Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program

Transcription

1 Application No.: Exhibit No.: Witnesses: A SCE-1 L. Oliva D. Parker D. Snow R. Thomas (U -E) Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program Before the Public Utilities Commission of the State of California Rosemead, California June 0, 0

2 Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program Table Of Contents Section Page Witness I. INTRODUCTION...1 L. Oliva II. BACKGROUND... L. Oliva A. Background of SDP... B. Demand Response Policy Changes... C. Impact of Edison SmartConnect on SDP... D. Current SDP Program Program Design.... Load Control Technology and Communications Infrastructure.... Event Performance... III. SUMMER DISCOUNT PLAN PROPOSAL...1 L. Oliva A. Considerations That Informed Transition Plan Proposal...1 B. Proposed Program Design Curtailment Event Triggers...1. Program Availability...1. Event Duration...1. Load Control Technology Options...1. Load Control Options...1. Customer Incentives...1 R. Thomas a) 0% Cycling and Override Option Valuation...1 C. Long-Term Considerations for the Existing Load Control Platform, Communications Systems and Field Devices... L. Oliva D. Integration of SDP Into CAISO s Market... D. Parker -i-

3 Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program Table Of Contents Section Page Witness E. Customer Education and Outreach... L. Oliva F. Enrollment and MW Forecast Customer Choice of Cycling Strategy or Override Feature... a) Cycling Strategy... b) Override Option.... Device Location.... Program Attrition.... Enrollment Forecast Summary... IV. SDP TRANSITION INCREMENTAL COSTS... A. Overview... B. Historical Spending for SDP Device and Installation Costs...1. System Enhancements... a) Billing and Customer Service System... b) SCE.com... c) Alhambra Control Platform.... Program Management, Administration and Customer Support Services... a) Tariff Programs and Services... b) Client Services Organization... c) Customer Communication Organization... d) Job Skills Training Organization... -ii-

4 Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program Table Of Contents Section Page Witness. Customer Education and Outreach... C. Conclusion... V. COST EFFECTIVENESS... A. Cost-Effectiveness Results... B. Methodology... VI. COST RECOVERY... D. Snow A. Overview... B. Rate Recovery of Demand Response Program Costs... C. Ratemaking of DRP Funding... Appendix A Witness Qualifications Appendix B SCE 0 01 Summer Discount Plan Program Abbreviations & Acronyms -iii-

5 Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program List Of Figures Figure Figure II-1 CAISO Load Duration Curve Sept 1, 00 to Sept, Figure III- Prototype Load Control Device with Override Feature...1 Page -iv-

6 Testimony in Support of Southern California Edison Company s Application for Summer Discount Plan Program List Of Tables Table Table II-1 SDP Residential Enrollment As of May 1, 0... Table II- SDP Program Events Table III- SCE s Summer Discount Plan Proposed Program Design...1 Table III- Program Attributes and Incentive Levels...1 Table III- Residential SDP Program Compensation... Table III- SDP Residential Customer Enrollment and Attrition Forecast by December 1, Table III- SDP Forecast Enrollment by Program Option by December 1, Table IV- SDP Transition Incremental Expense Forecast Table IV- Summer Discount Plan Recorded Expenses Table V- SDP Program Cost Effectiveness Results... Page -v-

7 I. INTRODUCTION SCE is filing this application to modify its existing residential Summer Discount Plan (SDP), an air conditioner (AC) load control cycling program, from a reliability-based demand response (DR) program to a price-responsive program to comply with the terms of the Joint Settlement Agreement filed in the DR Rulemaking (Settlement). 1 If this proposal is approved, the program will be used for price-responsive economic dispatch. The SDP resource can offer known and reliable load response on short notice and is readily available on hot days when the wholesale market prices are expected to be higher and more volatile. The current residential SDP has extensive enrollment, with over 0,000 customers enrolled and approximately MW of (DR) capacity. As an emergency-only program, the current program has historically been dispatched on a limited basis and, since 00, primarily been used for localized distribution relief. The combination of bill discounts and limited curtailments in the current SDP program have yielded high customer enrollment and satisfaction. Introducing a responsive trigger to the SDP program, on the other hand, will likely involve multiple curtailments of all enrolled customers. Thus, customer choice is needed to maintain customer enrollment and satisfaction with the proposed program with more frequent curtailments. Offering customers the choice of override or cycling options will mitigate the potential inconvenience and discomfort during curtailment events. Customer choice helps SCE ensure that existing investments in this large program do not become stranded assets. The revised program is designed to provide price-responsive dispatch and load curtailment potential while maximizing customer retention and customer satisfaction. This transition plan balances the needs of participating customers, ratepayers and SCE while integrating the SDP into the California Independent System Operator (CAISO) market. 1 See Reliability-Based Demand Response (DR) Settlement, attached to Joint Motion in Rulemaking (R.) , Phase, dated Feb., 0. CAISO, established in 1, is a non-profit corporation that manages the flow of electricity on California s high-voltage power grid, ensures fair and open access to the transmission grid for all qualified users, operates day-ahead, real-time, and ancillary services markets, and provides grid information. 1

8 SCE requests authorization for approximately $. million in funds to implement this transition plan. This request has two components: (1) incremental funding for 0 above the funding level authorized in Decision (D.)0-0-0 for the 00-0 program cycle; and () full funding for 01. In early 0, as part of the DR program cycle application, SCE will file for SDP program funding for the years 01 and 01. This testimony in support of the application contains all elements of SCE s proposal. In Chapter II, SCE describes the background and factors that contributed to the development of the plan and this filing. Chapter III describes the program proposal and design. Chapter IV provides an explanation of the costs and required funding. Chapter V covers the results of cost-effectiveness analyses. Finally, Chapter VI explains SCE s proposal for cost recovery. --

9 II. BACKGROUND This chapter describes the background and factors that contributed to the development of SCE s transition plan proposal, as well as an overview of the current program. A. Background of SDP SCE s AC cycling program, now known as SDP, was established in the early s to provide load relief at times of SCE system emergencies. When a customer enrolls on the SDP program, SCE installs a remote-controlled device on the participating customer s central air conditioner outdoor compressor unit. During curtailment events, participating residential and commercial customers AC compressors are remotely cycled off and on, as necessary, to control the unit s electric load. In return for participating in the SDP program, customers receive a credit on their electric bills each year from the first of June until the end of September. Enrollment in the program has grown significantly in the last decade. This growth trajectory began during the California energy crisis when the California Public Utilities Commission (CPUC or Commission) directed SCE to increase customer enrollments to increase potential DR load reduction during system emergencies. 00 brought heat storms and two Commission decisions directing SCE to significantly expand the SDP program. D directed SCE to enroll an additional 0,000 customers per year, in addition to the approximately 0,000 new customers already authorized in the 00 General Rate Case (GRC). Resolution E-0 directed SCE to accelerate enrollment approved in D and add MW of new load reduction capacity by 00. Beginning in 00, because of a shift in the Commission s DR policy away from emergency- to price-responsive DR, SCE limited SDP program marketing to replace attrition and allow for only modest growth SCE also anticipated that Edison SmartConnect advanced metering and associated home area network technologies would also bring significant changes to DR programs. See Resolution E-0, Ordering Paragraph, p. 1, filed Oct. 1, 00. The resolution also allowed SCE to conduct up to two 0-minute test events per year. See D.0-0-0, pp. 0-.

10 B. Demand Response Policy Changes The Commission has focused on the importance of price-responsive DR as a means to lower overall wholesale electricity costs and enhance competition in wholesale power markets. Further, the Commission has indicated that reducing consumer electricity usage during peak periods can help reduce fuel use and overall greenhouse gas (GHG) emissions. The Commission opened a rulemaking on January 1, 00 to examine and develop effective DR programs. It also identified consideration of modifications to demand response programs needed to support the [CAISO s] efforts to incorporate demand response into market design protocols. Phases 1 and were initiated to address DR program cost-effectiveness, load impacts, and goals. Phase was initiated to address the operation of the Investor-Owned Utility (IOU) emergency-triggered DR programs in the future electricity wholesale market. One of the key elements explored in Phase was the CAISO s contention that the amount of emergency-triggered DR of the three IOUs should be reduced to 1,000 MW. The CAISO estimated the 1,000 MW based on the need to address percent of its all time system peak load of 0,0 MW. During the course of this rulemaking, SCE actively explored potential DR program modifications with other parties. As a first step, SCE and the other utilities reached an agreement with the CAISO and other stakeholders to alter the emergency trigger so SDP could be dispatched after CAISO issues a Warning and a Stage 1 Emergency is imminent. Previously, the emergency DR resources were higher in the resource stack and only available to the CAISO once a Stage Emergency was issued. In 00, the Commission produced the Energy Action Plan (EAP) II that set a goal of five percent of peak demand to come from price response from consumers by 00. See EAP II, p., found at (last visited June, 0). See 00 EAP Update, p., found at CCB1EBE/0/00_EAP_UPDATE.PDF (last visited June 0, 0). See also D.0-0-0, p. 0. Order Instituting Rulemaking (R.) , dated Jan. 1, 00, p. 1. CAISO Peak Load History 1 through 00, showing megawatts, date and time found at (last visited June, 0). SDP trigger modifications were filed in SCE s Advice Letter -E and were approved by the Commission on May 1, 00.

11 A more significant step toward advancing the goal of integrating DR programs into the market was achieved on February, 0 when SCE and other parties filed the Settlement. The Settlement addresses the operation and integration of the utilities emergency-triggered DR programs in the wholesale electricity market. The Settlement limits the amount of reliability-based and emergencytriggered DR that will count for resource adequacy and commits the IOUs to implement and promote price-responsive options for reliability-based DR program participants. The Settlement called for SCE to submit an application by the second quarter of 0 that introduces a price-responsive option into the SDP program such that the program can be bid into the CAISO s markets. Further, the Settlement notes that once the Commission approves the proposal, SCE will undertake a multi-year transition effort that takes into consideration the roll-out of SCE s Edison SmartConnect metering infrastructure and the potential replacement of customer hardware devices with a new technology that enables the integration of the program into the market. SCE s transition plan will be discussed in detail in Chapter III. The benefit of including a price-responsive trigger to a flexible, limited-use, quick-response DR resource like the SDP program is that it can compete as a resource at the highest cost hours of the year. As shown in the load duration curve figure below, the top percent of the CAISO system peak load occurred over only 0 hours in 00. SCE s proposal to transition the residential SDP load, approximately 0 MW in demand response capacity, so that it is available to bid into the CAISO markets help mitigate those high peak hours. See Reliability-Based DR Settlement, attached to Joint Motion in R , Phase, dated Feb., 0. See D.-0-0, Appendix A, p.

12 Figure II-1 CAISO Load Duration Curve Sept 1, 00 to Sept, 00 1,000 0,000,000 0,000,000 0,000,000 0,000 1, ,0 1, System Demand; (MW) 1, 1, 1,,01,00,0,1,,1,,,,,,0,,0,01,,,,,0,1,0,,,,1,,,,1,1,0 0,0 MW Peak Demand % of Peak or, MW (-,1 MW) Demand >, MW Only 0 Hours/Yr % of Peak or, MW (-,0 MW) Demand >, MW Only Hours/Yr All-time System Peak July, 00 Hours 1 1 C. Impact of Edison SmartConnect on SDP In September 00, the Commission authorized SCE s Edison SmartConnect program. By 01, SCE expects to deploy advanced interval metering and communications infrastructure to approximately million residential and small commercial and industrial customers (<00 kw). Through this program, SCE will be able to offer new dynamic pricing and DR offerings to these customers. The infrastructure will also enable two-way communication capabilities which will enhance DR programs by allowing SCE to offer new enabling technologies such as Programmable Communicating Thermostats (PCTs). The increased choice and functionality of new technologies is expected to improve the appeal of load control programs and assist customers in participating in DR curtailment events. By employing these new capabilities and technologies, SCE expects to enroll more consumers in its programs. The opportunity for further growth in AC load control is particularly promising. Currently, SCE estimates that it has enrolled approximately 1 percent of its customers with central AC in its current SDP 1 Source: Training presentation by John Goodin on Feb. 1, 0 at the CAISO.

13 program. With new technologies, SCE reasonably expects that it could enroll percent of eligible customers. Metering and communications infrastructure is a key enabler to further the Commission s objective of achieving price-responsive DR that is integrated into the wholesale electricity market. As SCE has developed its transition plan for the existing SDP participating customers, SCE has carefully considered how to complement the new Edison SmartConnect capabilities and achieve alignment with the future direction of load control as envisioned in the Edison SmartConnect business case. This alignment will be addressed further in Chapter III. D. Current SDP Program SCE currently has the largest AC cycling program in California and one of the largest programs in the nation with over 0,000 residential customers and over,000 commercial customers enrolled in the program representing MW of DR capacity. SCE conducted a market research study and found participant satisfaction with the program was rated at 1 percent in 00 based on whether the program was worth the effort, and is among the highest of SCE programs surveyed. 1. Program Design The current SDP program is structured as an emergency- or reliability-based program. Curtailment event trigger criteria include CAISO declaration of a Stage Emergency and SCE declaration of a Category 1,, or Storm Alert that may jeopardize the integrity of SCE s distribution facilities. As discussed in Section B of this Chapter, in 00 SCE added an additional emergency-based trigger to the program to allow the CAISO to call SDP after a Warning Notice has been issued and when a Stage 1 Emergency is imminent, provided the CAISO has exhausted all other options to prevent further degradation of its operating reserves. Eligible residential and commercial customers may choose currently between either the Base 1 program that allows SCE to cycle off the air conditioner a maximum of 1 times per summer 1 See Schedule D-APS: Domestic Automatic Powershift at (last visited June, 0).

14 1 1 1 season or the Enhanced 1 program that allows SCE unlimited cycling interruptions. The Enhanced program provides approximately twice as much in incentives as the Base offering. SCE also currently offers customers choices between various cycling options for customer comfort. Residential customers may select either the 0 percent or 0 percent cycling options 1 and commercial customers may select the 0 percent, 0 percent, or 0 percent option. The 0% and 0% cycling options reduce load, but still allow for some air conditioner operation, while the 0% cycling option shuts off the compressor for the duration of the event. The SDP customer incentives are based on whether customers select the Base or Enhanced option, their cycling strategy, and the size or tonnage of their AC unit. 1 Residential and small commercial customers receive a daily bill credit and the larger commercial customers receive a monthly bill credit for their participation from June 1 until October 1. Customers must remain on the program for one year after receiving service in the program. Table II-1 below summarizes the program options, participants, and MW for residential customer participants as of May 1, See Schedule D-APS-E: Domestic Automatic Powershift-Enhanced at (last visited June, 0). 1 The % cycling strategy for residential customers was closed to new enrollment in Advice Letter -E and the existing customers were grandfathered on the cycling strategy. The 0% cycling strategy for commercial customers was closed to new enrollment in Advice Letter 0-E and the existing customers were grandfathered on the cycling strategy. 1 Incentives may be adjusted due to minimal energy usage. 1 SCE has. MW of commercial customer participants as reported on SCE s May 0 Report on Interruptible Load Programs and DR Programs, submitted on June 1, 0 in Application (A.) , p.1. Thus, the total SDP program represents MW of DR capacity.

15 Table II-1 SDP Residential Enrollment As of May 1, 0 Line Participants No. Program Offering No. enrolled Percentage MW 1 1. Base:. 0% cycling, 1%.0. % cycling,0 %.. 0% cycling 0,01 1%.. Enhanced:. 0% cycling,0 1%.. % cycling 1,00 %.. 0% cycling 1,0 %.. Total 1, 0% Load Control Technology and Communications Infrastructure SCE currently has over 0,000 SDP load control devices active in its service territory. These one-way communicating devices are activated through commands received via the Very High Frequency (VHF) Radio Frequency (RF) network. The VHF RF Transmitter network receives information from SCE s existing load control platform, the Alhambra Control Platform (ACP), and transmits it on a radio frequency to the devices. SCE s VHF radio communications network includes VHF RF primary transmitter towers. These towers have been strategically placed throughout SCE s service territory to provide sufficient geographical coverage to accommodate the locations of the SDP program participants. Load control technology used for the SDP program has evolved as SCE s DR programs have grown and diversified. Given the communication limitations associated with VHF radio technology, SCE began procuring a more efficient load control device technology beginning in 00. The older device technology required frequent communication from the control platform to ensure that it 1 MW is calculated according to A monthly reporting requirements. SCE calculates the ex ante MW using the number of enrolled accounts multiplied by the ex ante average load impact per customer of 1. kw.

16 performed as desired. As an example, during a cycling event, the older technology required that a cycling event message be sent to it every minutes for it to continue cycling. The new load control devices are able to operate more autonomously, requiring less broadcast time through the VHF radio technology to communicate event signals. Specifically, during a cycling event, only two cycling event messages per hour need to be sent. Given that the majority of the SDP program growth has occurred since 00, approximately 1 percent of the active load control devices are using this more efficient technology. At the same time, SCE has also been addressing the 1 percent of active load control devices that are using the less efficient technology. First, SCE has been replacing many of these old devices with the newer technology by using the maintenance funding that SCE received approval for in D These older devices have installation dates ranging from 1 to 00. Because devices have an expected operating life of to 1 years, SCE has been replacing the oldest devices in areas with constrained distribution circuits. Second, to ensure efficient communication and operation of SCE s load control system, SCE determined that all of the older devices should only be available to support a single cycling strategy. To minimize disruption, SCE chose the 0 percent cycling strategy because it was the strategy the majority of customers selected. Customers selecting the 0 percent or percent options received communications from SCE offering them the option to switch to 0 percent cycling or to have their load control device switched out.. Event Performance Historically, CAISO requested that SCE dispatch the SDP program for emergencies or local transmission and distribution relief. As shown in Table II- below, the program has been dispatched 1 times since 00 and many of those events were dispatched within a single district. No events occurred in 00. As shown in Chapter III, SCE intends to increase the use of the SDP resource through the introduction of a new price-responsive trigger.

17 Table II- SDP Program Events Line No. Date Dispatch level 1. July 1, 00 1 district. July 1, 00 Entire Service Territory. July, 00 Entire Service Territory. August, 00 Entire Service Territory. July 1, 00 districts. July, 00 districts. August 0, 00 1 district. August 1, 00 1 district. September 1, 00 1 district. September, 00 1 district. September, 00 districts 1. September, 00 1 district 1. July 1, 00 1 district 1. July 1, 00 1 district 1. August, 00 1 district 1. September, 00 1 district

18 III. SUMMER DISCOUNT PLAN PROPOSAL In accordance with the terms of the Settlement agreement, SCE outlines its proposal to modify the existing SDP program so that it can be bid as a price-responsive resource into the CAISO s markets. As part of this proposal, SCE also identifies the implementation needs and associated costs. A. Considerations That Informed Transition Plan Proposal Changing a program with high participation levels and customer satisfaction is a challenge. SCE has evaluated numerous options in the development of this transition plan to find an approach that effectively balances the needs of customers, SCE, and external stakeholders. During the development process, SCE has had conversations with the Commission s Energy Division staff, the Division of Ratepayer Advocates (DRA), The Utility Reform Network (TURN), and CAISO about the new SDP proposal. Among many considerations in reshaping this program, four important items stand out. First, SCE considered the characteristics of the SDP resource and how it could best be integrated into the wholesale energy market. SDP offers a known and reliable response on very short notice. The resource is readily available on hot days when the California wholesale market prices are expected to be high and volatile. Further, the SDP program is geographically dispatchable in cases where the resource is needed for only portions of CAISO control areas. Second, an important consideration is maintaining both the participation and satisfaction of the over 0,000 residential participants. The risks associated with an ill-prepared transition plan are quite high. 0,000 customers could become disengaged and decide not to participate in future SCE programs and services if they have a poor experience with the SDP transition. Further, significant ratepayer investment could be stranded if customers opt out of the modified program in substantial numbers. A third consideration is to minimize transition-related technology costs and leverage the existing RF communications infrastructure. The existing communications platform with 0,000 active SDP devices in the field is a reliable and effective resource. Replacing this system, which represents a large ratepayer investment and still has a significant useful life, would be unnecessary and costly. Even if it were economic to do so, it would take many years to replace the extensive infrastructure. 1

19 Fourth, SCE considered whether the modified program design could address the need for emergency firm load reduction at the CAISO and the SCE distribution system level while serving the need for price-responsive load reduction. The current SDP program has considerable value given its rapid emergency response capability. As such, SCE wanted to maintain SDP s emergency capability while leveraging the resource to be bid into the CAISO markets. After careful analysis and consideration of the issues outlined above, SCE presents its proposal to transition all 0,000 residential consumers to its new SDP program design, described in detail below. This transition will mark a major step for SCE toward advancing the Commission's goal of integrating DR programs into the market. With the transition of residential participants to the modified SDP, MW or percent of the total 1 SDP resource will be removed from the reliability-based DR program category and transitioned into the wholesale electricity market as a price-responsive program. SCE is currently evaluating the most appropriate transition plan and timeframe for the commercial SDP customers. From other programs across the country and from SCE s previous experience with the SCE Energy$mart Thermostat SM program, enabling technologies such as PCTs are envisioned to be a key enabler for a commercial customer transition. The timeframe that SCE will be able to offer a PCT solution to customers may change given recent developments in the Smart Energy Profile.0 ratification timeline. SCE is assessing these new developments and will be in a better position to address the transition plans for the commercial SDP customers in its application for the DR funding cycle. B. Proposed Program Design In this proposal, SCE is seeking to eliminate the Enhanced program and modify the Base SDP program to include new features. 0 Table III- below provides an overview of the key features of the modified program. A more detailed discussion of each of the key features follows this table. 1 The total SDP program, including commercial customers, represents MW of DR capacity. See FN 1 above. 0 D authorized closing the Base program to new enrollments, however, SCE believes that eliminating the Enhanced program will allow for a more successful transition. 1

20 Table III- SCE s Summer Discount Plan Proposed Program Design Program Elements Current Design Proposed Design Curtailment Event Emergency only Economic and Emergency Triggers Program Availability Events can occur June 1 September 0 Enhanced Program unlimited events per summer Base Program maximum 1 events per summer Events can be called year-round with a maximum of 0 event hours during a calendar year. Event duration Maximum hours per day Multiple events may occur in a single day, each with potentially varying durations. However, in all cases, a customer will not be interrupted for more than hours in a single day. Load control technology options Load control options 0% cycling; % cycling; or 0% cycling Customer Incentives Direct load control switch Direct load control switch; or Direct load control switch equipped with override capability. Customers will be permitted to override events per calendar year. Incentives based on: device count; AC unit cooling capacity (tonnage); cycling strategy. Credits applied to participants summer bill statements as a daily credit value. 0% cycling; or 0% cycling Incentives will be based on: device count; AC unit cooling capacity (tonnage); cycling strategy ;and override capability. Credits applied to the participants summer bill statements as a daily credit value Curtailment Event Triggers SCE will add a new price-responsive trigger to the program. This new trigger will allow the program to be called when wholesale market prices are high. High market prices can occur in situations of extreme or unusual temperature conditions or higher than expected demand on the system. High prices can indicate or portend emergency situations, and if the program is triggered in such cases, 1

21 it may help prevent an emergency situation from occurring. In addition to adding the price-responsive trigger, SCE will maintain the emergency-based triggers that are in effect today.. Program Availability SCE will convert SDP from a summer season program (defined as June 1 to September 0) to a year-round program. Changing the program availability to year round will allow the program to be used to address situations that can occur throughout the year, particularly in the shoulder months when warmer weather or higher market prices may occur while some generation resources are down for maintenance. SCE will enhance the program s effectiveness by converting it from an event-based to an hourly-based program. Allowing the program to be limited by number of hours rather than events will bring added flexibility to the program. Under the parameters of the current Base program, customers maybe be called for up to 1 curtailment events throughout the summer season, with events lasting up to hours (0 hours maximum per summer). Over the last years, emergency events have lasted an average of hours and 0 minutes. On average each year,,00 customers of the approximately 00,000 enrolled have experienced curtailments since 00. With the proposed program modifications, SDP participants will be available for 0 hours of curtailment per calendar year. Given the introduction of the new market-based trigger, SCE expects that most program participants will experience curtailment hours due to CAISO price-responsive market calls. These price-responsive events are expected to last from one to three hours. An hourlybased program maximizes dispatch flexibility, especially in the day-of hourly wholesale market. Customers may also be called for emergency curtailments similar to previous years depending on system conditions.. Event Duration SCE proposes to maintain a maximum event duration of six hours per day; however, most curtailment events are anticipated to be shorter in duration. Customers may not even feel a change in temperature in their homes with the shorter events. The proposed program design allows for multiple events per day, but in all cases curtailment will not exceed a cumulative daily duration of six hours, 1

22 which is what it is today. SCE has relied on the ability to call the program for the six hour duration during certain emergency situations like the 00 Southern California heat storm, when about 1,000 customers were curtailed for six hours per day on four of five consecutive days. Allowing multiple events up to a total of six hours will make the modified SDP more responsive to system needs.. Load Control Technology Options In the modified program, SCE will offer existing customers the choice to maintain their existing load switch or to replace it with an override enabled load switch. The override option is not currently available with SCE s existing program and direct load control devices. Customers will be allowed to override no more than five curtailment events in a calendar year. Customers opting for the override technology will receive significantly reduced incentive levels compared with customers who do not choose this feature. SCE is introducing the override feature for a number of reasons. First, offering customers with choices such as an override feature is an important way to ensure their continued participation in the program. Empowering customers with choices helps maximize program enrollment and mitigate potential customer attrition, dissatisfaction and stranded infrastructure costs due to increased dispatch frequency in the new program. Second, offering an override option to existing participants ensures alignment with the future direction of SCE s load control programs as described in SCE s Edison SmartConnect business case. A key feature of future enabling technology programs like the PCT is the ability for the customer to override an event. 1 Third, other utilities that are employing similar load control approaches to what SCE is proposing are offering an override feature as a key part of their program. Baltimore Gas and Electric s (BGE s) PeakRewards AC Program is available for emergency purposes and is bid into the capacity and energy markets of PJM Interconnection. This program offers an override feature and has nearly 1 See A.0-0-0, Vol., at pp. -, 1-1. PJM Interconnection is a regional transmission organization that serves 1 states and the District of Columbia. 1

23 00,000 customers enrolled. Nevada Energy s CoolShare Program is triggered quite extensively, averaging about events of up to hours per event each summer. This program also offers an override feature and has nearly 0,000 customers enrolled. Although existing load switch technology and communication infrastructure does not allow customers to opt out of curtailment events, SCE can leverage its existing technology platform to enable the override feature. SCE has worked with its load switch vendor to develop a prototype load switch which is the same as the current device except that it has an override button and light emitting diode (LED) lights that provide indicators for override status. See Figure III-. Figure III- Prototype Load Control Device with Override Feature 1 1 By pressing the button on the device before or during an event a customer may override an event. Further, SCE will be able to enforce limits on override capabilities with enhanced firmware by sending messages from its load control platform to overrideable devices to set the number of allowable curtailment events. SCE can remotely program these new load switch devices to either enable or disable the override feature. Once these devices are set in the field, if a customer requests to switch from an The prototype device will need to go through testing, Underwriters Laboratories certification and Federal Communications Commission approval. 1

24 overrideable option to a non-overrideable option, these changes will not require a field visit or device change. SCE is committed to leveraging capabilities coming with Edison SmartConnect to implement a PCT load control program. However, it will be important to continue offering a load switch option to customers as part of its load control program offerings. Upon assessing other utilities offers, SCE determined that a significant portion of customers prefer AC compressor switches over PCT devices. Both BGE and Pacific Gas and Electric (PG&E) offer multiple technology options. BGE s customers chose the AC switch percent of the time, while PG&E attributes roughly 0 percent of its current enrollment to this technology. Equipping air conditioner compressor switches with override capability achieves the desired consistency with the new PCT program, which will also include an override feature. SCE intends to explore how it can leverage interval data collected from SmartConnect meters to detect air conditioner compressor switch operation during SDP events, thus providing a comparable solution to the two-way communications infrastructure that will be implemented as part of the Edison SmartConnect project.. Load Control Options In the modified SDP program, SCE will continue to offer cycling strategy options. As discussed in detail in Section of this Chapter, it is important to offer customers choices as part of this transition because of the increased dispatch frequency. Like the override feature, a partial cycling strategy is a viable alternative for a customer to consider if they believe the 0 percent cycling will be too disruptive. However, customers will be compensated more for the 0% option. To simplify program design as well as SCE s operations, SCE will eliminate the percent cycling option and allow customers to choose between 0 percent or 0 percent cycling. In the customer communication efforts associated with this program transition, SCE will notify the approximately percent of existing residential program participants on the percent cycling option Because the existing communications infrastructure provides for one-way communications, SCE cannot remotely detect non-operational devices in the field. 1

25 that they will be defaulted to the non-override 0 percent cycling program option unless they elect otherwise.. Customer Incentives SCE used an avoided capacity valuation methodology for calculating the customer incentives associated with the new SDP program. This is the method reflected in the generation marginal cost portion of a settlement approved in D in SCE s 00 GRC rate design proceeding for non-firm service, price response programs, and reliability programs and the DR cost-effectiveness framework (Consensus Framework). The avoided capacity valuation methodology compares the resource value of each program by applying a set of discount factors to SCE s line loss adjusted marginal costs. The discount factors reflect a program s relative capacity value compared to a proxy combustion turbine resource. This methodology is commonly called the A*B methodology, where the A factor adjusts for event duration and call frequency and the B factor adjusts for notification lead time. The A*B factor rises as the DR program attributes behave more like their supply side resource counterparts. Specifically, the greater the availability of the DR program (i.e. higher number of available hours due to a higher number of events and/or longer event duration), the higher the A factor and the greater the value of the DR program. The B factor for programs like SDP that can be called up with as little as 1-minutes notice is 1.0, equating the DR resource with a quick-start supply side resource. The avoided capacity valuation methodology also accounts for resource adequacy requirements by applying a 1 percent reserve margin to an expected demand value with an additional distribution reliability component of $/kw-year also added because the proposed program can be dispatched at a distribution grid level. See D.0-0-0, Attachment B, p.. See R , Joint Comments of Joint Parties of California Large Energy Consumers Association, Comverge, Inc., DRA, EnergyConnect, Inc., EnerNOC, Inc., ICE Energy, Inc., PG&E, San Diego Gas & Electric Company (SDG&E), SCE and TURN Recommending a DR Cost Effectiveness Evaluation Framework, filed Nov. 1, 00. 1

26 1 1 1 The total capacity benefit derived from the avoided capacity valuation methodology is converted to a credit provided on a $/ton/day basis consistent with the current practice. In SCE s 00 GRC, the Commission authorized an increase in SDP incentives based on the A*B methodology. The Commission authorized an increased capacity value from $ per kw-year in SCE s 00 GRC to $/kw-year in the 00 case. Anticipating upcoming program modifications associated with the program transition, SCE requested and received authorization to defer the increase in SDP credits pending the implementation of the transition plan. Table III- shows key program attributes affecting the incentive levels, filed in SCE s 00 GRC Phase. As described in Section III(B), SCE intends to maintain the structure of the current Base program while adding new features. For the Base Program, the A factor is calculated based on a 1 event call frequency and a hour event duration. While allowing year-round calls in the new SDP program (instead of restricting events to strictly the summer season) will marginally increase the A value associated with SDP, the increased A value does not result in a larger program credit after rounding. 0 The current $/ton/day compensation applies to the total number of tariff defined summer days (June 1 Sept. 0). While program activations will now be possible year-round, it is expected that they will be concentrated in the summer season. For program consistency, SCE proposes to continue compensation during the summer months only. The full net (excluding distribution value and line losses) capacity value of $/kw-year was reduced by $/kw-year to account for various program operations expenses. See Volume Marginal Cost in SCE s GRC Phase application (A ) testimony approved in SCE s 00 GRC Phase decision (D.0-0-0), p. and Ordering Paragraph. See D Without this decision, the 0%-Enhanced customers would see an incentive increase from $0./ton/day to $0.1/ton/day in the summer of 0, followed by program modifications and a subsequent reduction back to the original $0./ton/day. 0 The A factor for the Base program increases from 1% to % as a result of adding the year-round call feature. 0

27 Line No. 1. Cycling Strategy 0% - Base Program Attributes Maximum 1 events in summer, - hour event duration Table III- Program Attributes and Incentive Levels "A*B" Factor Estimated Demand Reduction (kw) per Ton Pre-00 GRC Phase Compensation ($/ton/day) 00 GRC Phase Compensation ($/ton/day) 1% 0. $0.1 $0. Note: A*B valuation assumes 1 separate -hour events a) 0% Cycling and Override Option Valuation To establish the compensation for the 0% cycling strategy, SCE began with the valuation described above for the 0% cycling option and discounted the compensation on a pro-rata basis to the estimated amount of load reduction the 0% cycling strategy provides relative to the 0% option. SCE used load estimates whereby the load reductions provided by the 0% cycling strategy equaled roughly half of that provided by the 0% cycling strategy. 1 For program simplicity, SCE rounded this compensation to exactly half that provided under the 0% cycling strategy. Because SCE is also providing an override option to the program, SCE must discount the available compensation to correspond with the expected reduction in DR resulting from customers using the override feature as well as the additional equipment cost of this feature. SCE assessed other utilities' programs that offer override capabilities to get a better understanding of the expected DR impact of this program feature. The reported DR override rates range from 1 percent to percent. The impact of override features varies by a number of factors including curtailment frequency, curtailment duration and method of override. Given this variability and after considering the additional 1 See R , Table -, in Load Impact Estimates for SCE s DR Programs - Residential and Commercial Summer Discount Plan, Agricultural and Pumping Interruptible Program, Real Time Pricing, filed April 1, 0, p.. See PG&E SmartAC Study: (last visited June, 0). See also 00 Air Conditioning Load Management Program NV Energy Southern Nevada Program Year 00, Measurement & Verification Report Final Report, February 0. See also SDG&E Smart Thermostat Pilot Program Report: (last visited June, 0). 1

28 cost associated with providing a curtailable device, SCE did not rely solely on these external estimates and instead proposes to apply a 0% adjustment factor for the override feature for both the 0% and 0% programs. Table III- below shows a high level summary of the proposed program compensation on a $/ton/day and an annual basis. Table III- Residential SDP Program Compensation Line No. $/ton/day Compensation 0% Cycling 0% Cycling 1 Without Override $ 0. $ 0.1 With Override $ 0.1 $ 0.0 Typical A/C tonnage =. Annual Compensation 0% Cycling 0% Cycling Without Override $ 1. $. With Override $. $ C. Long-Term Considerations for the Existing Load Control Platform, Communications Systems and Field Devices SCE intends to operate and maintain the existing program platform and devices for the foreseeable future even though the Edison SmartConnect infrastructure and associated Home Area Network (HAN) device enabled programs will be deployed in the next few years. As discussed previously, the existing communications platform is a reliable and effective resource and replacing this system would be both unnecessary and costly. Because SCE does not intend to decommission the existing platform or systems, existing load switches or those installed over the next few years will not need to be replaced due to obsolescence when SCE s new infrastructure is deployed. Further, as part of its maintenance strategy, SCE will continue to replace non-working switches with new ones. SCE proposes that any replacement switches be overridable even if the participating customer is presently enrolled on a non-overrideable option so as to preserve the option for future years. When Edison SmartConnect enabled PCTs and other load control devices are available, SCE will begin to use two-way communicating devices on a new load control platform. However, SCE does not intend to

29 abandon the 0,000 existing load control devices and procure new devices to operate on the new load control platform. D. Integration of SDP Into CAISO s Market As discussed in Chapter II, Section B, adding a market-based trigger will enhance the effectiveness of the new SDP program and allow SCE to bid the program directly into the CAISO markets using the Proxy Demand Resource (PDR) market product currently under review by the Federal Energy Regulatory Commission. Given that the resource has a known and reliable load response on short notice, SCE expects the program will be used in the day-of market. SCE intends to use a bidding strategy that will optimize the program s value and focus on using the resource for a limited number of hours per day. The bids will be based largely on the opportunity costs associated with the limited use resources or PDRs. The resources would be bid such that curtailments could effectively shave the highest-cost peak demand hours while minimizing retail customer impacts. SCE may be able to increase the number of economic dispatch hours in future years after experience is gained to measure the effects of this type of load control on customer participation and satisfaction. There are two necessary developments to allow the program to be bid into the CAISO s markets. First, market integration would not be feasible without the Edison SmartConnect metering infrastructure. Interval meter data is necessary to facilitate financial settlement of load resources bid into the CAISO markets. Second, the Alhambra Control Platform (ACP) will need to be enhanced to enable the market integration of the new program. Program participants will need to be organized into blocks that align with CAISO bidding geographic boundaries instead of SCE district boundaries as they are today. Given the timeline associated with achieving a resolution of this application, SCE expects to implement the new program and market-based trigger by the summer season in 01. In addition, SCE will evaluate the results of on-going market integration pilots to find other feasible methods for bidding AC cycling load into the CAISO markets. If other methods become viable, SCE will seek Commission approval in the upcoming DR application or other appropriate filing.

30 E. Customer Education and Outreach The development of a customer education and outreach campaign is a critical component of this transition plan. The campaign will be aimed at providing sufficient and relevant information to customers about the program changes and the choices they have so they can make informed decisions about their participation. A well structured and executed communication campaign is key to managing customer expectations and program attrition. To support the implementation of the modified SDP program by June 1, 01, SCE will begin communicating the program changes after the 0 summer season concludes. SCE will leverage a variety of communication channels to reach customers. Initially, bill inserts and/or bill messaging will be used to communicate changes to existing SDP customers. This will be followed by a direct mail campaign that will inform existing SDP participants of the new incentive, cycling and override choice options. In this direct mail communication, customers will be notified of their default plan and be advised of alternate program options. Customers will be able to communicate their program choices to SCE through a variety of channels including SCE.com, directly with a customer service representative, or via a return postcard. For customers who do not respond to this first direct mail campaign, SCE will send an additional letter approximately 0 days later. Prior to the 01 summer season when curtailment events are expected to begin, a letter will be sent to all customers confirming their participation and reminding them of the key program features. In addition to direct mail, SCE will also leverage other distribution channels to communicate information. For example, for those SDP customers who have provided SCE with their address, SCE will contact them with s notifying them of the program changes. SCE s website will also be updated to provide easily accessible information on the new SDP program. Further the website will be enhanced so that it can continue to provide customers with access to current and historical curtailment event information. See next section for discussion of default plans.