Commission Staff Report

Transcription

1 STATE OF CALIFORNIA Edmund G. Brown Jr., Governor PUBLIC UTILITIES COMMISSION 505 VAN NESS AVENUE SAN FRANCISCO, CA Commission Staff Report Lessons Learned From Summer 2012 Southern California Investor Owned Utilities Demand Response Programs May 1, 2013 Performance of 2012 Demand Response programs of San Diego Gas and Electric Company and Southern California Edison Company: report on lessons learned, staff analysis, and recommendations for program revisions in compliance with Ordering Paragraph 31 of Decision

2 ACKNOWLEDGEMENT The following Commission staff contributed to this report: Bruce Kaneshiro Scarlett Liang Uejio Tim Drew Rajan Mutialu Dorris Chow Paula Gruendling Taaru Chawla Jennifer Caron Alan Meck

3 TABLE OF CONTENTS EXECUTIVE SUMMARY... 1 Chapter 1: Introduction... 5 I Summer Reliability and Demand Response Programs... 5 II. Energy Division November 16, 2012 Letter and the Staff Report... 6 Chapter 2: Demand Response Program Load Impact... 8 I. Summary of Staff Analysis and Recommendations... 8 II. Different DR Load Impact Estimates... 9 III. Comparison of DR Daily Forecast and Ex Post Results... 9 IV. Comparison of the 2012 Ex Post to the 2012 Resource Adequacy (RA) Chapter 3: Demand Response Program Operations I. Summary of Staff Analysis and Recommendations II DR Program Trigger Criteria and Event Triggers III. DR Events Vs. Peaker Plant Service Hours IV. Peaker Plant Comparison V. Conclusions Chapter 4: Residential Demand Response Programs I. Summary of Staff Analysis and Recommendations II. Residential Peak Time Rebate (PTR) III. Residential Air Conditioning (AC) Cycling Chapter 5: Non Residential Demand Response Programs I. Summary of Staff Analysis and Recommendations II. Background and Summary of Utility Data III. Commercial Air Conditioning (AC) Cycling IV. SCE s Auto DR V. SDG&E s Demand Bidding Program (DBP) Chapter 6: Flex Alert Effectiveness I. Summary of Staff Analysis and Recommendations II. Background III. Utility Experience with Flex Alert IV. Customer Experience V. The Future of Flex Alert VI. DR Program Ex Post Load Impact Results on the Flex Alert Days Chapter 7: Energy Price Spikes i

4 I. Summary of Staff Analysis and Recommendations II. Definition of Price Spikes III. DR Programs and Price Spikes IV. Conclusion Chapter 8: Coordination with the CAISO I. Staff Recommendations II. DR Reporting Requirements in Summer III. DR Reporting Requirements for Appendix A: Highlight of 2012 Summer Weather & Load Conditions Appendix B: Energy Division November 16, 2012 Letter Appendix C: Descriptions of DR Load Impact Estimates Appendix D: SCE 2012 Monthly Average DR Program Load Impact (MW) Appendix E: SCE 2012 DR Program Load Impact by Event (MW) Appendix F: SDG&E 2012 Monthly Average DR Program Load Impact (MW) Appendix G: SDG&E 2012 DR Program Load Impact by Event (MW) Appendix H: SCE 2012 DR Program Overview Appendix I: SDG&E DR Program Overview Appendix J: SCE Historical DR Event Hours Appendix K: SCE Historical Number of DR Events Appendix L: Summary of SCE s Reasons for the 2012 DR Triggers Appendix M: SDG&E Historical DR Event Hours Appendix N: SDG&E Historical Number of DR Events Appendix O: Utilities Peaker Plant Total Permissible vs. Actual Service Hours Appendix P: Ex Post Demand Response Load Impact on Flex Alert Days Appendix Q: CAISO Energy Price Spikes Appendix R: Utilities Demand Response Reporting Requirements Appendix S: Additional Information ii

5 EXECUTIVE SUMMARY This report is prepared by Energy Division in compliance with Ordering Paragraph 31 of D The purpose of this report is to provide the lessons learned from the 2012 Demand Response (DR) programs operated by San Diego Gas and Electric Company (SDG&E) and Southern California Edison Company (SCE) (Utilities), and to recommend program or operational revisions, including continuing, adding, or eliminating DR programs. Below are highlighted conclusions and recommendations in the report. To see all recommendations, please go to each chapter in the report. In summary, Energy Division makes the following overarching conclusions about the Utilities DR programs: Forecast vs. Ex Post: While a few DR programs met or even exceeded their daily forecast when triggered, on average the ex post results for all program events diverge from the daily forecast by a considerable degree. The majority of programs either provided a mixed performance (the program both over and underperformed relative to its forecast) or were poor performers (consistently coming up short relative to its forecast). Of particular note are the Utilities Peak Time Rebate program 1 and SCE s Summer Discount Plan. 2 (Chapter 2) The divergence between the ex post results and the daily forecasts can be traced to a variety of causes, such as inadequate forecasting methods employed by the Utilities, program design flaws, non performance by program participants and/or program operations. A complete explanation of the reasons for divergence across all programs however, was not possible within the scope and timing of this report. (Chapter 2) 2012 RA vs. Ex Post: Comparing the ex post results to the 2012 Resource Adequacy (RA) forecast is not a good indicator as to how well a DR program performs. RA forecasts are intended for resource planning needs. Ex post load impacts reflect demand reductions obtained in response to operational needs at the time the program is triggered. Resource planning and operational planning have different conditions and serve different purposes. (Chapter 2) DR vs. Peaker Plants: The Utilities used their DR programs fewer times and hours than the programs limits (each program is limited to a certain number of hours or events). In contrast, the Utilities dispatched their peaker power plants far more frequently in 2012 in comparison to historical averages. (Chapter 3) Energy Price Spikes: DR programs are not currently designed to effectively mitigate price spikes in the CAISO s energy market. On many days a DR event was called and 1 SCE s marketing name for Peak Time Rebate is Save Power Day, SDG&E calls it Reduce Your Use. 2 Air conditioning (AC) cycling 1

6 no price spikes occurred, and conversely there were days where price spikes occurred and DR events were not called. The timing and scope of this report did not permit a quantification of the cost of unmitigated price spikes to ratepayers, but in theory, avoidance of these spikes would benefit ratepayers. (Chapter 7) Energy Division also makes the following program specific conclusions about the Utilities DR programs: SCE s AC Cycling Program Forecasting: SCE s 2012 forecasting methodology for its air conditioning (AC) Cycling program (the DR program that SCE triggered the most in 2012) cannot be relied upon to effectively predict actual program load reductions. (Chapter 2) SCE s AC Cycling Dispatch Strategy: SCE s sub group dispatch strategy for its AC Cycling Program (also called Summer Discount Plan) created adverse rebound effects, thereby reducing the effectiveness of the program during critical hot weather days, e.g. 1 in 10 weather. (Chapter 2) SDG&E s Demand Bidding Program: SDG&E Demand Bidding Program produced on average 5 MW of load reduction when triggered, although the US Navy did not participate. The US Navy claimed certain program terms and conditions precluded it from participating in the 2012 program. The Commission s decision to modify the program to a 30 minute trigger may further limit the US Navy s ability to participate. (Chapter 5) Peak Time Rebate Awareness: SCE and SDG&E customers who received utility notification of Peak Time Rebate (PTR) events had higher awareness of the program when compared to customers who were not notified by the utility. More importantly, customers who opted into receiving PTR alerts significantly reduced load. All other customers in the program provided minimal load reduction. (Chapter 4) Peak Time Rebate Free Ridership: The Utilities PTR program has a potentially large free ridership problem, where customers receive incentives without significantly reducing load. SCE paid $22 million (85% of total PTR incentives in 2012) in PTR bill credits to customers whose load impact was not considered for forecast or ex post purposes. 94% of SDG&E s 2012 PTR incentives ($10 million) were paid to customers who did not provide significant load reduction. The inaccuracy of settlement methodology (in comparison to the ex post results) is the main reason for the free ridership problem. The default nature of the program (everyone is automatically eligible for the incentives) aggravates the problem. (Chapter 4). Flex Alert: There is a lack of data to evaluate the effectiveness and value of the Flex Alert campaign. Attribution of savings from Flex Alert is complicated by the fact that load reduction from the Utilities DR programs on the two days Flex Alert was 2

7 triggered in 2012 contributed to reduced system peak load. A load impact evaluation of Flex Alert is planned for (Chapter 6) DR Reports: The Utilities DR daily and weekly reports were useful to the CAISO and the Commission for purposes of up to date monitoring of DR resources throughout the summer. (Chapter 8) In light of above findings, Energy Division recommends the following: DR Evaluation: The Commission should require further evaluation of Utility DR program operations in comparison to Utility operation of peaker plants for the purpose of ensuring Utility compliance with the Loading Order. (Chapter 3) Forecast Methods Generally: The Utilities daily forecasting methods for all DR programs (especially AC cycling and other poor performers) should undergo meaningful and immediate improvements so that the day ahead forecasting becomes an effective and reliable tool for grid operators and scheduling coordinators. (Chapter 2) Forecasting for SCE s AC Cycling Program: SCE should improve forecasting methods for its residential AC Cycling Program with input from agencies and stakeholders. SCE should also pilot more than one forecasting method for the program in (Chapter 2) Forecasting for SDG&E Programs: SDG&E s forecasting methods for its AC Cycling Program (Summer Saver) could be improved doing the following: running a test event and including a correlation variable that accounts for customer fatigue. SDG&E s Capacity Bidding Program forecasting could be improved by including a weather variable. (Chapter 2) SCE s Outreach for Commercial AC Cycling: Through its outreach and marketing efforts, SCE should clearly communicate the new features of its commercial AC cycling program to avoid customer dissatisfaction and dropout. (Chapter 5) Auto DR: Future studies are necessary to explore the load impacts of Auto DR. (Chapter 5) SDG&E s Demand Bidding Program: SDG&E should work collaboratively with the US Navy to design a program to meet the unique needs of the Navy. Key attributes to consider are a day ahead trigger, aggregation of 8 billable meters and a minimum bid requirement of 3 megawatts (MW). (Chapter 5) Peak Time Rebate Design Changes: The Utilities residential PTR program should be changed from a default program to an opt in program, so that bill credits are paid only to customers who opt in. (Chapter 4) SCE s AC Cycling Dispatch Strategy: SCE should reconsider its current strategy of calling groups of residential AC cycling customers in sequential one hour cycling events. Alternatively, if SCE retains its current strategy, it should modify the 3

8 program s incentive structure so that customers who are willing to have their AC units cycled for an entire event (as opposed to just one hour) are compensated more than those who can tolerate only one hour of cycling. (Chapter 4) DR Reports: The Utilities (and Pacific Gas & Electric) should submit daily and weekly DR reports to the CAISO and the Commission for the summers of 2013 and They should follow the same format and data requirements in the 2012 reports, unless otherwise directed by the Commission or Commission staff. (Chapter 8) 4

9 Chapter 1: Introduction I Summer Reliability and Demand Response Programs San Onofre Nuclear Generating Station (SONGS) Units 2 and 3 were taken out of service in January By March 2012, the Commission determined that the outage of SONGS two units could extend through summer Working closely with the Governor s Office, the California Independent System Operator (CAISO), and the California Energy Commission (CEC), the Commission took immediate mitigation actions to ensure that lights stay on in California with the loss of 2,200 MW of capacity provided by SONGS. 3 When considering adding new generation resources, 4 an important action was to further incorporate the Utilities Demand Response (DR) programs into the CAISO s contingency planning and daily grid operations during the summer. This included mapping the Utilities DR programs to grid contingency plans and developing new daily and weekly DR reporting requirements. In addition, the Commission also moved swiftly to approve three new DR programs for summer 2012: SDG&E s Peak Time Rebate (PTR) for commercial customers and Demand Bidding Program (DBP); and SCE s 10 for 10 conservation program for non residential customers. 5 Because of the intensive interagency mitigation effort and relatively cool weather, California grid reliability was not compromised in spite of the SONGS outage. Nevertheless, southern California experienced several heat waves in August and September with the highest temperature reaching 109 F in SDG&E s service area and 100 F for SCE on September The CAISO issued two Flex Alerts: on August 10 and 14. The Utilities triggered all of their DR programs at least once and some on multiple occasions. Throughout the summer, Energy Division (ED) staff monitored the Utilities DR program events on a daily basis and provided weekly briefings to the Governor s Office, the CAISO, and the CEC. Staff observed that, for many event days, the load impact forecasts provided by the Utilities to the CAISO and the Commission in their daily DR reports were inconsistent with the results submitted seven days after each event (referred as the 7 Day report ). In some cases, the Utilities reported much lower load reduction results than they originally forecasted. In addition, load impact forecasts provided by the Utilities throughout the summer were lower than the capacity counted for the 2012 Resource Adequacy (RA) Requirement. This raised a question as to whether the Commission might have overestimated DR load impact for RA purposes or, rather, if the Utilities might have under utilized their DR programs. Sometime in mid summer, the Utilities began to experience price spikes in CAISO s wholesale energy market. Questions were raised on whether the DR programs could be used to mitigate price spikes, and if so, should they be Retired Huntington Beach Units 3 and 4 were brought back on line temporarily. 5 Resolutions E 4502 and E A 1 in 10 (or 10% probability) weather condition in any given years. 5

10 Some of the Utilities DR programs were triggered on as many as 23 events over the five summer months, and many were triggered on two or three consecutive days. Appendix A highlights the DR program load impact on the three hottest days and the three days when SDG&E and SCE experienced highest system peak load. Staff observed that SDG&E s system peak correlate to temperature and biggest DR load reduction happened on the hottest day. On the other hand, SCE s system peak load did not consistently correlate to weather. In contrast, SCE s system load reached its annual peak at 90 F temperature, 10 F cooler than the hottest day in its service territory. Counter intuitively, DR program load impact on a cooler day was actually higher than the amount delivered on the hottest day. This led to questions how the Utilities make decisions to trigger DR programs and whether aspects of the customers experience, such as expectations and fatigue have an effect. In August, CAISO issued two Flex Alerts when it determined a reliability risk due to insufficient supply to meet demand. As expected, the Utilities triggered relatively large amounts of DR programs on both days. CAISO reported that the actual peak load was significantly lower than its hours ahead forecasts and attributed the load drop to Flex Alert events. This parallel dispatch situation raises important questions regarding the effectiveness of the Flex Alert when overlapped with the Utilities DR program events and how customers perceived with these statewide alerts versus local utility DR notifications. Based on the above experience, the Commission concluded that staff should evaluate DR program performance and other lessons learned in order to seek answers to these and other questions. Such lessons could help the Commission to determine the extent of DR program reliability and usefulness and in turn, to the extent to which DR resources can be counted on in CAISO markets and operations. II. Energy Division November 16, 2012 Letter and the Staff Report On November 16, 2012, the Energy Division sent a letter (Energy Division Letter) to the Utilities directing the Utilities to 1) file an application proposing DR program improvements for 2013 and 2014 to mitigate the SONGS outage and 2) provide data and responses to a set of questions on lessons learned from 2012 DR programs. The questions were developed based on the Utilities 2012 demand response experience and fell into six categories: 1. DR Program Performance, which include load impact and program operations, 2. CAISO Market, covering price spikes and market analysis 3. Customer Experience, 4. Coordination with the CAISO and Utility Operations 5. Emergency DR Program Dispatch Order, and 6. Flex Alert Effectiveness The Energy Division Letter is attached in Appendix B of this report. 6

11 On December 21, 2012, the Utilities filed separate applications for the approval of the DR program revisions for 2013 and The Utilities submitted data and responses to the questions attached to the Energy Division Letter and subsequent Assigned Administrative Law (ALJ) rulings for developing the record. 8 Decision (D.) approved certain DR program improvements for and directed the Commission staff to develop a report on the lessons learned from the DR programs in This report is based on a snapshot of data and studies available at the time (i.e. ex post load impact data, utility responses to Energy Division data requests, etc.) On going and future (e.g. Flex Alert load impact analysis per D ) evaluations will shed further light on the issues raised in this report. One point of emphasis in this report is the extent to which the current DR programs delivered their forecasted savings when they were triggered by the utilities. It is important to understand that there are a range of factors that can affect whether a program delivers its forecasted savings targets. Some of these factors can be controlled through good program design, operation and forecasting methodologies. Other factors that can impact program performance are exogenous or outside the utilities control such as temperature, participant enrollment fluctuations, and behavioral or technological changes by the participants. While this report contains certain findings and recommendations for DR programs, we caution against sweeping conclusions or generalizations about DR programs based on this report. The point of this report is to find ways to improve existing DR programs so that they are more useful to grid operators, utilities, ratepayers and participants. 7 A (SDG&E) and A (SCE). 8 On January 18, 2013 and February 21,

12 Chapter 2: Demand Response Program Load Impact I. Summary of Staff Analysis and Recommendations SCE Most of the program event ex post results diverge from the daily forecast by a considerable degree. The daily forecast should be more consistent with the ex post results in order for the day ahead forecasting to be valid and useful for grid operators. Staff recommends that the daily forecasting methods for all programs undergo meaningful and substantial improvements, including more thorough and transparent documentation and vetting through relevant agencies and stakeholders. The Summer Discount Plan (Residential AC Cycling) program forecasting methods in particular requires an audience with a broad panel of agencies and stakeholders. Staff also recommends that SCE pilot more than one forecasting method and conduct interim protocolbased load impact evaluations to identify the most reliable forecasting methods throughout the 2013 summer season. SCE should also be required to address Summer Discount Plan program operation issues before the 2013 summer peak season begins, if possible. Specifically, the strategy of calling groups of customers for sequential one hour cycling events, rather than calling all the customers for the duration of the full event (or other potential strategies), needs to be reconsidered before the program is further deployed. As discussed in detail later in this chapter, this strategy resulted in load increases during the latter hours of events, thereby reducing the overall effectiveness of the program. SDG&E Similar to SCE, many of SDG&E s program event ex post results also diverge from the daily forecast by a considerable degree. The Demand Bidding Program daily forecast was accurate and reliable in predicting ex post results, while the Summer Saver and Capacity Bidding Day Ahead and Day Of program daily forecasts did not accurately nor reliably predict ex post results. The Peak Time Rebate Residential daily forecast was not accurate in predicting ex post results, but consistently underestimated ex post results by approximately 80%. The Critical Peak Pricing and Base Interruptible program did not accurately or reliably predict ex post results, but consistently under predicted ex post load impacts. Due to a weak price signal and inelastic customer demand, the PTR commercial program ex post results were not significant. The CPP E was discontinued as of December 31, Staff recommends (1) including only customers that opt in to receive e mail or text alerts in the PTR residential daily forecast model (2) running a test event to measure % load impact per customer in order to improve CPP daily forecast estimates (3) including a correlation variable in the Summer Saver daily forecast model to account for customer fatigue during successive event days (4) including a weather variable in the CBP daily forecast model in order to have parity with the ex post regression model. 8

13 II. Different DR Load Impact Estimates DR programs load impact are forecasted or estimated at different times for different purposes. The following table summarizes the five different DR load impact estimates that are discussed in this chapter. Detail descriptions and methodologies for each DR program measurement are provided in Appendix C. Table 1: DR Load Impact Estimates DR Load Impact Estimates General Description Purpose Ex Ante for RA (e.g., 2012 RA) A year ahead monthly ex ante load impact potential attributed by individual program under a 1 in 2 weather condition. To determine the RA counting against the Load Serving Entity s system and local capacity requirements. Daily Forecast 7 Day Report Ex Post Results Settlement The Utilities daily estimate of hourly load impact from DR programs during an event period. The Utilities preliminary estimate of hourly load reduction results from each triggered DR program The Utilities most accurate measurement of the load impact results from all of the DR programs triggered in a year. The ex post results are calculated using comprehensive regression models. A measurement of customers load reduction from their specific reference load using a baseline method. To provide the CAISO, CPUC, and CEC the hourly MW provided by DR programs on each event day. To report to the CAISO the load reduction data from the triggered DR programs seven days after each DR event. To report to the CPUC the actual results of the DR events To calculate customers incentive payments for billing purpose. In this proceeding, the Utilities provided the above DR load impact estimates for their DR programs, which are shown in Appendices D to G. III. Comparison of DR Daily Forecast and Ex Post Results A. Overall Program Performance The following section draws on data provided by the Utilities on March 4, in response to the Feb 21, 2013 ALJ ruling, which compares event day forecasts (daily forecast or day ahead forecast) to the event day ex post load reduction estimates. Detailed data and methodological descriptions relevant to this chapter are provided in Appendices C and G. Subsequent to its March 4 filing, SCE updated its ex post results for some of the DR program events in its April 2 Load Impact Report but did not update its March 4 filing accordingly. However, in most cases, the April 2, 2013 updated ex post results are even lower than the March 4 preliminary data, e.g., the AC cycling. Therefore, if the updated data was used, it would further support staff s findings. 9 SCE 03 and SGE 03. 9

14 On average, the ex post results for all program events diverge from the daily forecast by a considerable degree. While some program events were forecasted more accurately and consistently than others, Energy Division staff s overall conclusion is that the daily forecasting methods for all programs requires meaningful and immediate improvements in order for the day ahead forecasting can become an effective and reliable tool for grid operators. Some of the divergence between the ex post results and the daily forecast estimates can possibly be explained by inadequate program design and program operations. This section focuses on the observed differences between the ex post and the daily forecast with an eye towards identifying improvements for day ahead forecasting, and thus does not cover all potential program improvements. Furthermore, many program design and operational improvements that could lead to better ex post results may not be evident by simply inspecting the daily forecast and ex post data. The ex post analysis methods are guided by Commission adopted load impact protocols 10 and the study results are carefully documented in reports prepared by independent consultants managed by SCE staff. However, there are currently no comparable standards and processes guiding the methods for daily forecasting. Indeed, during the course of preparing this report, Energy Division staff became aware that the day ahead forecasting methods are far from transparent, and in some cases lack the robust analysis that is expected of the Utilities. These problems may be somewhat understandable, however, since the daily reports were only formally instituted in While this report is highly critical of the implementation of the day ahead forecasting, it is important to recognize that the 2012 DR events as a whole did indeed reduce participants loads, and some of the program load reductions were consistent with or better than the day ahead forecast. To that end, staff has categorized the demand response programs into three categories (good, mixed, and poor performance) based on how well the program events performed relative to the day ahead forecasts. SCE Programs that performed well yielded load impacts that were consistent with or better than the day ahead forecast. The Base Interruptible Program (BIP) and the Day of Capacity Bidding Program events produced load reductions that were on par with the forecasts. It is worth noting that BIP, the single largest program, was triggered on only one occasion in 2012 however, and this was test event. Program events with mixed performance were not consistent with the day ahead forecast, but sometimes exceeded the forecast. Staff includes the Day ahead Capacity Bidding, Demand Bidding, and the Residential Summer Discount Plan program events in this category because these program events did indeed occasionally exceed the day ahead forecasts by a significant margin. These programs are discussed in greater detail elsewhere in this section and report. While considered to be mid performing programs, they do have many important issues that deserve attention. 10 Decision

15 Program events that were consistently below the forecast are considered to be poor performing programs. All of the Critical Peak Pricing, Peak Time Rebate, Demand Response Contracts, Commercial Summer Discount Plan, and Agricultural Pumping Interruptible program events triggered during 2012 produced load reductions that were lower than forecasted. Table 2: SCE s DR Overall Performance Programs No. of DR Events Daily Forecast Ex Post Difference % Good Performance: Capacity Bidding Program Day of >2 >17% Base Interruptible Program % Mixed Performance: Capacity Bidding Program Day Ahead to % to 86% Demand Bidding Program to 16 40% to 21% Summer Discount Plan (AC Cycling) Res to % to 58% Poor Performance: Critical Peak Pricing < 5 < 11% Peak Time Rebate < 11 < 11% Demand Response Contracts < 70 < 34% Summer Discount Plan (AC Cycling) Com % Agricultural Pumping Interruptible < 19 < 52% SDG&E (Averaged MW over All Events) (Range from Low to High) Utilizing the same criteria for evaluating SCE DR programs, The Base Interruptible Program and the Critical Peak Pricing Program were categorized as good performers, the Capacity Bidding Day Ahead, Capacity Bidding Day Of, Demand Bidding, and Summer Saver (AC Cycling) were categorized as mixed performers, and the Critical Peak Pricing Emergency and residential Peak Time Rebate programs were categorized as poor performers. As stated above, DR program design and operation characteristics also need to be taken into account for a complete evaluation of DR program performance. 11

16 Table 3: SDG&E s DR Overall Performance Programs B. Program Performance During Critical Event Days The critical event days of August 10th, 13th, 14th, and September 14th were selected as a focus because they occurred on Flex Alert days, the service area system peak day, or the hottest days of the year. These are all conditions when demand response resources are most critical. August 10, 2012 SCE Two SCE programs were called on August 10th, a Flex Alert day. The programs triggered during that event were the Demand Bidding Program and the Save Power Day (also known as the Peak Time Rebate program). The load reductions achieved during the Demand Bidding Program event surpassed the forecast by 12%, while the Save Power Day event was below the forecast by 11%. Table 4: SCE s August 10, 2012 Demand Response Events Program Name Number of Events Daily Forecast MW Daily Forecast Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C=B A D=C/A Demand Bidding Program % Save Power Day % Total Ex Post Difference % (Averaged MW over All (Low To High) Events) Good Performance: Base Interruptible Program % Critical Peak Pricing > 2.4 >3.1% Mixed Performance: Capacity Bidding Program Day 7 Ahead to % to 12.2% Capacity Bidding Program Day Of to % to 6.0% Demand Bidding Program to % to 8.0% Summer Saver (AC Cycling) to to 38.7% Poor Performance: Peak Time Rebate Residential < 24 < 73.6% Critical Peak Pricing Emergency < 0.7 < 53.3% 11 SCE did not provide a daily forecast for this event, so the comparison for this event is done with the 7 day report rather than the daily forecast. 12

17 SDG&E Three DR programs were called on August 10 th. The Capacity Bidding Day Ahead program load reduction exceeded the forecast by 1%. Conversely, the Summer Saver and residential Peak Time Rebate forecasts under predicted the forecast by 32% and 75%. Table 5: SDG&E August 10, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C = B A D=C/A Capacity Bidding Day Ahead % Summer Saver (AC Cycling) % Residential Peak Time Rebate % Total August 13, 2012 SCE August 13, 2012 was the system peak day for the SCE service area, with a peak load of 22,428 MW. As shown in Table 6 below, the Critical Peak Pricing program, a dynamic pricing program for commercial and industrial customers over 200 kw, and the Day Of Capacity Bidding Program were triggered during this day. Again, the Capacity Bidding Programs exceeded the forecast by a few MW. The Critical Peak Pricing program event had satisfactory performance, falling short of the forecast by 15%. Table 6: SCE s August 13, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C=B A D=C/A Critical Peak Pricing % Capacity Bidding Program (Day Of) % Total SDG&E All three DR programs that were triggered on August 13th, Capacity Bidding Day Of, Summer Saver (AC Cycling), and Critical Peak Pricing, had ex post load impacts that were respectively below daily forecast predictions by 27%, 45%, and 48%. 13

18 Table 7: SDG&E s August 13, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C= B/A D= C/A Capacity Bidding Day Of % Summer Saver (AC Cycling) % Critical Peak Pricing Emergency % Total August 14, 2012 SCE August 14, 2012 was another Flex Alert day, during which seven events were called, using a variety of DR programs. As shown in Table 8 below, all the events combined were forecasted to reduce loads by 570 MW. However, the ex post load impact evaluations found that the actual load reductions were short of the total forecast by 155 MW. 60% of the 155 MW shortfall is attributed to the Demand Response Contract program. The Agriculture Pumping Interruptible program event was short of the event forecast by 52%. Only the Capacity Bidding Program exceeded the forecasted load reduction, but this only made up 4% of the Demand Response Contract program forecast, and thus was insufficient to cover the overall event day shortfall. It is worth noting that the Demand Response Contract and Capacity Bidding Programs share something in common in that they are both commercial aggregator programs. The reason for the difference in performance between these programs requires further study. It should be noted that SCE s Demand Response Contracts expired on December 31, 2012 and have since been replaced by new contracts that that expire at the end of Table 8: SCE s August 14, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C=B A D=C/A Demand Response Contracts % Demand Bidding Program % Agriculture Pumping Interruptible % Summer Discount Plan (Res) Group % Capacity Bidding Program (Day Of) % Summer Discount Plan (Res) Reliability % Summer Discount Plan (Com) % Total D

19 SDG&E Four DR programs, Demand Bidding, Critical Peak Pricing, Capacity Bidding Day Ahead, and residential Peak Time Rebate, were called on August 14 th. While the Demand Bidding and Capacity Bidding Program ex post load impacts closely matched the daily forecast, the Critical Peak Pricing and residential Peak Time Rebate did not. Since the Critical Peak Pricing and residential Peak Time Rebate programs are large scale residential programs it is possible that the difference between the forecast and ex post load impacts reflect widely varying customer behavior during DR events. Table 9: SDG&E s August 14, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C=B A D=C/A Demand Bidding Program % Critical Peak Pricing % Capacity Bidding Program (Day Ahead) % Residential Peak Time Rebate % Total September 14, 2012 SCE September 14, 2012 was the hottest day of the year in both the SCE and SDG&E service areas (see Table 10 below). Understandably, SCE triggered their Summer Discount Plan (residential AC Cycling Programs) during this day. The Capacity Bidding Program was also triggered, with performance comparable to the other Capacity Bidding Program events on critical days discussed above. The September 14 residential Summer Discount Plan events consisted of three separate customer groups sequentially triggered for one hour events. All three one hour events fell considerably short of the forecasted load reductions. Table 10: SCE s September 14, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post A B C=B A D=C/A Summer Discount Plan (Residential) Groups 5 and % Summer Discount Plan (Residential) Groups 1 and % Capacity Bidding Program (Day Of) % Summer Discount Plan (Residential) Groups 3 and % Total

20 SDG&E On September 14, 2012, the peak temperature in SDG&E s service territory was 109 degrees. The Demand Bidding, Summer Saver, and Base Interruptible Programs ex post load impacts were above the daily forecast in a range between 8% and 167%. Since the absolute value of the Base Interruptible Program load impact is ~ 1 MW, a small increase or decrease in the daily forecast prediction can result in high variability in the percent difference between these two figures. Conversely, the Capacity Bidding Day Of and Day Ahead Programs and the Critical Peak Pricing Emergency Program daily forecasts were below the daily forecast in a range between 12% and 44%. Table 11: SDG&E s September 14, 2012 Demand Response Events Program Name Daily Forecast MW Ex Post MW Difference Forecast & Ex Post MW % Difference Forecast & Ex Post C. Detailed Program Analysis A B C=B A D=C/A Capacity Bidding Program (Day Of) % Capacity Bidding Program (Day Ahead) % Demand Bidding Program % Summer Saver (AC Cycling) % Base Interruptible Program % Critical Peak Pricing Emergency % Total The following section discusses programs and events that produced load reductions forecasted by the daily reports, as well as programs that failed to produce the forecasted load reductions. For this purpose, all programs and events that came within 10% (+/ ) of the forecasted load reductions are considered to be consistent with the daily forecast and all programs and events that were more or less than 50% of the forecasted load reductions are considered to have failed to produce the forecasted load reductions. SCE There were a total of 104 separate events in the SCE service area in Only ten of these events produced the load reductions consistent with those forecasted in the daily reports. As shown in Table 12 below, all of these events produced fairly sizable load reductions, ranging from 59 to 130 MW, with the exception of one Capacity Bidding Program event, which produced a very small load reduction. 16