31. Categorization and Assignment of Proceeding
This proceeding is categorized as ratesetting. Rachelle B. Chong is the assigned Commissioner and Jessica T. Hecht is the assigned Administrative Law Judge in this proceeding.
1. The cost effectiveness estimates included in the applications are sufficient to support our review in this proceeding.
2. Emergency-triggered demand response activities are programs that are not triggered by the IOUs in response to wholesale energy market prices, but are instead triggered in response to an actual or imminent declaration by CAISO of a system emergency, or during, or in anticipation of, a local transmission or distribution emergency.
3. Price responsive demand response programs generally have triggers other than a called CAISO emergency, such as weather conditions or the market cost of electricity.
4. Phase 3 of R.07-01-041 is intended to determine the appropriate amount of capacity (in megawatts) to enroll in emergency-triggered demand response programs, and how to transition any excess capacity to non-emergency programs with price responsive triggers integrated with the new CAISO markets.
5. The SmartAC program and budget were approved by the Commission on February 14, 2008, in D.08-02-009, which approved a settlement agreement among PG&E, DRA, and TURN allowing PG&E to expand its SmartAC program to approximately 305 megawatts of load reduction by June 1, 2009.
6. The following existing demand response programs are cost effective or meet other criteria for continuation during the 2009-2011 period, and should be continued: the Base Interruptible Program, the Optional Binding Mandatory Curtailment Program, the Scheduled Load Reduction Program, the Capacity Bidding Program, Critical Peak Pricing, Real Time Pricing, Technical Assistance and Technology Incentives, Emerging Markets and Technology, Automated Demand Response; SCE's Summer Discount Plan, Agricultural Pumping - Interruptible, Rotating Outage Program, and Agricultural Pump Timer Program; SDG&E's Critical Peak Pricing - Emergency, and Summer Saver programs; and PG&E's SmartAC, SmartRate, Demand Bidding Program, and PeakChoice.
7. PG&E's proposed transition of Base Interruptible Program participants into its PeakChoice does not appear to be fully developed at this time.
8. It is unclear whether PG&E can maintain the Demand Bidding Program's load impact if the Demand Bidding Program is discontinued and participants are asked to transition to PeakChoice.
9. It is likely that enrollment in and load impacts of Critical Peak Pricing tariffs will increase as they become default tariffs for certain groups of customers.
10. PG&E's PeakChoice program is new and complex, and its impacts may be difficult to analyze.
11. PG&E's administrative costs for PeakChoice program are extremely high compared to the estimated costs of incentives under the program.
12. PG&E's Business Energy Coalition Program is not cost effective, and it is extremely unlikely that this program or the proposed Automated Business Energy Coalition Program will become cost effective over the next several years. The non-cost effectiveness criteria cited by PG&E in support of this program, such as locational value and flexibility, are not unique to the Business Energy Coalition programs, and are not sufficient to support continuation of these programs.
13. Current estimates show that the SCE Summer Discount Program is only marginally cost effective; the cost effectiveness may be improved if SCE is able to maintain enrollment in the program with a decreased budget for marketing.
14. The communications supported by the Rotating Outage Program include both Commission-mandated notices and courtesy notifications intended to facilitate the administration of emergency rotating outages.
15. SCE's Agricultural Pump Timer Program utilizes Time Management Load Control devices to allow customers to interrupt their equipment at peak times, in order to take advantage of low off-peak utility rates.
16. Critical Peak Pricing programs overall have high estimated benefit to cost ratios based on the Total Resource Cost Test.
17. Technical Assistance and Technology Incentives activities differ somewhat in participation requirements, incentive payments, and other structural aspects, but all support the installation of technologies to facilitate customer peak load reduction and demand response.
18. Technical Assistance and Technology Incentives activities facilitate peak load reduction and demand response by utility customers, and in many cases lead directly to customer enrollment in utility demand response programs.
19. Technical Assistance and Technology Incentives activities include many activities that do not result in the payment of financial incentives, but provide valuable services to customers. These services, such as conducting audits, developing company-specific demand response plans, and recommending equipment and strategies to improve load reduction, are not true program administration activities (such as data collection or processing), and should not be considered program administration in the determination of program budgets.
20. SCE's method of reporting money spent under its Technical Assistance and Technology Incentives program makes it difficult to determine the demand for this program or the budget required to sustain it through 2011.
21. Because the Technical Assistance and Technology Incentives programs provide services to customers beyond financial incentives, such as audits, it is not appropriate to limit the budget for Technical Assistance and Technology Incentives activities to twice the financial incentives paid to customers.
22. The Emerging Markets and Technologies Programs fund research projects intended to further develop technologies and equipment, processes, and products to make demand response easier or more effective in the future.
23. It is not appropriate to give blanket approval now for long-term emerging technologies projects that cannot yet be identified.
24. Automated demand response refers to automated enabling technologies that allow a customer to reduce electricity usage in response to peak load conditions or high prices without needing to take a specific action.
25. Automated demand response activities appear to result in some load reduction, through participant enrollment in other demand response programs.
26. The utilities have not submitted any analysis of whether automated demand response programs are cost-effective on their own, separate from the underlying programs in which participants ultimately enroll.
27. Through the use of mass media such as TV commercials, radio advertisements, billboards, newspapers, and other communication avenues, Flex Alert is intended to educate the general public about the need to reduce electricity during times of peak electricity demand.
28. A working group related to the California Energy Efficiency Strategic Plan is exploring alternatives for statewide coordination and branding for demand side awareness.
29. The challenge of keeping the power grid in balance grows as the amount of intermittent resources grows.
30. Smart Charging technology that could assist customers in keeping efficient electric or hybrid electric vehicles charged without increasing peak system load may move electricity demand away from peak times, without creating inconvenience for customers.
31. The Small Customer Load Aggregation Pilot, as proposed, is duplicative of two other proposals in PG&E's 2009-2011 demand response application.
32. It is likely that information from this pilot will enable the utility to more effectively and efficiently provide customers with Programmable Communicating Thermostats and information needed to utilize that equipment more effectively.
33. The proposed Tier Alert Pilot is designed to achieve energy conservation, and is unlikely to result in any actual demand response.
34. SDG&E's proposed residential automated controls pilot is designed to answer specific questions related to the willingness of residential customers to install enabling technologies that facilitate load reduction, as well as curtailment devices that allow the utility to control certain appliances.
35. Changes in the energy market over the next two years may affect the desirability of entering into new contracts for 2012 and beyond.
36. A properly designed baseline calculation methodology is important for the success of any demand response program as it provides the benchmark by which performance is measured.
37. Existing studies suggest there are more accurate baselines than the current three-day unadjusted baseline for the large commercial and industrial customers. The studies also conclude that a day-of adjustment based on usage data from the morning before an event can significantly reduce the bias and improve the accuracy of this type of baseline.
38. Existing studies recommend a 10-day baseline with a day-of adjustment.
39. The settlement baseline for demand response activities should be consistent across utilities and programs.
40. As dynamic tariffs become more common and the utilities implement default Critical Peak Pricing, current rules against participation in more than one demand response program or tariff may limit the amount of peak load reduction that can be achieved through demand response.
41. It is consistent with the Commission's policy of encouraging cost effective demand response activities to allow customers to participate concurrently in two demand response activities and programs, as long as duplicative payments for a single instance of load drop can be avoided.
42. It is consistent with the Commission's policy of encouraging cost effective demand response activities to allow customers receiving partial standby service from PG&E to participate in certain demand response programs for the load they purchase from the utility.
43. Participation in more than one demand response program may provide flexibility to customers and expand their ability to respond to the varying conditions that trigger demand response.
44. It is logical to continue existing permanent load shifting activities for the terms of their existing contracts.
45. Circumstances relevant to the expansion of permanent load shifting are likely to change by 2011.
46. A standard offer would enable customers to choose from any vendor that offers thermal energy storage technologies.
47. EM&V activities, which include program evaluation, load impact evaluation, and demand response research projects, are essential to the development of effective, and cost effective, demand response programs in California.
48. PG&E's request for two-way balancing account treatment for the DREBA departs from the cost recovery rules in place for that utility in 2006-2008.
49. PG&E's current one-way balancing account treatment for certain demand response expenses in DREBA allows tracking of actual expenses and recovery of those expenses up to the authorized budget level.
50. Two-way balancing account treatment for program incentives allows recovery of additional incentive costs in the unlikely event that extreme conditions result in more than the forecasted number of events through 2009-2011, without requiring additional ratepayer funding unless extreme conditions cause the incentive budget to be exeeded.
1. It is reasonable to continue existing demand response programs that are estimated to be cost effective, or that serve the public interest in other ways.
2. It is reasonable to approve the discontinuation of a demand response activity if it does not provide actual demand response, or if the program's participants will be transitioned to an equally effective demand response program, while maintaining their load reduction efforts.
3. It is reasonable to cap emergency triggered programs at their current enrollment (in megawatts) and funding levels pending the resolution of R.07-01-041 Phase 3.
4. It is reasonable to provide a limited exemption from the general cap on emergency triggered demand response programs for the PG&E SmartAC program, and to cap that program at the expanded enrollment level of 305 megawatts authorized and funded in D.08-02-009.
5. It is reasonable to deny PG&E's request to transition the Base Interruptible Program customers to PeakChoice because PeakChoice is unproven.
6. For most demand response activities, administrative expenses should not be greater than customer incentives paid under the program.
7. It is reasonable to approve PG&E's request to modify event notification time from 12 noon to no later than 2:00 p.m. the day preceding an event to align with CAISO markets.
8. Consistent with current Commission policy, for programs that allow customer enrollment directly through the utility as well as through a demand response aggregator, it is reasonable for directly enrolled customers to receive 80% of earned incentives, and customers enrolled through an aggregator to receive 100% of the earned incentives.
9. It is reasonable to increase tracking requirements for certain demand response activities in order to monitor performance under these programs and develop better budget forecasts for future funding cycles.
10. It is reasonable for Technical Assistance and Technology Incentives and Automated Demand Response activities available through more than one utility to have similar requirements throughout the state, including the following:
a. The maximum rebate for non-Automated Demand Response services under the utilities' Technical Assistance and Technology Incentives programs should be $125 per kilowatt for all utilities.
b. The maximum rebate for automated demand response equipment installed through Technical Assistance and Technology Incentives or Automated Demand Response Programs should be $300 per kilowatt for all utilities.
c. Customers receiving an incentive of $100 or more per kilowatt under the Technical Assistance and Technology Incentives program should be required to make a minimum one year commitment to a demand response program or Critical Peak Pricing tariff.
d. SCE and SDG&E should develop proposals for integrating their Technical Incentives programs with other, similar demand side management inventive or rebate programs and should submit detailed proposals consistent with ongoing work through the Energy Efficiency Strategic Plan workgroups as part of their next demand response program applications.
11. It is reasonable to approve activities that may be affected by ongoing working groups on coordination and integration of demand side management activities for 2009-2011, subject to further review and potential modification in A.08-07-021 et al., where they can be reviewed in the context of those coordination efforts.
12. It is reasonable to use demand response funding to support activities that will leverage the utilities' AMI investments to increase demand response.
13. It is advisable to study technologies and strategies that may assist with integration of intermittent renewables into the power grid before the electricity provided by intermittent resources increases.
14. It is reasonable to explore ways to leverage the ratepayers' investment in infrastructure such as the Smart Meter program, in an attempt to provide additional benefits beyond those foreseen when the project was approved.
15. Because it is not necessary to determine at this time whether an RFP for additional demand response contracts will be appropriate in 2011, it is reasonable to await additional information before approving an RFP request.
16. In the long term, utilities should attempt to steer customers with highly variable loads away from demand response programs that require baselines, and towards programs that do not require baseline calculation such as Critical Peak Pricing.
17. It is reasonable to consider Critical Peak Pricing to be an energy payment program for the purposes of dual program participation.
18. It is reasonable and consistent with the Commission's policy of encouraging cost effective demand response activities to allow customers to participate concurrently in two demand response activities and programs, as long as duplicative payments for a single instance of load drop can be avoided.
19. It is reasonable to allow partial standby customers to participate in these demand response programs for the load they purchase from PG&E, and we approve this request.
20. It is reasonable to approve the settlement proposed on February 23, 2009, and adopt the contracts between SCE and AER, and SCE and EnerNOC as modified under that settlement.
21. The settlement agreement between PG&E and SF Power on the Small Commercial Aggregation Pilot is reasonable in light of the whole record, consistent with the law, and in the public interest.
22. It is reasonable to defer decisions on the best method for expanding the availability of permanent load shifting until more information is available.
23. It is reasonable to approve EM&V funding associated with approved demand response programs, pilots, and related activities.
24. Because it is intended for non-controversial updates or changes to existing programs, the advice letter process is not appropriate for the review of new programs or an increase in the total budget for a program area adopted in a decision.
25. It is reasonable to provide the utilities with some flexibility to shift funds among demand response programs, in order to provide the utilities with the ability to respond effectively to unforeseen developments that may occur and to respond to changing conditions.
26. It is reasonable to allow two-way balancing account treatment for demand response program incentives.
IT IS ORDERED that:
1. Southern California Edison Company shall continue the following existing demand response programs, as described in this decision: the Base Interruptible Program, the Optional Binding Mandatory Curtailment Program, the Scheduled Load Reduction Program, the Demand Bidding Program, the Capacity Bidding Program, Critical Peak Pricing, Real Time Pricing, Technical Assistance and Technology Incentives, Emerging Markets and Technology, Automated Demand Response, the Summer Discount Plan, Agricultural Pumping - Interruptible, Rotating Outage Program, and the Agricultural Pump Timer Program.
2. Southern California Edison Company's proposal to implement an Energy Options program is approved. Southern California Edison Company shall transition participants in its Demand Bidding Program and Capacity Bidding Program into this program, as proposed, and shall discontinue those programs when the transition is complete.
3. Pacific Gas and Electric Company shall continue the following existing demand response programs, as described in this decision: the Base Interruptible Program, the Optional Binding Mandatory Curtailment Program, the Scheduled Load Reduction Program, the Demand Bidding Program, the Capacity Bidding Program, Critical Peak Pricing, Real Time Pricing, Technical Assistance and Technology Incentives, Emerging Markets and Technology, Automated Demand Response, SmartAC, SmartRate, and PeakChoice.
4. San Diego Gas & Electric Company shall continue the following existing demand response programs, as described in this decision: the Base Interruptible Program, the Optional Binding Mandatory Curtailment Program, the Scheduled Load Reduction Program, the Demand Bidding Program, the Capacity Bidding Program, Critical Peak Pricing, Real Time Pricing, Technical Assistance and Technology Incentives, Emerging Markets and Technology, Automated Demand Response, Critical Peak Pricing - Emergency, and Summer Saver programs.
5. San Diego Gas & Electric Company shall transition its Demand Bidding Program participants onto its Critical Peak Pricing Tariff, as proposed, and shall discontinue the Demand Bidding Program when the transition is complete.
6. Pacific Gas and Electric Company shall discontinue the Base Interruptibles Program Option B within 30 days of the effective date of this decision.
7. Pacific Gas and Electric Company shall discontinue the Business Energy Coalition and the Automated Business Energy Coalition within 90 days of the effective date of this decision.
8. San Diego Gas & Electric Company shall discontinue its Peak Day Credit Program within 30 days of the effective date of this decision.
9. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall provide customers currently enrolled in discontinued programs with timely notice of the programs' cancellation, as well as information on other demand response program options for which the customer may be eligible.
10. The demand response budgets for Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company enumerated in Section 24 of this decision are adopted for 2009-2011.
11. All emergency-triggered demand response programs of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company are capped at their current level of enrolled megawatts, and shall not be expanded, pending a decision in Phase 3 of Rulemaking 07-01-041. PG&E's SmartAC program is exempted from this cap and shall continue to enroll customers consistent with the Commission's direction in D.08-02-009.
12. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall modify their Technical Assistance and Technology Incentives programs as follows. These rules shall apply to customers receiving services under these programs beginning January 1, 2010:
a. The maximum rebate or incentive for non-Automated Demand Response services under the utilities' Technical Assistance and Technology Incentives programs should be $125 per kilowatt for all utilities.
b. The maximum rebate or incentive for automated demand response equipment installed through Technical Assistance and Technology Incentives or Automated Demand Response Programs should be $300 per kilowatt for all utilities.
c. Customers receiving an incentive of $100 or more per kilowatt shall be required to make a minimum one year commitment to a demand response program or Critical Peak Pricing tariff.
13. Southern California Edison Company, San Diego Gas & Electric Company, and Pacific Gas and Electric Company shall develop proposals for integrating their Technical Incentives programs with other, similar demand side management incentive or rebate programs, consistent with the discussion in Section 12 of this decision. Each utility shall submit a report on how to integrate these activities, consistent with the results of the Energy Efficiency Strategic Plan workgroups, as part of their next demand response program applications.
14. Southern California Edison Company, San Diego Gas & Electric Company, and Pacific Gas and Electric Company shall each provide annual reports on their Emerging Markets and Technology projects, including estimates of the expected term of each project, to Energy Division as described in Section 12 of this decision. These utilities shall work with Energy Division staff to develop a reporting format, and shall provide reports on the previous year's Emerging Markets and Technology activities reports on the director of the Commission's Energy Division, and to provide copies to the most recent service list in this proceeding. In addition, the utilities shall post their monthly reports on a publicly available web site.
15. Utilities shall evaluate the results of their Automated Demand Response activities as described in Section 12. 3, above. The utilities shall report the results of these evaluations to the Energy Division Director by September 30, 2010, and provide copies to the most recent service list in this proceeding. In addition, the utilities shall post these reports on a publicly available web site. The utilities shall jointly hold two workshops on these results, one to present and discuss their findings and solicit feedback from the parties and a second public workshop to present proposals based on the results of the first workshop and solicit feedback and other proposals from the parties. The timing of these workshops shall be coordinated with other workshops planned by the DRMEC.
16. To continue beyond December 31, 2011, an Emerging Markets and Technology Project funded through the 2009-2011 budgets adopted in this decision, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each request permission either through a Tier 2 advice letter describing specific projects and the reason for the project to continue beyond the end of the funding period, or by including a request to continue these projects in their next demand response funding application.
17. The Flex Alert Campaign shall continue at the requested funding levels, as set forth in Section 13, above, pending final recommendations of the California Energy Efficiency Strategic Plan on coordination of statewide education efforts.
18. The utilities' proposed specialized marketing activities and budgets are approved for 2009-2011, subject to further review and potential modification in Application 08-07-021 et al., the ongoing energy efficiency applications proceeding.
19. Pacific Gas and Electric Company's requests to issue a Request for Proposal in 2011 to solicit more demand response contracts for the 2012-2014 period are denied.
20. The settlement on Southern California Edison Company's proposed aggregator contracts with Alternative Energy Resources, Inc. and EnerNOC Inc., contained in Attachment A of this decision, is approved.
21. The settlement between Pacific Gas and Electric Company and SF Power on the Small Commercial Aggregation Pilot, contained in Attachment B of this decision, is approved.
22. The following demand response pilots are approved to operate during 2010 and 2011, along with pilots already approved in D.08-12-038:
a. For Pacific Gas and Electric Company: the Commercial and Industrial Intermittent Resource Pilot and the Hybrid Electric Vehicle/Electric Vehicle Smart Charging Pilot.
b. For Southern California Edison Company: the Smart Thermostat Customer Experience Pilot and the Optional Programmable Communicating Thermostat Pilot.
c. For San Diego Gas & Electric Company: the Residential Automated Controls Pilot.
23. The Tier Alert Pilot proposed by Southern California Edison Company and the Small Customer Load Aggregation Pilot proposed by Pacific Gas and Electric Company are rejected.
24. The plans proposed by Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company to transition demand response activities to integrate into the new CAISO markets during 2009-2011 are approved with the following modifications. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each prepare two related reports over the next two years. Each company shall serve each report on the director of the Commission's Energy Division, and to provide copies to the most recent service list in this proceeding. In addition, the utilities shall post these reports on a publicly available web site by the date indicated. These required reports are:
a. An evaluation of the Participating Load pilots in 2009. This report shall assess what was learned through the pilots, areas that need further exploration (if any), and potential next steps for 2010 and beyond. Each of the utilities shall provide this report by December 31, 2009.
b. A report on the transition of demand response programs into Market Redesign and Technology Upgrade. This report shall include lessons learned from the utilities' 2009 pilots and their 2010 Proxy Demand Resource experience, including performance assessments as well as an evaluation of expected costs and benefits of integrating of all programs into Proxy Demand Resource (if such programs have not already been integrated) and Participating Load (for all programs). Each of the utilities shall provide this report by January 31, 2011.
25. Within 30 days of the filing of CAISO's Proxy Demand Resource tariff with the Federal Energy Regulatory Commission, the utilities shall propose modifications to one or more existing demand response programs that will make at least 10 percent of the megawatts enrolled in the demand response programs authorized in this decision comply with the requirements of CAISO's Proxy Demand Resource.
26. Within 30 days of the approval of CAISO's Proxy Demand Resource tariff by the Federal Energy Regulatory Commission, each utility shall file a proposal with the Commission to make at least one new or existing demand response program or option within a program comply with the 10-minute dispatch notification time requirements for participation in the CAISO's ancillary services market as either Proxy Demand Resource or Participating Load.
27. All demand response programs that have not been transitioned to Proxy Demand Resource or Participating Load shall be scheduled in the CAISO day-ahead market as Non-participating Load, complying with CAISO requirements for scheduling including the provision of a price curve.
28. All demand response programs of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company utilizing a baseline for settlement purposes shall use a 10-day individual customer baseline with a day-of adjustment, as described in Section 17 of this decision. The adjustment shall be symmetrical (upward or downward, as indicated by usage in the window time period), shall be capped at 20% of the calculated average usage, and shall be based on the first three of the four hours prior to the event. Each of these utilities shall offer customers the opportunity to opt into the adjustment.
29. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each work with parties to develop a definition of highly variable load customers, and to prepare a report containing that definition along with an estimate of the number of highly variable load customers currently in its baseline demand response programs, and the number of megawatts contributed to the programs by those customers. The report shall propose a plan for steering highly variable load customers towards demand response programs that do not require baseline calculations for settlement purposes. This report shall also include information on the proportion of customers choosing the morning-of adjustment option that reach or exceed the maximum adjustment of 20%, and how often that maximum adjustment is reached. Each of the utilities shall submit its report to the Director of the Energy Division no later than September 1, 2010 and provide copies to the most recent service in these proceedings.
30. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall each file Tier Two advice letters within 90 days of the effective date of this decision specifying dual program participation rules consistent with the discussion in Section 18 of this decision. These rules shall allow customers to participate concurrently in up to two demand response activities, if one provides energy payments and the other provides capacity payments. These rules shall prohibit concurrent participation in programs with the same trigger (day-ahead or day-of); however, a participant may participate in one day-ahead and one day-of program. In the case of simultaneous or overlapping events called in two programs, a single customer enrolled in those two programs shall receive payment only under the capacity program, not for the simultaneous event for the energy payment program. Critical Peak Pricing shall be considered to provide an energy payment for the purposes of these dual program participation rules. These rules shall also apply to customers enrolled in a utility-administered program and customers administered by a third-party aggregator.
31. Pacific Gas and Electric Company shall allow partial standby customers to participate in the following demand response programs for the load they purchase from the utility: the Demand Bidding Program, the Base Interruptible Program, the Aggregator Managed Portfolio, the Capacity Bidding Program, Critical Peak Pricing, and the PeakChoice Program.
32. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall work with parties to examine ways of expanding the availability of permanent load shifting. This study shall include discussion of a standard offer proposal that could apply generally to any permanent load shifting technologies including, but not limited to, thermal energy storage. This study should also consider other ways of encouraging permanent load shifting, including modifications to time of use rates or another RFP process. This report shall contain a summary of permanent load shifting standard offers available throughout the United States, as well as an evaluation of what incentive payment would be appropriate for a future standard offer. Each of the utilities shall provide its report to the Director of the Energy Division no later than December 1, 2010, and shall provide copies to the most recent service list in this proceeding. In addition, the utilities shall post these reports on a publicly available web site.
33. During the 2009-2011 period, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company may file a petition for modification of this decision to request to develop new demand response programs or program options, or to request additional funding beyond the total amount approved in this decision. During this period, these utilities may request new demand response programs only through a new application. During this period, these utilities may request changes to policies specifically adopted in this decision, such as the calculation of a settlement baseline for an existing program or rules for concurrent participation in multiple programs, and modifications to existing aggregator contracts through either an application or a petition for modification of this decision.
34. During the 2009-2011 period, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company may request to change program terms and conditions via a Tier 2 advice letter.
35. The following rules for fund shifting are adopted for the 2009-2011 demand response programs of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company:
a. The utilities may shift up to 50% of a program's funds to another program within the same budget category. The utilities shall document the amount of and reason for each shift in their monthly demand response reports.
b. The utilities may file a Tier 2 advice letter to request elimination of a program. No program may be eliminated through multiple fund shifting events or for any other reason without prior authorization from the Commission.
c. The utilities shall file a Type 2 advice letter to request authorization to shift more than 50% of a program's funds to a different program within the same budget category. If a shift of more then 50% of a program's funds is proposed as part of the implementation of a new program, the utility shall include the proposed fund shift in its application for approval for the new program, described in Ordering Paragraph 27.
d. The utilities shall not shift funds among the 10 categories defined in the table in Section 26 of this decision.
36. Consistent with the determinations made in this decision, the budgets specified in Section 24 of this decision are adopted for the demand response activities for 2009-2011 of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company. These budgets include the amounts adopted for bridge funding for 2009 in Decision 08-12-038.
37. PG&E shall revise its Demand Response Expense Balancing Account to allow two-way balancing account treatment for program incentives only. Administrative expenses for demand response programs will continue to be subject to one-way balancing account treatment, and are capped at 50% of the program costs for each approved program, as provided in this decision.
38. The Demand Response Measurement and Evaluation Committee shall continue its oversight of demand response evaluation, measurement and verifications activities. Beginning with the evaluation of 2009 demand response programs, the Demand Response Measurement and Evaluation Committee shall oversee not only the evaluation of statewide demand response activities, but also the evaluation of activities conducted by Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company. In addition, the Demand Response Measurement and Evaluation Committee shall conduct an annual public workshop presenting the results of demand response evaluations conducted under the Demand Response Measurement and Evaluation Committee's oversight. This annual workshop shall be noticed to the most recent service list of this proceeding.
39. Starting with a year-end report for 2009, and continuing through the end of the current budget period, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall prepare and provide monthly reports consistent with the discussion in Section 28 of this decision. The utilities shall use a consistent monthly report format approved by Energy Division staff, and shall provide these monthly reports to the Director of the Commission's Energy Division, with service on and the most recent service list in this proceeding. In addition, the utilities shall post their monthly reports on a publicly available web site. The year-end report for 2009 shall be provided no later than January 21, 2010, with subsequent reports provided monthly thereafter.
40. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company shall implement the modifications to policies and program rules affecting existing demand response programs adopted in this decision by January 1, 2010, or upon Energy Division approval of the advice letter implementing the change. The utilities shall implement the new programs and pilots authorized in Sections 10, 11, 12, and 14 of this decision in 2010, unless otherwise noted in this decision. Southern California Edison Company, San Diego Gas & Electric Company, and Pacific Gas and Electric Company shall each file one or more Tier 1 compliance advice letters within 90 days of the date of the effective date of this decision updating its tariffs to be consistent with the requirements of this decision and specifying the date on which those changes will take effect.
41. The utilities' applications for the 2012-2014 period shall be filed by January 30, 2011.
42. Application (A.) 08-06-001, A.08-06-002 and A.08-06-003 are closed.
This order is effective today.
Dated August 20, 2009, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
