VII. Assignment of Proceeding

Michael Peevey is the Assigned Commissioner and Lynn Carew is the assigned ALJ in this proceeding.

Findings of Fact

1. The Commission instituted R.02-06-001 to formulate comprehensive policies that will develop demand flexibility as a resource to enhance electric system reliability, reduce power purchase and individual consumer costs, and protect the environment; through this collaborative interagency effort with theCalifornia Energy Commission (CEC) and the California Consumer Power and Conservation Financing Authority (CPA), the Commission is engaged in policymaking designed to make a broad spectrum of options available to customers who make their demand-responsive resources available to the electric system.

2. Demand response is the ability of an individual electric customer to reduce or shift usage or demand in response to a financial incentive; in this rulemaking we seek to determine whether customers will alter their usage patterns in response to a financial signal that is keyed to system conditions.

3. Working under the direction of interagency decision makers, and with the assistance of a staff facilitator, Working Group 3, a group comprised of respondents and interested parties who examined residential and small commercial (<200 kW) demand response issues, developed a near-consensus dynamic pricing pilot proposal known as the Statewide Pricing Proposal (SPP).

4. The SPP tests dynamic tariffs for a representative sample of residential and small commercial customers in order to learn more about demand elasticities and customer preferences.

5. The SPP, which will run through the end of 2004, measures the impact of three specific time-varying rates on customer electric consumption and coincident peak demand. The SPP's primary target is residential customers, since earlier experiments show that they demonstrate greater responsiveness to time-varying rates than do commercial customers; however, the SPP breaks new ground by including small commercial customers.

6. In the interests of achieving a statistically representative sample of customers, pilot participants will be drawn from four climate zones statewide, and will include customers of all three respondent investor-owned utilities (IOUs).

7. The 2,575 customers participating in the SPP are assigned to three "tracks" (A, B, and C) that simulate the effects of a large-scale rollout of time-varying rates.

8. In order to provide optimal information, the pilot must test different dynamic rate structures, information treatments, and technology options.

9. The SPP tests three different rate structures: a static time-of-use (TOU) rate, and two types of critical peak pricing (CPP) tariffs, fixed (CPP-F) and variable (CPP-V).

10. The SPP tests the impact of various information presented to participating customers, including the Track B pilot, whose participants will be given information about the economic and environmental consequences associated with peak power use, and informed of the potential to reduce reliance on a locally-polluting power plant through adoption of a CPP-F tariff.

11. The SPP examines customers' relative responsiveness to dynamic rates with and without various technologies which enable the customer to respond automatically to signals through pre-programming devices.

12. Market research is a necessary part of any pilot design, because it ensures that customers understand the pilot and it also provides insights into their needs and preferences in the interests of fine-tuning the rate, information, or technology aspects of the pilot design.

13. A limited amount of market research is reasonable prior to deployment of the SPP in order to determine how the concept of time-varying pricing can best be explained to customers, to learn what features appeal to them, how to maximize customer acceptance, and what sorts of peak periods and pricing combinations customers will accept.

14. It is also reasonable to conduct concurrent market research to determine whether rate, information, and technology treatments are working optimally during the pilot.

15. Market research conducted at the conclusion of the pilot is valuable in order to obtain the views of customers about their specific experience with the rate, information, and technology treatments.

16. The SPP's market research elements, which include research before, during, and after completion of the program, are reasonable.

17. One of the assumptions that the CPP is designed to test is whether certain low-usage customers have the ability to shift enough load to make program participation cost-effective.

18. Track A of the SPP, as proposed, lacks a robust set of enabling technologies to enhance customer response to a CPP-V rate, and the pilot would be improved by offering Track A customers a choice of additional control devices based on their appliance ownership, as discussed in this decision.

19. SF Co-op will play a crucial role in the implementation of the Track B pilot and the interface with San Francisco customers in collaboration with the PG&E project management as discussed previously. PG&E is responsible for overall project management of the Track B pilot. PG&E will budget and allocate sufficient funds in support of SF Co-op's participation in the Track B pilot.

20. The Track B Pilot needs a viable control group, derived from another similarly situated Bay Area community and representative of the Track B participants in that it includes similar households (including a sufficient number of low-income participants) who face the same environmental conditions and/or reside in transmission constrained areas.

21. As proposed, the Track C pilot, which consists of 488 customers currently participating in the pre-existing smart thermostat programs of Edison and SDG&E, tests demand response from customers who voluntarily chose to be in a demand response program. The pilot would be significantly improved by testing alternative recruitment techniques and by ensuring that there is an adequate control group for comparison purposes.

22. An appreciation bonus or inducement enhances the voluntary aspects of the SPP's enrollment process at a minimal cost well within the budget cap for the SPP.

23. The ideal way to achieve the Commission's SPP enrollment goals is to select a statistically random sample and persuade those selected to participate in the SPP voluntarily.

24. Providing additional feedback to customers regarding the kW or dollar impact of their curtailment actions on either a daily or monthly basis, enhances customer satisfaction with the program.

25. In addition to the SPP, two alternative pilot programs were presented by Invensys and IM Serv.

26. The Invensys pilot, designed to test the effectiveness of an advanced, interactive technology, and dispatchable demand response offering, has merit because it advances the range of technologies available to customers to enable demand response; it is desirable to test these enhanced capabilities in a full-scale system as part of a subsequent stage of the SPP.

27. The IM Serv pilot, which offers customers transmission and distribution (T&D) credits, for reducing T&D costs through demand response, requires more detailed development prior to any Commission approval for residential and small commercial customers.

28. With the modifications to the SPP included in this decision (specifically 1) the additional technology treatments added to Track A; 2) the full-scale system technology testing to be integrated into the SPP; and 3) the customer appreciation bonus or inducement), the projected cost of the pilot increases from $9.6 million to approximately $12 million for calendar year 2003.

29. With the modifications ordered in this decision, the SPP is reasonable.

Conclusions of Law

1. Phase 1 of this proceeding has proceeded as a notice-and-comment rulemaking, and no evidentiary hearings have been held.

2. Track A of the SPP should be modified to include additional control technologies, consistent with the preceding discussion.

3. SF Co-op's request for $142,000 for its role in pilot development, implementation, and analysis, related to the Track B pilot should be denied, since PG&E, as project manager of the Track B pilot, will compensate SF Co-op for its involvement in these efforts under the SPP's proposed budget. PG&E should budget and allocate sufficient funds in support of SF Co-op's participation in the Track B pilot.

4. The Track B pilot should be modified to include a viable control group including similar households facing the same environmental and/or transmission-constrained conditions.

5. The Track C pilot should be modified to include additional customers through alternative recruitment techniques to ensure representative comparisons, as well as ensure an adequate control group.

6. The SPP's enrollment process should meet the following goals: 1) enroll a representative sample of customers to maintain the integrity of the experimental design and ensure the validity of the results; 2) maintain a high level of customer satisfaction; 3) promote retention of the participants for at least one summer; and 4) minimize costs.

7. The SPP should provide an "appreciation bonus" or inducementto SPP participants, based on customer focus group results, and consistent with the enrollment goals detailed in the decision.

8. The Respondent IOUs should file an evaluation plan detailing how they plan to analyze the demand response and/or price elasticity impacts of the various technology treatments and information treatments they will provide in the SPP.

9. All Tracks of the SPP should include adequate control groups to ensure the statistical validity of the pilot results.

10. Respondent IOUs should develop a plan to evaluate the impacts of a full-scale system comparable to the alternative proposed by Invensys, and shall propose a method of integrating the installation of such devices at a representative sample of homes during the later stages of this pilot, consistent with the discussion in this decision.

11. The IMServ T&D incentive-based pilot programs should not be approved at this time.

12. The SPP will meet most of the conditions outlined in Pub. Util. Code §393 (c), which requires the Commission to conduct a pilot study of the residential and small commercial customers of each electrical corporation; where it does not precisely conform to the statute, such variations are in the public interest.

13. No randomly-selected customer who agrees to participate in the SPP (and who will receive an appreciation bonus) will be required to participate in the pilot study beyond the Summer of 2003, due to the nature of the recruitment and opt-out features adopted in this decision, thus enhancing the voluntary aspects of pilot participation, consistent with Pub. Util. Code § 393(c )(3). In general, the opt-out nature of the enrollment process ensures that customer participation is voluntary.

14. The record developed and the programs approved provide much of the data necessary to make the report required by Senate Bill (SB) 1976, which requires the CEC, in consultation with this Commission, to report to the Legislature regarding the feasibility of implementing real-time, critical peak, and other dynamic pricing tariffs for electricity in California.

15. The efforts planned in Phase 2 of this proceeding to review the contribution that cost-effective A/C cycling programs can make in meeting peak load reduction targets are part of this agency's compliance with SB 1790, which added §2774.6 to the Public Utilities Code, requiring the Commission, in consultation with the CEC, to develop a program for residential and commercial customer A/C load control.

16. The SPP cost recovery mechanisms proposed for Phase 1 relative to administrative and general (A&G) and operating and maintenance (O&M) costs, capital additions, incentive payments and revenue shortfalls, are reasonable and should be adopted.

17. Since we require SPP to continue through calendar year 2004, rather than 2003 as originally proposed, it is appropriate to cap the total SPP expenditures at $12 million, but to provide a mechanism for considering and approving additional program costs that may be incurred in calendar year 2004.

18. Respondent IOUs should develop tariffs for all SPP participants, both residential and small commercial, which are designed to meet the principles previously outlined in this decision. Sample TOU, CPP-F and CPP-V tariffs should be designed using the clean sheet approach, consistent with customer usage patterns and existing rates representative of proposed treatment cells for each of the utilities in the SPP. Consequently, TOU and CPP rates should be designed and evaluated consistent with SDG&E or SCE rate determinants, not just PG&E parameters. Rate forms, illustrative bill impacts, tier structures, load profiles, all other analytical assumptions, and computational methods should be documented and made available to all parties.

19. The SPP, as modified in this decision, should be approved.

20. The Respondent IOUs should make every effort to develop and implement the SPP no later than July 1, 2003.

ORDER

IT IS ORDERED that:

1. Within 30 days of the date of issuance of this decision, respondent IOUs shall file and serve a compliance filing containing all of the following modifications along with a revised pilot schedule, as discussed in this decision:

a. Their plan for offering additional control technologies to Track A, CPP-V, customers within the existing treatment cells;

b. A summary of their plan to include a representative control group in the Track B pilot;

c. A summary of their proposal to include alternative recruitment techniques to ensure the statistical validity of the results from Track C participation;

d. A summary of the feedback options to be provided to participating customers and how they will evaluate the impact of this feedback on kW reductions;

e. Their plan for additional control groups in all SPP tracks.

2. By August 1, 2003, respondent IOUs shall file and serve an evaluation plan detailing how they plan to analyze the demand response and/or price elasticity impacts of participating customers' enabling technology choices, and their use of different information assistance or direct billing impact information. The WG3 moderator shall schedule a public meeting to gather comments in the plan, coordinating with the assigned ALJ on whether additional Commission action is required.

3. By July 1, 2003, respondent IOUs shall file and serve a final plan for evaluating the demand response capabilities of a full scale system, comparable to that proposed by Invensys, with the specific capabilities outlined in the preceding discussion, as well as a proposed method to integrate the installation of these devices at a representative sample of homes during the later stages of this pilot. The respondents shall follow the schedule outlined in the decision for all steps prepatory to making the July 1, 2003 filing. The incremental cost of this plan shall not exceed $1 million.

4. The incremental cost of the additional required control technology offerings in Track A of the SPP shall not exceed $1 million.

5. The data resulting from the SPP shall be available to the public and shall be provided in a way that does not reveal customer-specific information. Such information shall not be used for any commercial purpose without the express authorization of the customer.

6. Any meter installation done as part of the SPP shall not compromise customer or worker safety, or the integrity or accuracy of the meter.

7. With the closure of R.00-10-002, the Commission's interruptible rulemaking, the Commission will review, in Phase 2 of this proceeding, the contribution that cost-effective A/C cycling program, as peak load reduction programs undertaken by respondent IOUs, can make in meeting the interagency demand response goals we have articulated in this proceeding.

8. Within 5 business days after the date of issuance of this decision, the respondent IOUs shall each file and serve on all parties of record, advice letters establishing Advanced Metering and Demand Response Accounts (AMDRAs) for the purpose of recording and recovering the incremental, one-time set up and on-going Operating and Maintenance (O&M) and Administrative and General (A&G) expenses incurred to develop and implement, or in reasonable anticipation of implementing, the demand response programs adopted in Phase 1 of this proceeding. The AMDRAs will apply to all customer classes, unless a class is explicitly excluded by the Commission. The revision dates applicable to the AMDRAs shall be as determined in each IOU's annual advice letter filing or as otherwise ordered by the Commission. The AMDRAs will not have a rate component. The IOUs shall maintain their respective AMDRAs by making entries at the end of each month as follows:

f. A debit entry equal to the UDC's incremental one-time "set up" and on-going O&M and A&G expenses incurred to develop and implement, or incurred in reasonable anticipation of implementing, the following programs being developed in R. 02-06-001: (1) the statewide pricing pilot (SPP) for small customers (under 200 kW), and (2) demand response tariffs and programs for large customers (greater than 200 kW), including:

    1. Market research prerequisite to SPP implementation;

    2. Development of rate, information, and technology treatments for various SPP cells;

    3. Sample design for various SPP cells

    4. Miscellaneous pilot design refinement and implementation activities;

    5. Development of systems for billing and implementing tariffs and programs for large customers; and

    6. Miscellaneous large customer tariff refinement and implementation activities reasonably necessary to ensure timely implementation of large customer tariffs and programs approved in the Phase 1 decision.

g. A debit entry equal to the interest on the average of the balance at the beginning of the month and the balance after the above entry at a rate equal to one-twelfth the interest rate on three-month Commercial Paper for the previous month, as reported in the Federal Reserve Statistical Release, H.15 or its successor.

Parties have 10 days to comment on the advice letters, which shall become effective retroactive to the date of filing upon written approval of the Energy Division.

9. Capital additions incurred for Phase 1 programs shall be treated as authorized additions to the respective respondent IOUs' plant, and all capital-related costs as authorized additions to each respective respondent's revenue requirement, and therefore recovered in rates, consistent with the preceding discussion.

10. Incentive payments associated with Phase 1 demand response programs shall be recorded in the appropriate procurement-related cost account established by the Commission for each respondent IOU, and identified in the advice letters that will implement SPP cost recovery and tariffs.

11. Revenue shortfalls associated with Phase 1 demand response programs offered to bundled service customers shall be recovered from all bundled service customers through each respondent IOU's procurement-related cost account, as identified in the advice letters that will implement SPP cost recovery and tariffs.

12. The total collective amount recorded in the procurement-related cost accounts in connection with the programs authorized in this decision shall not exceed $12 million exclusive of revenue shortfalls.

13. As part of their bi-monthly reporting requirement, respondent IOUs shall provide specific information detailing the actual monthly cost of maintaining and operating the SPP between May 1 and September 30, 2003. Using this operating cost information as its basis, on October 15, 2003, respondent IOUs shall file and serve a compliance filing, seeking Commission approval of the 2004 calendar year SPP budget, and any adjustment of the $12 million cost cap, as necessary to cover 2004 costs. Such filing shall include the 2004 calendar year costs of evaluating the SPP results. Other parties may respond to this compliance filing within 20 calendar days of service, and the Commission will address the matter thereafter.

14. For the duration of the SPP, the respondent IOUs shall file bimonthly reports to summarize program progress, as detailed in Attachments C and D.

15. Any necessary modifications or refinements to the pilot design, beyond those authorized in this decision, shall be requested by formal motion, filed and served on all parties of record, consistent with the discussion in this decision. The assigned ALJ, in consultation with the WG3 facilitator, is authorized to make any necessary modifications by ruling.

16. Within 7 working days after the date of issuance of this decision, the respondent IOUs shall each file and serve on all parties of record, advice letters containing all tariffs required to implement the adopted statewide pricing pilot for all participants, both residential and small commercial. These tariffs shall conform to the technical requirements contained in Attachments C and D of this decision, and shall be designed to meet the following principles:

h. Tariffs shall be designed to be revenue neutral for the average residential and commercial customer;

i. Tariffs shall be designed to minimize the bill impacts due to a rate change from the existing rates to pilot rates, assuming no consumption change. The average electricity bill within low, typical, and high customer usage levels (residential) or class (small commercial) to participating customers in any given month shall not exceed ± 5 % compared to current rates, assuming no change in consumption.

j. The tariff shall provide the customer a meaningful incentive for shifting load, or at least a 10 percent bill reduction assuming a 30 percent shift or reduction in consumption from some combination of either the critical-peak and/or on-peak periods.

17. The Statewide Pricing Pilot, as modified in this decision, is hereby approved, with a targeted start date of July 1, 2003.

This order is effective today.

Dated March 13, 2003, at San Francisco, California.

I will file a concurrence.

/s/ LORETTA M. LYNCH

This glossary is intended to describe terms used in this report only. It is not intended to take the place of existing rate glossaries, such as those put out by the CPUC, the Rate Design Study, EEI, NARUC, or NRRI.

Automatic control technology Any technology that allows the customer or electric service provider to pre-program a control strategy - for an individual electric load, group of electric loads, or an entire facility - to be automatically activated in response to a dispatch.

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

Demand rate A per-kW rate, typically applied to the peak demand during each month.

Demand response (DR) The ability of an individual electric customer to reduce or shift usage or demand in response to a financial incentive.

Dispatch A broadcast signaling the initiation of a control strategy or price adjustment.

Dynamic rate A rate in which prices can be adjusted on short notice (typically an hour or day ahead) as a function of system conditions. A dynamic rate cannot be fully predetermined at the time the tariff goes into effect; either the price or the timing is unknown until real-time system conditions warrant a price adjustment. Examples: real-time pricing (RTP), critical peak pricing (CPP)

Flat rate A per-kWh rate in which the same price is charged for all hours during a predetermined time period, usually a season or year.

Information Facts and data that facilitate consumer response to energy prices. 'Basic information' describes a tariff and its potential impact on expected monthly energy costs. 'Technical information' describes technologies that can be used to respond to the tariff. 'Energy information' describes the consumer's energy consumption patterns on an ongoing basis, to help the consumer adjust behavior and infrastructure to reduce monthly energy costs.

Interval meter An electricity meter or metering system that records a consumer's load profile by storing in memory each consecutive demand interval, which typically consists of a period ranging from 5 minutes to an hour, synchronized to the hour. The meter can be read through a hand-held device (typically monthly) or through a data link to a central metering master station (typically daily).

Notification Information provided to customers regarding price adjustments or system conditions. 'Day-ahead' notification provides at least 24 hours advance notice. 'Hour-ahead' notification provides at least one hour advance notice.

Price elasticity A measure of the sensitivity of customer demand to price. Price elasticity is expressed as the ratio of the percent change in demand to the percent change in price; e.g. a 10% load drop in response to a 100% price increase yields a price elasticity of -0.10. 'Own-price' elasticity relates changes in peak period demand to changes in peak period price. 'Cross-price' elasticity relates changes in usage in one period to changes in price in another period.

Rate The retail price of electricity per-kW demand or per-kWh usage. A rate may vary as a function of usage (tiered rate), demand (demand rate), period of use (time-of-use rate), or as a function of system conditions (dynamic rate).

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

Revenue neutrality A regulatory requirement that any alternative rate design must recover the same total revenue requirement as the default rate design, assuming that customers make no change in their usage patterns.

Seasonal rate A rate in which the price of electricity changes by season.

Smart thermostats A heating, ventilation and air-conditioning (HVAC) thermostat that: (1) automatically responds to different electricity prices by adjusting the temperature set point or the operation of the HVAC equipment using pre-programmed thresholds that have been specified by the customer; (2) displays energy information and rates, and notifies the customer of rate changes; and/or (3) can be programmed to control devices other than the HVAC system.

System conditions Any or all of the following: wholesale electricity costs, reliability conditions, environmental impacts, and/or the relationship between supply and demand.

Tariff A public document setting forth the services offered by an electric utility, rates and charges with respect to the services, and governing rules, regulations and practices relating to those services.

Tiered rate A rate in which predetermined prices change as a function of cumulative customer electricity usage within a predetermined time frame (usually monthly). Prices in an 'inverted tier' rate increase as cumulative electricity usage increases. Prices in a 'declining tier' or 'declining block' rate decrease as cumulative electricity usage increases.

Time-of-day (TOD) rate A rate in which predetermined electricity prices vary across two or more preset time periods within a day.

Time-of-use (TOU) rate A rate in which the price of electricity varies as a function of usage period, typically by time of day, by day of week, and/or by season. Examples: TOD rate, seasonal rate.

Time-varying rate A rate in which prices change or can be changed within a 24-hour period. Examples: TOD rate, dynamic rate.

(END OF ATTACHMENT A)

Attachment B

Table 3-2. Sample Design of the Statewide Pricing Pilot

(END OF ATTACMENT B)

(END OF ATTACHMENT C)

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