10. Assignment of Proceeding

Michael R. Peevey is the Assigned Commissioner and Michelle Cooke is the assigned ALJ in this proceeding.

Findings of Fact

1. D.04-12-048 adopted 2005 price responsive goals of 450 MW for PG&E, 628 MW for SCE, and 125 MW for SDG&E.

2. Day-ahead notification programs are valuable for reducing predictable high peak loads.

3. Reliability-triggered programs, with shorter notification periods, serve as an important tool in mitigating unexpected shortages that could result in system failure.

4. Providing customers with an integrated presentation of their energy management options, addressing demand reduction strategies, energy efficiency, and other options will assist customers in making the best decisions about how to more effectively manage their energy requirements.

5. Recording capital and operating costs associated with meeting our goal of having interval meters in place for all customers with demand of 200 kW and greater in a memorandum account if these costs are not already authorized as part of the utility's authorized revenue requirement is reasonable.

6. Multi-year funding of demand response programs is desirable, but, given the lack of track record of demonstrated value to ratepayers, should not be authorized for the 2005 program year.

7. Approving an overall level of funding and allowing the utilities the flexibility to manage the allocation of the overall budget will prevent problems associated with over funding or under funding a particular program.

8. Adoption of a new default tariff will eliminate the need for continuation of a voluntary CPP rate.

9. No customers are currently enrolled in SDG&E's Hourly Pricing Option.

10. The minor modifications proposed to the Demand Bidding Program and expanded eligibility requirements improve consistency of this statewide program across service territories and expand the customers that can be recruited to participate.

11. Prices in the 2004 electricity market generally did not increase under high system load conditions because of the extent of forward contracting in the current market.

12. The market price threshold for triggering the Demand Bidding Program was never reached in 2004.

13. Paying a premium over the market price for voluntary load reduction from the Demand Bidding Program will make the program less cost effective, compared to purchasing from the market.

14. The Demand Reserves Partnership program is triggered by utilities for economic reasons or by DWR for reliability reasons.

15. The utilities helped fund the initial startup costs for the DRP programs, contributing approximately $2.7 million, with the expectation that by the end of 2004 the program would no longer need utility funding.

16. The CPA business plan for 2005 and 2006 anticipates generating more revenues than expenses for the DRP.

17. Adoption of a new default tariff will eliminate the need for PG&E's
E-SAVE, SDG&E's CPP-E, or a 20/20 program for customers with demand of 200 kW or greater or reopening SCE's I-6 or PG&E's non-firm rates.

18. There remains a need for a program to encourage customers under 200 kW in demand to reduce their on peak consumption.

19. SDG&E's approach to a 20/20 program for customers between 20 and 200 kW is most effective by targeting demand reduction during on-peak hours on specific days when temperature or system peak is forecasted to be relatively high but requires that a customer have an interval meter installed.

20. Development of cooperative relationships between customers and organizations with energy management skills should be promoted.

21. PG&E's proposal to offer a three-hour lead time option in its BIP expands the number of customers who might be willing to participate in the program.

22. There is a lack of demonstrated curtailment experience under the BIP program.

23. SCE's existing air conditioner cycling program results in reliable emergency load reduction, and can be targeted geographically at a fairly low marginal cost.

24. Installing additional air conditioner cycling controllers could result in some redundancy if the Commission directs the utilities to deploy an advanced metering infrastructure, but SCE's original ALC proposal would result in even more redundancy or replacement requirements.

25. SDG&E's Rolling Blackout Reduction Program and PG&E's Diesel Retrofit Generation Program reduce demand on the utility system by shifting load to onsite generation.

26. The Rolling Blackout Reduction Program is one of SDG&E's few existing reliability programs with subscribed capacity.

27. Focusing on providing customers with both technical assistance in evaluating their demand response capability and with lowering the cost of enabling technology will allow customers to more effectively reduce their load in response to critical peak price signals.

28. Although technical and technology assistance programs are unlikely to be cost-effective on a standalone basis, expanded programs of this nature are especially important in 2005 because of the anticipated conversion to new default rates that include a critical peak price.

29. Research pursued as part of the Emerging Markets Program will assist in developing new programs and demand response technology.

30. The improvements to the 20/20 residential program payment methodology address our concerns over free-ridership of the program.

31. Evaluation of reliability-triggered programs will allow us to more readily compare the costs and benefits between programs, but the evaluation of demand response programs will only be useful to the extent that the programs are triggered.

Conclusions of Law

1. Any demand response program that is designed to be triggered the day ahead, whether for price, temperature, or system demand conditions, should count towards meeting the utilities goals for price responsive demand.

2. The utilities should install interval meters for all customers with loads 200 kW and greater and place those customers on time differentiated rates.

3. Any utility whose current tariff language references installation of an AB1X 29 meter as a requirement for being placed on a TOU rate should modify that language to simply require installation of an interval meter.

4. We should approve spending flexibility, consistent with SDG&E's recommended fund shifting guidelines, within the following program categories: Day-Ahead Notification Programs, Reliability-Triggered Programs, and all other programs.

5. The current CPP rate should remain in place until a new default tariff is adopted or the CPP rate is otherwise modified in this or successor proceeding.

6. Allowing direct access customers and multiple meter customers to participate in the Demand Bidding Program facilitates additional customer enrollment in the program.

7. Allowing SDG&E customers with demand 20 kW or greater who have interval meters installed to participate in the Demand Bidding Program facilitates additional customer enrollment in the program.

8. The price trigger for the Demand Bidding Program should be replaced by a system conditions trigger.

9. Because current market prices do not reflect existing transmission system constraints, the utilities should pay day-ahead Demand Bidding Program customers the market price plus 10 cents for load reduction when system conditions result in an ISO Alert by 3:00 p.m. the day-ahead or when system load is forecast to be 43,000 MW or greater.

10. Because the Demand Bidding Program is voluntary, it does not result in reliable demand reduction for emergency purposes and therefore the day-of provisions of the program should be cancelled.

11. Based on the current reserve in the DRP program, the utilities should no longer be required to fund CPA operating costs for the DRP.

12. SDG&E's 20/20 program for customers between 20 and 200 kW ensures that only customers with the intention to participate and reduce load will receive the incentive payment.

13. In order to expand participation in the program, direct access customers should be able to participate in SDG&E's 20/20 program for customers between 20 and 200 kW, through receiving a credit on their distribution bill.

14. The existing Demand Bidding Program and DRP programs already offer opportunities to bid to provide load reduction or guarantee demand reduction capability, but a stand alone program like the Business Energy Partnership is needed.

15. The one year enrollment requirement for BIP programs should be waived for 2005.

16. All three utilities may offer a three-hour notification option for their BIP program.

17. Adopting PG&E's proposed change to the BIP non-performance penalty could undermine our ability to rely on load reduction from the program.

18. SCE's expanded air conditioner cycling program should be approved.

19. SCE has not yet provided any results or analysis of its 2004 Commercial and Industrial Smart Thermostat program to justify expansion, but the proposals to modify the incentive payment, reduce the deduction for overrides, allow two test events that do not count towards the incentive payment and expanded marketing of the internet programming feature should be approved.

20. SDG&E should modify the incentive payments and deduction for overrides, and reduce the number of times its residential Smart Thermostat program can be triggered.

21. Because of our concerns about Southern California supply-demand balance for 2005, SDG&E's Rolling Blackout Reduction Program modifications should be approved.

22. Although the Rolling Blackout Reduction Program may have some value, it is not a true demand reduction program and should not be funded through the demand response program budgets after 2005.

23. Because it promotes reliance on diesel generators as part of California's resource mix and Northern California does not face the same demand and supply imbalance problem in 2005 a Southern California, we should not approve PG&E's Diesel Retrofit Generation Program

24. Because of the additional need for technical and technology assistance due to new default rates and the elimination of the CPP or Demand Bidding Program enrollment requirement, program funding in scale with SDG&E's proposed program is appropriate.

25. The utility proposed budgets for Flex Your Power Now! should be approved and some portion of that funding should be directed toward messages about the importance of reducing load during critical peak days for Summer 2005.

26. Education programs targeting students should utilize a shared budget and information approach consistent with the utilities' IDSM efforts.

27. SDG&E's Community Partnership Program should be approved, and SCE and PG&E should implement a similar type of integrated energy usage education program targeted at small and medium business customers.

28. SDG&E's Circuit Saver Program should be approved to assist in meeting peak demand concerns for Summer 2005.

29. The utilities should dedicate some portion of their budgets to research.

30. A 20/20 program structured like PG&E proposes for load under 200 kW is preferred to the SDG&E Power Pledge approach.

31. PG&E's cost recovery proposal is reasonable with the clarification that our limitation on review of the amounts recorded in UGBA is specific to PG&E's residential 20/20 program costs.

32. After review of recorded amounts, PG&E should annually transfer the approved recorded amounts to its DRAM for rate recovery.

33. SCE should record its demand response program costs in its AMDRA, with the exception of 20/20 programs costs, which should be recorded in its ERRA.

34. In SCE's annual ERRA proceeding, its AMDRMA should be audited and approved amounts should be consolidated with other approved revenue requirement changes for reflection in distribution rates.

35. SDG&E's cost recovery proposal is generally reasonable, but it should record costs associated with reliability-triggered programs in its pre-existing AMDRMA.

36. After review of recorded amounts, SDG&E should annually transfer the approved recorded amounts to its Rewards and Penalties Balancing Account for amortization into distribution rates.

37. We should authorize funding for process and impact evaluation of both reliability and day-ahead triggered programs but direct the utilities to work with Energy Division and CEC staff to identify which programs will provide the most useful analytical information based on how frequently the programs are triggered.

ORDER

IT IS ORDERED that:

1. The following programs are approved for implementation by Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE) in 2005, as described herein:

2. SDG&E's Hourly Pricing Option rate is terminated.

3. SCE, SDG&E, and PG&E shall file 2006-2008 demand response program applications on June 1, 2005, concurrent with their 2006-2008 energy efficiency applications.

4. The utilities may shift funds within the following program categories-- Day-Ahead Notification Programs, Reliability-Triggered Programs, and all other programs-without additional authorizations provided that the shift does not exceed 25% of one program's funds and/or change the aggregated load reduction goal.

5. SCE and PG&E shall explore whether SDG&E's Circuit Saver Program could be applied to their service territories and include such a program, if appropriate, in their 2006-2008 program plans.

6. The utilities shall meet with staff from the California Energy Commission and Energy Division to identify alternative ways of reporting load reduction capability of demand response programs.

7. SCE shall prepare one combined report on demand response and reliability-triggered programs, consistent with the approach taken by PG&E and SDG&E.

8. When reporting on demand response programs, the utilities shall report both demand response potential and expected/actual demand reduction when the program is called.

9. The utilities shall work with Energy Division and California Energy Commission staff to identify specific measurement and evaluation activities within the general scope proposed.

10. The utilities shall file Advice Letters to implement the modifications to existing programs, new programs, and cost recovery provisions of this decision, as necessary, within 10 days of the effective date of this decision.

This order is effective today.

Dated January 27, 2005, at San Francisco, California.

Comr. Grueneich recused herself

from this agenda item and was not

part of the quorum in its consideration.

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