customers.58

Based on the IOUs' responses to the ALJ's February 21st ruling, it appears that the major cost issue relative to agricultural customer participation, is posed by PG&E's 657 customers who lack interval meters. Based on the figures presented, the cost implications for Edison and SDG&E appear to be less significant than the PG&E situation. While we wish to maximize the participation of all customers, including agricultural customers, in the demand response programs authorized in this decision, the record is not well developed on the issue of agricultural customer participation. We must carefully consider the participation of agricultural customers to determine which rate schedules are likely to provide meaningful, cost-effective demand response within the structure of the programs adopted in this decision. This we will do in Phase 2 of this proceeding. In order to allow some agricultural participation now, at the 200 kW level and above, we will authorize participation by agricultural customers on certain specific rate schedules, as proposed by PG&E and SDG&E. For PG&E, these are customers on options C and F of the AG-4 and AG-5 rate schedules, who have an existing interval meter. For SDG&E, eligible customers must be on schedule PA-T-1. Edison has not proposed specific tariff schedules, but rather proposes to transfer participating agricultural customers to discrete commercial accounts. We do not adopt this proposal, but instead will require Edison to identify specific tariff schedules eligible for participation. The 200 kW threshold, rather than the 100 kW threshold approved in D.01-05-032, applies to SDG&E as well, since the authorization provided in that decision excluded agricultural customers. So that additional agricultural customers who do not currently have interval meters are able to participate in these programs in the future, we will review the cost implications of such participation in Phase 2 of this proceeding.

2. Multiple Meter Situations

WG2 explored, but did not resolve, the issue of participation by customers at multiple meter facilities, where no single meter is >200 kW, but in aggregate the total usage at the customer's facility exceeds 200 kW. The IOUs apparently implemented their RTP metering contracts with the CEC differently, so some of these customers may have interval meters while others do not. While we understand that a liberal aggregation policy will encourage more customer participation, that goal must be balanced against the unknown metering costs and the paucity of our present knowledge about small commercial customer demand response. Thus, we do not allow aggregation at this point, but we are open to exploring this issue further in Phase 2 of this proceeding.

We will, however, allow customers with multiple meters at one site where at least one meter already exceeds 200 kW, to combine other smaller meter loads at the same facility for purposes of participation in the tariffs or programs authorized in this decision. In the interests of clarity, we will adopt a proposal made by PG&E in its comments to define permissible multi-meter participation.

An eligible site must be defined under the IOU's appropriate tariff rules (e.g., Rule 1 for PG&E) or consist of adjacent customer premises.

3. Multiple Program Participation

The participation of customers in multiple programs presents challenging issues. From the customer perspective, participating in a specific program requires hardware investments and management attention that can be more readily justified if more than one program provides benefits. From the program operator perspective, there are technical complications, such as attribution of load reductions between two programs, or the possibility that the response from one program will affect the "baseline" of another program. From the system operator perspective, it may be difficult to credit loads participating in multiple programs unless it is very clear how this affects aggregate capacity and the incremental capacity remaining once the system conditions leading to a sequential call of programs has been initiated.

From our experience with traditional interruptible tariffs and load curtailment programs, the specific concerns have focused on two key concerns: the possibility that customers will be compensated multiple times for the same load response (so-called "double dipping"), and the possibility that potential load relief associated with a particular program will be "double counted." Double counting occurs when the participating load on one program is the same load that is expected to perform in another program at the same time. Concerns have also been raised that multiple participation can add layers of billing and administrative costs associated with "overseeing" participation and calculating complex settlements. And utilities are concerned that such overlapping program participation may inhibit enrollment and cause customer dissatisfaction and confusion.59

On balance, however, we believe that multiple participation should be allowed provided that there are acceptable guidelines governing its applicability to the programs adopted in this decision. At this point in time, we will test multiple participation scenarios against the goal of avoiding both double dipping and double counting, as defined above. To develop this issue further in our rulemaking proceeding, the ALJ requested parties' comments on four multiple participation scenarios, some of which we will adopt. As we gain more experience with the interaction of these programs over time, we will be open to considering the adoption of additional scenarios.

May a bundled service customer on CPP also participate in the CPA DRP (or the IOUs' DBP) during hours when CPP prices are in effect, as long as the customer does not receive energy payments (from the CPA or the IOUs)? The answer is "yes," subject to certain conditions. This approach will balance providing an incentive to encourage customer participation and not making two energy payments for the same load reduction.

While the IOUs oppose this scenario as unlikely to provide additional load reduction because DRP and CPP operating days must be the same (PG&E Comments to ALJ's February 21st Ruling, p. 7), we note that the CPP will be in effect for only 15 days per summer, whereas the DRP can be in effect 150 hours a year. Thus, CPP customers should be allowed to participate in the IOU DBP and CPA DRP, but not receive energy payments during CPP-event hours. The CPA offered to account for and monitor the multiple program ramifications of the CPA DRP in the January 16 WG2 report and we will request that they do so.60

May a customer on an OBMC rate also participate in the CPA DRP, as long as the customer does not receive energy payments from the CPA during hours when the OBMC curtailment is in effect? Here, the answer is "Yes."

PG&E asserts that this form of multiple participation makes it almost impossible to predict the expected load reduction when an OBMC event is called and thus can have serious ramifications in forecasting load drops during a rotating outage. While this may be true, the load reductions offered by the CPA DRP are considerably cheaper per MW than those load drops available during an emergency through OBMC. In addition, load participation in the DRP may help avoid the need to call an OBMC event. On its face, this proposed multiple participation also does not raise a double dipping or a double counting concern, because of the non-payment periods for the DRP program during an OBMC event. Thus, we will allow customers to participate in both the OBMC tariff and the CPA DRP.

The IOUs recommend against this combination, but we will allow it. PG&E argues that most interruptible rate program participants have already specified relatively minimal firm service levels, so that additional load that might be made available for the CPA DRP under this approach would not be significant.61 As events unfold, that may be the case, but it is not entirely clear now. What is clear is that if an interruptible rate program participant wanted to participate in the CPA DRP, the customer will receive a reservation payment for additional load below the firm service level designated by participation in interruptible tariffs. Theoretically, while both load segments would receive capacity payments, each segment represents "new" load and each would receive separate payments. There is no dual compensation. Therefore we will allow this combination.

The answer is "yes," in part. Interruptible rate customers should be able to participate in the CPA's Supplemental Energy Markets, since no capacity payment if offered and no energy payments are made during interruptible program load curtailment events, as this scenario is described. Thus double compensation cannot occur under this scenario. Where interruptible customers already receive a capacity payment for participating load, they should not be allowed to participate in the Ancillary Service option (where a capacity payment is offered), as this would constitute double compensation.

4. Transitional Incentives

In its final report issued March 11, 2003, WG2 asserts that additional incentives are required to clear some significant hurdles that may impede our demand response goals. These hurdles include significant customer inexperience with demand response programs, customer reluctance to make the expenditure of time and effort necessary to participate in these programs effectively, as well as the perceived risk of participation. Representatives of one targeted group, BOMA, doubt that their constituencies will participate in the programs, as described in previous WG2 reports. And the IOUs report low levels of participation in existing demand bid programs, thus indicating that program changes, incentives, and more robust marketing may be needed to ensure broader participation. As a result WG2 proposes two basic transitional incentive options both of which would apply to the CPP Joint Proposal and SDG&E's HPO tariff, and one of which would apply to the IOUs' Demand Bidding Program.

These transitional incentives share common objectives: to increase initial customer participation levels, achieve significant demand response, provide the foundation for demand response programs, allow for experimentation with demand response capabilities, and accelerate the installation and use of demand response capabilities (March 11, 2003 WG2 Report, pp. 9 - 10).

a. CPP/HPO Incentive Proposal

For customers participating in the CPP and HPO programs, WG2 proposes that two types of transitional incentives be available, and that participants be allowed to receive one or both, either simultaneously or sequentially.

Under the proposed "rate protection incentive," the goal is to provide 100% bill protection, meaning that the participating customer pays no more than they would had they remained on their original rate schedule. Such customers are so protected for the first 12 months they are on the program, but no later than December 31, 2005. After the initial 12 months, if the sum of the CPP or HPO bills is higher than the sum of the bills on the otherwise applicable rate schedule, participants will receive the differential as a bill credit. There is no bill protection for individual customers after their initial 12 months on the program, or after December 31, 2005. BOMA maintains that the 100% bill protection feature should extend for the life of the CPP and HPO programs, and not just for 12 months, so as to allow customers to take the time necessary to adjust and adapt to the HPO/CPP regime.

Participation is capped at 500 MW (200 MW for PG&E; 200 MW for Edison; and 100 MW for SDG&E). The rate protection option is nearly no cost as long as existing revenue requirements are established and shortfalls are collected through appropriate balancing mechanisms.

To receive the benefit of the CPP, customers under the bill protection option must actually reduce peak demand by a minimum of 3% per CPP event averaged over the course of their 12 months' participation. If this minimal load shifting does not occur, the customer will not be given a CPP credit for participation under the program. Instead, the customer will only receive a refund to the extent its CPP bill exceeded the charges under its otherwise applicable tariff. The customer must also agree to allow the CEC or its contracting agent to conduct a site visit for measurement and evaluation, and agree to complete any surveys needed to enhance the program. Finally, since the CPP is a voluntary tariff, a customer may leave at the end of the 12-month period during which they received 100% bill protection, but a customer who leaves before the 12-month commitment ends will not receive bill protection.

In the case of the HPO tariff, the WG2 reports are silent as to how the 3% performance requirement is to be met. HPO customers receive their pricing signals daily; therefore they cannot be expected to meet a 3% demand reduction requirement daily and we do not believe this is what is contemplated by WG2. Rather, a 3% reduction could be averaged over the entire time period of the customer's participation in the HPO (or annually, as applicable). In its tariff filing, SDG&E should specify the exact nature of the performance requirement for HPO customers.

BOMA is indifferent to the 3% performance obligation, but it does believe that a customer should receive the full bill protection if it remains on the CPP tariff through one of its four month summer cycles, as opposed to the full 12 month period. Edison is concerned about the complexities of implementing the 3% performance obligation and believes that offering bill protection for 12 months without the complex measurement obligation would encourage maximum participation in the most cost effective way.

Under the proposed technology incentive, a CPP or HPO participant may earn a rebate incentive for installing and using pre-approved technology that enhances the customer's ability to respond to curtailment events. Technology such as, but not limited to, automated load control hardware, energy management systems, and smart thermostats may be eligible for this transitional incentive. Professional technical advice solicited and received by the customer that leads to actual demand response may also be eligible for a rebate. One WG2 participant, Echelon, is concerned that the definition of "qualifying equipment" is unclear, as is the approval process for such equipment. Echelon also expresses the more specific concern that any equipment installed as part of the load reduction program should offer real time energy information to both the customer and the CEC.62

The transitional incentive will rebate up to $150 per kW of curtailable on-peak load for the combination of costs associated with receiving technical advice and installing qualified equipment. Incentives must lead to actual demand response, either by installing technology or through technical assistance that identifies modifying existing equipment or behavior.

Under the proposal, payments will not be made for technical assistance that does not lead to demand response. Upon completion of hardware installation and certification of potential on-peak load reductions, the customer will receive a transitional incentive equal to 50% of the potential payment. The remainder of the incentive will be paid after the customer has achieved certain milestones. More specifically, to receive the 50% rebate remainder, the customer must show a calculated peak demand reduction equal to at least 50% of their estimated load drop per CPP event, as averaged over 4 consecutive CPP or HPO months, while on the program and before December 31, 2005. If this minimum level of measured load shifting does not occur, the customer would not be given the 50% rebate remainder. BOMA is concerned that imposing a performance requirement as a condition for reimbursement will cause many customers to forego these programs, and suggests that some level of technical assistance be offered to customers free of charge.

To determine performance, kW drop is estimated as the difference between the customer's specific baseline for that hour (calculated via a 10 day rolling baseline) and the customers actual energy usage during that hour. Edison is concerned that the 10-day rolling baseline is a measurement not used in any form in the tariff, and thus would complicate billing operations. It proposes a compliance measure it considers much simpler: reduction in historical on-peak usage measured annually. BOMA is concerned about the manner in which the estimated load drops are set. It believes that individual customer input is necessary and it is concerned that weather and temperature conditions must be taken into account in a manner that does not disadvantage participating customers.

Funding for the CPP/HPO technical incentive option is proposed at $11.375 million for all three IOUs (the incentive costs totaling $10 million, program tracking costs totaling $750,000, and monitoring and evaluation costs totaling $625,000). Under the proposal, incentives would be available to participants until December 31, 2005, or until funding under the specified caps is exhausted. Proponents suggest that if one category of funding is exhausted, any remaining dollars from any category can be used to keep the entire program going.63

b. Demand Bidding Program Incentive Proposal

The IOUs propose to offer a transitional technical incentive package to DBP participants, identical to the transitional technical incentive package offered to CPP/HPO participants. They will offer no bill protection incentive to these customers.

Funding for this DBP technical incentive option is proposed at $8.249 million for all three IOUs (the incentive costs totaling $5.375 million, emergency tests totaling $2.124 million, and program tracking costs totaling $750,000).64

CLECA questions whether there is sufficient evidence that technical incentives will motivate customers to participate in the DBP program, as DBP involves determining the load to be bid into the market and the price, in contrast to simply reducing load in response to a price signal.

For its part, CUE questions the cost of the technology incentives (for CPP and HPO, not just DBP), arguing that the Commission should not authorize such costs for ill-defined qualifying equipment until it has determined whether the free advanced meters already installed by the State will be an adequate "incentive" to meet demand response goals. CUE is concerned that WG2 exceeds its mission of developing tariffs that enable large customers to expand their demand response capabilities.

While supporting the objectives of the transitional incentives for all three programs, ORA believes that better and more effective incentives may be provided through the redesign of current TOU rates and changing the CPP rate design to increase the discount level so it would be equivalent to the interruptible and other demand response programs.

c. Adopted Transitional Incentives

For the CPP and HPO programs we will approve the bill protection incentive. Despite BOMA's argument that the program should extend well beyond 12 months for participating customers, we will authorize only a limited extension of the program, to 14 months. We do this because the CPP tariff may not be available until later this summer, and we are concerned that CPP events will be called in the Fall of 2004. This modest extension will provide meaningful protection during these additional events. We will also adopt the proposed 3% performance obligation, although we understand Edison's argument that a less rigorous performance obligation would be somewhat easier to implement. On balance, however, we prefer to have a more precise demand reduction measurement. To receive the benefit of the CPP, the customer under the bill protection option must actually reduce peak demand by a minimum of 3% over the course of their 14 months' participation. Bill protection will be credited at the end of the 14-month period of successful participation. If this minimal load shifting does not occur, the customer will not be given a CPP credit for participation under the bill protection program. Instead, the customer will only receive a refund to the extent its bill exceeded the charges under its otherwise applicable tariff.

We will also adopt two other proposed performance obligations: the site visit and survey completion agreement, and the time commitment as a condition for receipt of bill protection. We will also cap the bill protection program at 500 MW as proposed, while noting that this incentive does not increase costs.

We decline to approve the technical equipment portion of the technology incentive for either the CPP/HPO or DBP. While an equipment-based rebate is potentially helpful in augmenting demand response based on the projections included in the March 11th WG 3 Report (Table 2), the proposal lacks key detail, including a method for determining what constitutes "qualifying technology." More significantly, the level of projected costs exceeds $11 million, a significant amount, with no indication of how much demand response such expenditure may encourage, a fact not counterbalanced by the inclusion of a performance requirement that would withhold 50% of the incentive in cases of nonperformance. Considering all of these factors, we will not approve the technology equipment component of the proposed technology incentive for any of the three programs in question.

We will, however, approve the technical assistance portion of the proposed incentive package, allowing a rebate for professional technical advice regarding installation of new equipment or modification of existing equipment or behavior because the modest expenditure we authorize65 in that regard may indeed spur customer participation at a more acceptable cost. As originally proposed, a rebate of up to $150 per kW of curtailable on-peak load would be allowed for the combination of costs associated with receiving technical advice and installing technical equipment. Since we are not approving the technical equipment installation component, we will exercise our discretion and reduce the rebate accordingly. The authorized rebate amount for technical assistance will be $50 per kW of curtailable on-peak load for the costs associated with receiving technical assistance (related to the installation of new equipment or the modification of existing equipment or behavior) that leads to actual demand response. As with the original proposal, the customer will receive a transitional incentive equal to 50% of the potential payment upon certification of potential on-peak load reductions. The remainder of the incentive (the 50% remainder) will be paid after the customer has shown a calculated peak demand reduction equal to at least 50% of their estimated load drop per CPP event, as averaged over 4 consecutive CPP or HPO months, while on the program and before December 31, 2005. If this minimum level of measured load shifting does not occur, the customer will not receive the 50% remainder payment. To determine performance, the kW drop will be determined using the customer baseline proposed in the March 11th WG2 report.66

Our decision allows CPP/HPO customers to opt to receive just the bill protection incentive or both the bill protection incentive and the professional technical assistance incentive. Participants in the IOU DBP tariff may receive only the professional technical assistance incentive. Like our conditions stemming from receipt of incentives for CPP, any DBP customers accepting incentives must allow access to their site for research purposes by the CEC and/or its contracting agent. Since our decision allows some multiple program participation, we take this opportunity to clarify that multiple program participation does not entitle a customer to any additional incentive due to multiple participation.

Finally we note that the approved incentives are available to participants until December 31, 2005, or until funding under specified caps is exhausted. However if one category of funding is exhausted, any remaining dollars from any other category can be used to keep the entire incentive program running, with the caveat that at least 50% of the funding for technical assistance shall be guaranteed for the CPP.

We have taken several steps in this decision to augment customer participation in order to increase the amount of demand response generated by the adopted tariffs and programs. These include opening the tariffs and programs to agricultural customers, allowing certain multiple meter situations, allowing multiple program participations, as defined, and approving bill protection and professional technology assistance incentives on a transitional basis. As a result, it is expected that in calendar years 2003 and 2004, these demand response programs will provide approximately 411 MW and 954 MW, respectively (see Appendix B). While our decision to reject the technology portion of the transitional incentive proposal may diminish, to some degree, the expected MW contribution provided in Appendix B related to the statewide CPP, the HPO, and the IOUs' DBP, other steps taken to open these programs to agricultural customers and to authorize certain multiple-meter situations, and to allow discrete multiple program participation may offset any MW reduction.

The recent history of demand response programs in California is one of constant flux in program design. The WG2 participants strongly recommend that we embrace the concept of program stability, which is characterized as a policy allowing for consistent program design, eligibility and triggering mechanisms over multiple years. We are in total agreement with the WG2 participants on this point, and this rulemaking has exemplified this principle, embracing consistent and well-developed demand response policymaking over ad hoc program development. In our view, program stability will help us to achieve significant participation in demand response programs. To that end, the programs authorized in this decision are designed to continue beyond calendar year 2004, and have no expiration date, although funding is authorized in this decision through calendar year 2004. We will direct the IOUs to file evaluations for all authorized programs in this decision, as well as those authorized in
D.02-04-060 in our interruptibles rulemaking, in the Fall of 2004 for the purpose of making any necessary revisions for summer 2005. At that time, we will consider authorizing additional funding as necessary. If any program modifications are necessary, they should not be disruptive to customers who have participated up to that point. And if a specific tariff or program needs to be terminated, those participating in it should be offered a reasonably smooth transition to another program if at all possible.

Over the years various efforts to introduce demand response pilots have resulted in some programs that are no longer active. For example, PG&E reports that there are no remaining customers enrolled under its experimental real time pricing tariff, Schedule A-RTP, and it views the Joint Proposal submitted in Phase 1 as a reasonable successor to that tariff. Therefore in the interests of avoiding customer confusion about available advanced tariff options, we will eliminate this outdated tariff.

In D.02-04-060 we authorized a pilot known as P-BIP in response to a CEC request to introduce a measure of market based pricing. The tariff has only one participant, and the WG2 participants see little harm in eliminating the pilot. The single participant will be encouraged and assisted to fit into another program.

The cost figures for calendar years 2003 and 2004 for the programs approved in this decision, and discussed below, appear in Attachment "A" to this decision.

1. Cost-Effectiveness

We now address the question whether the four programs adopted in this decision are cost effective. California regulatory agencies have a long history of attempting to ensure that demand-side management (DSM) activities are cost effective. This Commission, in conjunction with the CEC, has established and periodically updated the Standard Practice Manual to create greater uniformity in assessments.67 We have typically required that DSM programs be shown to be cost-effective according to one or more of the standardized tests.

The WG2 reports document the difficulties that participants have had in developing the inputs for and applying the current SPM tests to tariffs and programs that are designed to interact with markets. 68 The ALJ Ruling dated October 2, 2002 recognized some of the concerns of WG2 participants. In directing parties to proceed nonetheless, the ALJ Ruling dated November 13, 2002 provided high and low values for avoided cost scenarios to be used in the analysis.

The Working Group 1 principals have expressed a belief that a long-term, sustainable direction was desirable for Demand Response options in this Proceeding. We concur that a focus on the cost of a new peaker power plant69 is the most relevant standard in determining cost-effectiveness for tariffs and programs designed to be part of a growing reliance upon demand response, just as it has been for rate design and demand side management measure evaluation historically.

The Benefit-Cost ratios of the four options being pursued are reported in Table 2. Three of the tests from the SPM were applied to the program options - the Total Resource Cost (TRC) test, the Participant test, and the Ratepayer Impact Measure (RIM) test. The TRC test considers the Benefits and Costs from society's or the total state of California's perspective. In contrast, the RIM test considers the revenue impact on ratepayers not participating on the tariff or program.

Table 2: Benefit-Cost Ratios of DR Options Compared to a New Peaker70

Program/Tariff

TRC

Particip.

RIM

IOU Critical Peak Pricing

15.4

4.8

1.2

SDG&E Hourly Pricing Option

14.7

2.6

0.8

IOU Demand Bidding Program

22.6

1.3

4.6

CPA Demand Reserve Partnership

2.2

3.1

1.2

All programs passed all three tests, with the exception of SDG&E's HPO, which did not pass the RIM test. However, some argued that the RIM test is not directly applicable because presumably the HPO better reflects what the true costs of power are than conventional time-of-use rates - and hence participants now joining the HPO are currently subsidizing other customers on the less precise time-of-use rates. Therefore, given the limitations of the tests, all program proposals were judged to be attractive compared to investing in a new peaker of comparable MW size. Under revenue neutrality principles, discussed subsequently, the IOUs will not lose money. Further, since it has become clear that at least an initial rationale for these programs is to develop experience in attracting customers to participate and evaluating their load response when programs are triggered, we believe that these specific tariffs and programs are sufficiently cost-effective to be authorized.

We believe that the concerns expressed by WG2 participants about the validity of the SPM tests, and the process for developing inputs that accurately reflect the value of displaced supply side power procurement costs, are sufficiently important that we will direct parties in Phase 2 of this proceeding to develop and bring forward proposed modifications to the SPM.

There is general agreement that customer participation in demand response tariffs and programs will cause the IOUs to lose revenue (compared to authorized revenue requirement) because load reduction involves both a reduction in energy usage and a shift from energy use during peak periods in which existing rate designs accentuate revenue recovery. The exact amount of revenue loss depends upon many factors, including the nature and extent of customer participation in demand response programs and other unknowns such as offsetting energy purchase cost reductions attributable to effective demand response. In that light, the estimated dollar impacts provided at the end of the WG2 process ($11.5 million in 2003 and $29.9 million in 200471) must be viewed as very conservative approximations, since they assume no short-term commodity procurement cost savings associated with these revenue reductions. Those cost savings certainly will exist, though their magnitude cannot be predicted in advance.

Under the concept of revenue neutrality proffered by the WG2 participants, the IOUs' authorized revenues should be protected from the effects of the actual demand reductions that occur due to demand response.72 The IOUs recommend recovery of revenue shortfalls from the entire system, asserting that it is burdensome to track such shortfalls by class.

Against this recommendation, ORA argues that such revenue shortfalls should be recovered from the large customer class, not system-wide. Under ORA's proposal, certain revenue shortfalls would be recovered from the non-CPP participants in the same sub-customer class, which will give non-participating (static rate) customers an incentive to switch to CPP or other dynamic tariffs and programs. This proposal is possible due to the likelihood that some customers who volunteer for the CPP pay less under their new tariff without making any change in their usage. This happens because current static rates are designed based on average load profiles, and these customers are currently paying more than their fair share through an intra-class subsidy to users with peak loads greater than the average load. ORA proposes that this structural revenue shortfall (the intra-class subsidy to users with peak loads greater than the average load) be recovered from customers who choose to stay on the default TOU rate. In ORA's view, this will cause an increase in the default TOU rates, thereby encouraging more customers to migrate to the CPP tariff. ORA notes that the "dynamic revenue shortfall," the bill savings resulting from customers changing their loads in response to new prices, is offset by comparable reductions in procurement costs, and ideally net procurement cost savings will be passed through to the cub-class of CPP participants via rate design in the form of lower off-peak prices. ORA believes that CPP rates should be designed so that the dynamic shortfall equals the avoided procurement costs.73

We find merit in ORA's proposal designed to encourage program participation by sending appropriate price signals. Effectively, it would cause CPP participants to receive the benefit of the full amount of avoided procurement costs, thus making the CPP rate more attractive. However there are some roadblocks to implementation of ORA's proposal. First, it is unknown how much rates will increase for those customers who stay on the default rates, as part of the calculation depends upon how many opt for the CPP. Second, there are practical rate-related differences among the IOUs. Specifically, Edison recently filed an application for rate reductions, so an increase to default TOU rates for its customers would be offset. On the other hand, the elimination of PG&E's surcharges is not expected to occur immediately, and SDG&E has no current plans to reduce rates. Third, the IOUs do not currently allocate either procurement costs or prospective savings by class or schedule, which is a necessary prerequisite to the ORA proposal. Nonetheless we believe that these practical problems must be weighed against the benefits of the ORA proposal and the likelihood that it will increase participation in demand response programs over the long term. ORA's conceptual proposal merits further exploration. Accordingly, we will require the IOUs to file a compliance filing outlining their assessment of the customer impacts of implementing the ORA proposal; indicating how they would implement both features of the ORA plan (its treatment of structural revenue shortfalls and its treatment of dynamic shortfalls); and identifying the currently available, or next available, ratesetting forum where the ORA proposal may be explored and implemented in the context of the IOU's overall rate design. ORA has requested that a workshop be held prior to the submission of these compliance filings and our order so provides.

Until the ORA proposal can be implemented, we will allocate the revenue shortfalls associated with the programs adopted in this decision on a system-wide basis, consistent with the recommendation of the IOUs and most other WG2 participants.

3. Program Administrative Costs

As shown in Attachment B, program administrative costs, which are comprised of O&M and A&G costs associated with the various activities necessary to implement the adopted demand response programs total $13.0 million and $7.0 million for calendar years 2003 and 2004, respectively. These costs included program monitoring and evaluation expenditures totaling $1.5 million in 2003 and $0.5 million in 2004. All costs attributable to the CPA DRP program should be covered by the IOUs in the following proportions: 45% each from PG&E and Edison, with 10% from SDG&E.

As shown in Attachment B, capital costs for such items as advanced meters, billing system additions or measurement data collection software attributable to the adopted demand response programs total $7.9 million, and $0 for calendar years 2003 and 2004, respectively. $4.5 million of the total $7.9 figure relates to the installation of additional AB29X meters on certain types of willing customers and it is not clear that all of those customers will select such meters. Thus, those capital costs could be considerably less than the amount projected. For purpose of allocation among the utilities, costs related to the CPA DRP program should be allocated 45% each to PG&E and Edison, with 10% to SDG&E. Additional metering costs should be allocated at $2.5 million for PG&E, $1.5 million for Edison, and $0.5 million for SDG&E, with the proportional higher amount available to PG&E due to the number of agricultural customers in its territory with demands over 200 kW that do not yet have interval meters.

5. The Costs of Incentives

With our decision to approve only the professional technology assistance incentive, costs in this expenditure category for calendar years 2003 and 2004 are significantly reduced from the $11 million originally proposed to $3.41 million ($2.0 million in 2003 and $1.4 million in 2004).

There are expenditures shown in Attachment B as "other incentives" capped at a total of $0.9 million and $0.9 million in calendar years 2003 and 2004, respectively. These are the expenditures authorized in this decision for this category. In addition, Attachment B lists, for purposes of completeness, certain incentives already approved in the DWR revenue requirement (i.e., not authorized in this decision) related to the CPA DRP program. The total amount for 2003 is $12.75 million and for 2004 is estimated to be $25.5 million.

Adding the total transitional incentive costs authorized to the "other incentives" not applicable to CPA and covered in the DWR revenue requirement yields total incentive costs of $2.9 million in 2003 and $2.3 million in 2004.

6. Imposition of Cost Cap

The costs (Program Administrative, Capital and "Other Incentive" Costs from the discussion above) for the demand response programs authorized in this decision for calendar years 2003 and 2004, are capped at the total amount of $23.7 million and 9.3 million, for calendar years 2003 and 2004, respectively. This total figure, $ 33.0 million, is exclusive of revenue shortfalls and CPA DRP costs, which are part of the DWR revenue requirement.

7. Cost Recovery Mechanisms

The respondent IOUs requested identical cost recovery mechanisms for programs adopted as a result of both WG2 and WG3. Consequently in our recent decision (D.03-03-036) dealing with WG3 issues, we adopted cost recovery mechanisms that apply to all Phase 1 programs, both those advanced by WG3 and WG2. Therefore it is unnecessary to address cost recovery mechanisms again in this decision.

In the March 11th Report the WG2 participants have presented an implementation plan which builds upon the detailed Customer Marketing, Education and Recruitment Plans included in the December 13, 2003 WG2 Report. This plan assumes that the IOUs will assume the responsibility for marketing the adopted CPP/HPO and DBP programs to their large customers. As proposed, customer education includes extensive training for utility employees who have customer contact responsibilities, as well as development of customer education materials and education sessions, all designed to provide general familiarity with the adopted programs, program benefits, bill information, sign-up requirements, and enrollment procedures.

As proposed, marketing and recruitment efforts will emphasize higher potential customers, including those not currently participating in demand response programs but who have participated in them in the past; and commercial and industrial customers whose operations offer peak load shifting opportunities. Some customer contacts will be made by phone, direct mail, or selected event participation. In addition, each IOU proposes to place CPP and DBP program information on its website. Throughout the life of these programs, communication with customers will continue via various program communication letters and ongoing one-on-one customer contact.

While adopting the WG2 customer education/outreach proposals in concept, we will also impose some requirements. We will require the IOUs to implement substantially similar customer education and outreach programs for the CPP/HPO and DBP; further these programs must be compatible with parallel activities of the CPA for its DRP programs. Marketing of incentives requires particular care so that incentives are not over-emphasized. We prefer to attract customers with as little use of incentives as is feasible in order to minimize costs, and in recognition of the fact that these incentives are not an intrinsic part of the tariffs, but merely a transitional tool. In connection with the adopted technical assistance rebate, professional technical assistance incentive certification and verification of load reduction should be handled by firms designated by the CEC. The IOUs should coordinate with the CEC to make every attempt to attract customers to these demand response programs who already have received subsidies from the state for installation of demand response equipment.

The customer education/outreach proposal submitted by WG2 leaves many specific implementation details to be resolved over time. We will not leave the resolution of these details to the sole discretion of the IOUs. Rather we will continue the WG2 process, requiring WG2 to be periodically briefed about IOU implementation proposals and to express alternative views. And in the event there are disputes, we expect the WG2 facilitator initially to attempt to resolve them with the parties. If in the opinion of the WG2 facilitator, the IOU response to concerns insufficient, the WG2 facilitator will bring the matter to the attention of the assigned ALJ who will resolve the matter in consultation with the assigned commissioner.

WG2 has proposed a comprehensive monitoring and evaluation plan.74 Specifically, the monitoring plan would include recruitment and sign-up; tracking continuity; measuring actual patterns of demand response; IOU revenue impacts; participant expenditures; administrative costs; and reporting monitoring results. The evaluation plan will include such elements as identifying the nature of the participants; assessing load shape changes; understanding how to accomplish load impacts; estimating system benefits; estimating IOU revenue and cost impacts; and assessing whether tariff or program changes are necessary. The costs of the comprehensive measurement and evaluation plan are estimated at $861,000, and $275,000 for 2003 and 2004, respectively (see Attachment B). Supplemental research for adopted incentives is also contemplated. WG2 proposes to supplement the plan to monitor the use of these incentives and gauge their effectiveness. Specifically the supplement will assess how successful the rate protection incentive is in overcoming customer specified barriers to wider CPP and HPO acceptance, in increasing initial enrollment in these programs, and in leading to second year enrollments. It would also include analysis of customer preferences for alternative incentive packages, the overall effectiveness of the incentives in producing the desired results, and comparative load reductions of those accepting the incentive vs. those who chose not to. Monitoring would be broadened to include reporting on the number of customers signed up for the rate protection incentive and the number and amount of true-up payments made after the first 12 months on the CPP or HPO tariff.75

WG2 participants also propose to monitor the technical assistance incentive designed to increase enrollment in the CPP and HPO tariffs as well as the IOU DBP. They plan to separately track and assess this incentive. There will be reporting on the number of sign-ups, the load reductions represented, and the incentive payments made. In addition, WG2 proposes to include the assessment of impacts of installing a variety of sub metering and data-logging devices on a sample of the technology-assisted customers, representing a broad range of customer types. Sub-metering and data-logging data will be correlated to total building loads and analyzed to determine how specific technologies contribute to total building load reductions. Costs for this effort include acquisition, installation, and removal of monitoring equipment; data collection and management; and data analysis and reporting. The CEC will supervise this work in coordination with the IOUs and the Energy Division. The costs of augmenting the comprehensive measurement and evaluation plan to assess the rate protection plan and incentives are projected to be $125,000 for 2003 and $250,000 for 2004 (see Attachment B), but these costs may be slightly higher than actual costs as they include the technology incentive which is not approved in this decision.

We are especially interested in monitoring and evaluating the impact of the incentives approved in this decision, so we will approve the supplemental work suggested by WG2 in that area, as part of our overall approval of the plan as described above. The $460,000 estimated for this work is reflected in Attachment B. We also believe the CEC and the Energy Division must play a key role in the monitoring and evaluation process, as reflected in the WG2 proposal. And it is abundantly clear that an important coordination effort is needed to ensure that the appropriate data is collected and made available for analysis to support programmatic evaluation. The WG2 facilitator is designated to work with the IOUs and parties who wish to be included in this effort, to maintain the required level of coordination, including review of implementation plans, fine tuning of program implementation mechanics within the scope of this decision, and review of compliance filings or tariffs that may be required. In the event of disagreement that cannot be resolved within the WG2 process, the facilitator will bring the matter to the attention of the assigned ALJ who will resolve the matter in consultation with the assigned commissioner.

WG2 has suggested that Fall 2004 be a major point to evaluate the authorized tariffs and programs, but this decision has authorized tariffs without expiration dates and extended the period in which incentives can be offered through calendar year 2004. We will direct the IOUs, in coordination with the CEC, to conduct evaluation activities to be completed in the Fall of 2004, as input to a systematic review of demand response policy, tariff development, and program design to be conducted in the winter of 2004/2005.

16 Order Instituting Rulemaking (R.02-06-001), p. 1. 17 CMTA's Comments on WG2 Reports, p. 2. 18 See, e.g., the following parties' comments on the various WG2 Reports: ACWA; BOMA; CLECA; and CMTA. 19 CMTA's Comments on WG2 Reports, pp. 3 - 4. 20 WG 2 Report dated November 15, 2003, p. 4. 21 Working Group 2 Report dated November 15, 2002, p. 32. 22 TURN Comments on WG2 Reports, pp. 3 - 5. 23 TURN Comments on WG2 Reports, pp. 12 - 13. 24 See WG2 Report dated December 13, 2002, pp. 86 - 93. 25 See WG2 Report dated December 13, 2002, pp. 93 - 94. 26 See Glossary of Retail Electricity Rate Terms, Attachment A to D.03-03-036. 27 See D.03-03-036, Attachment A, "Glossary of Retail Electricity Rate Terms." 28 See, WG2 Report dated November15, 2002, pp. 60-70. 29 In their response to the ALJ's February 21, 2003 Ruling, the IOUs submitted pro forma tariffs including this 12-day provision. 30 See, Southern California Edison Company's Addendum to Working Group 2 Report Submitting Critical Peak Pricing Proposal, Attachment "A," p. 1. 31 CCSF has demonstrated that it has a direct and substantial interest in the outcome of this proceeding that cannot be represented adequately by any other party. Pursuant to Rule 45, we will grant its motion to intervene. 32 The CPA DRP proposal, discussed subsequently, also provides a potential solution for demand response in transmission constrained areas by allowing a targeted operation in such areas. 33 BOMA's January 27, 2003 Comments on the Working Group 2 Reports, pp 7 - 8. 34 TURN's January 27, 2003 Comments on the Working Group 2 Reports, pp. 7 - 9. 35 ORA's January 27, 2003 Comments on the Working Group 2 Reports, p. 3. 36 DGS January 27, 2003 Comments on the Working Group 2 Reports, pp 2- 3. 37 Errata to Comments of SDG&E on Working Group 2 Reports, dated January 31, 2003, p. 3. 38 SDG&E's Supplemental Comments Responding to Data Request in February 21, 2003 Ruling, p. 3. 39 That decision allowed the establishment of an RTEM Memorandum Account associated with the $12.5 million of purchase and installation costs for the meters and the accompanying meter data management system, while deferring the issue of actual cost recovery and cost allocation to a subsequent reasonableness review. 40 SDG&E's customers in the 200-300 kW range do not have AB29X meters installed, so SDG&E will incur additional costs if these customers participate in the programs authorized in this decision. However this Commission has already authorized SDG&E to procure real time meters for customers with usage exceeding 100 kW (D.01-05-032). 41 SDG&E's February 1, 2003 Program Evaluation Report #1, "Hourly Pricing Option Pilot, Schedule EECC-HPO," p. 6. As required by Resolution E-3782, SDG&E served this report on the service list of R.02-06-001. 42 SDG&E's January 27, 2003 Comments on the WG2 Reports, pp. 5 -6. 43 D.02-01-062, mimeo, p. 28. 44 See Third Report of WG2 dated January 16, 3002, p. 12; and Fourth Report of WG2 dated March 11, 2003, pp. 20-29. 45 Third Report of WG2 dated January 16, 2003, p. 12. 46 WG2 Report dated March 11, 2003, p.25. 47 SDG&E Comments in response to February 21, 2003 ALJ Ruling, p. 5. 48 Exclusive of the incentive features whose merits are addressed subsequently. 49 SCE's Agriculture and Pumping Interruptible Program and TOU-PA-SOP-I tariff. 50 See Working Group 2 Report dated January 16, 2003, pp. 18 - 22. 51 WG2 Report dated December 13, 2002, pp. 93-94. See also Appendix C to the December 13th report. 52 The original schedule proposed by WG2 has slipped and it will be necessary for them to meet to develop a new schedule to test two-part RTP tariff design features. 53 See Appendix C of the December 13, 2002 WG2 report. 54 Edison Response to ALJ's February 21, 2003 Ruling, p. 4. 55 SDG&E Response to ALJ's February 21, 2003 Ruling, p.2 56 SDG&E Supplemental Response to ALJ's February 21, 2003 Ruling, p. 2. 57 SDG&E Response to ALJ's February 21, 2003 Ruling, p. 2. 58 PG&E Response to ALJ's February 21, 2003 Ruling, pp. 5 -6. 59 See, e.g., Edison comments to February 21, 2003 ALJ Ruling, p. 6; and SDG&E Comments to February 21, 2003 ALJ Ruling, p. 4. 60 WG2 Report dated March 11, 2003, p. 26: "CPA will insure that no [energy] payment was made during hours that the utility program curtailment events were being exercised." 61 PG&E Rersponse to ALJ's February 21, 2003 Ruling, p. 8. 62 See WG2 Report dated March 11, 2003, p. 20. 63 Working Group 2 Report dated March 11, 2003, p. 16. 64 Working Group 2 Report dated March 11, 2003, p. 24. 65 As shown in the Attachment A, the total amount of these incentives for 2003 and 2004 is $3.41 million, versus the $11.3 million proposed by WG2. 66 Edison argued against this baseline due to concerns about billing complications, but this is the same baseline used in connection with the IOU DBP program approved in this decision. 67 CPUC, "California Standard Practice Manual: Economic Analysis of Demand-Side Programs and Projects," October 2001. 68 See "Issues for Cost-Effectiveness Analyses" on page 53 of the January 16, 2003 Working Group 2 report. 69 ALJ Ruling, November 13, 2002. The cost of a new peaker was $85/kW-yr and $.035/kWh. 70 The IOU numbers include technical incentives and bill guarantees and are taken from the March 11, 2003 report of Working Group 2. The CPA numbers are taken from the January 16, 2003 report of Working Group 2 since no new incentives are proposed for the CPA programs. Moreover, the CPA numbers reported here are a weighted (by MW) average of the 3 CPA options reported in the January 16 report. 71 See WG2 Report dated March 11, 2003, Table 5, p. 48. WG1 staff has extrapolated from Table 5 to arrive at these approximate figures for Year 2003 and Year 2004. 72 See WG2 Report, dated November 15, 2002, p. 29. 73 ORA's Written Comments on the WG2 Reports, dated January 27, 2003, pp. 4 - 6. 74 See, Working Group 2 Report dated December 13, 2002, pp. 24 - 29, and Working Group 2 Report dated March 11, 2003, pp. 37-39. 75 Working Group 3 Report dated March 11, 2003, p. 38.

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