4. Process for Addressing Remaining and New Issues
4.1 Continuation of 2005 Programs Pending Decision on 2006-2008 Programs
D.05-01-056 adopted budgets and funding for 2005 demand response programs. That decision also required the utilities to file applications for adoption of 2006-2008 program plans. The current schedule for handling those applications in A.05-06-006 et al anticipates a Commission decision on the applications in March 2006, which could leave a funding gap for the first few months of 2006. On October 6, 2005, SCE filed a motion for authorization to continue to implement 2005 demand response programs in first quarter of 2006. PG&E filed a similar motion on October 27, 2005. The assigned ALJ and Commissioner, under authority delegated in D.03-06-032, have consistently carried over demand response program funding from one year into the next funding year to ensure fuller utilization of authorized funding before approving new funds. In the event that no Commission decision has been adopted in A.05-06-006 et al. by January 1, 2006, the utilities may carry over any 2005 authorized funding to continue to offer 2005 programs until such time as a decision is adopted for 2006 programs. This temporary bridge is a logical and simple means to ensure program continuity. SCE and PG&E's motions should be granted and extended to SDG&E.3
4.2 Tariff and Bill Issues
As stated above, although establishing an RTP tariff was identified as a topic for Phase 2 of the rulemaking, the Commission did not make further progress on developing two-part RTP tariffs for the largest utility customers. This lack of progress was driven by the lack of a meaningful price signal in the California Independent System Operator (CAISO) market upon which a real time price could be established as well as the parties' fundamental disagreement about how to design key components of a two-part RTP tariff, and the difficulty in doing so given the non-bypassable DWR charges on customer bills.
As the CAISO moves to implement its market redesign, we anticipate that transparent pricing information will become available that will facilitate development and adoption of a true RTP tariff. However, design of such a tariff cannot be performed in isolation from comprehensive rate design examination. Therefore, we direct each utility, as part of its next comprehensive rate design proceeding application following development and final implementation of an hourly day-ahead market price by the CAISO, to submit a real time pricing tariff for consideration as part of its tariff offerings. By that time, the CAISO will have implemented its market redesign, costs associated with recovery of the DWR revenue requirement will be declining, and we will have a clearer picture of whether and how utilities have deployed an advanced metering infrastructure and the basis on which to develop and adopt an RTP tariff will be much clearer.
In addition, we would like to see the utilities propose additional price responsive tariff options for their customers to consider. These were first articulated in the vision statement for demand response, entitled "California Demand Response: A vision for the Future (2002-2007), which was
Attachment A to D.03-06-032. In that statement, we articulated the following set of options that different types of customers should ideally have access to:
"Very large customers (over 1 MW): Hourly real-time pricing (RTP), critical peak pricing (CPP), or Time of Use (TOU) Pricing.
Large customers (200 kW to 1 MW): CPP, TOU, or RTP
Residential and small commercial customers (under 200 kW): CPP, TOU, or flat rate (the latter with an appropriate hedge for risk protection)"
Thus, we also require the utilities to make proposals for consideration for all of the above price-responsive tariff options for their customers in the next comprehensive rate design application.
In the short term, we will focus our efforts with respect to tariff offerings on reviewing the applications of each utility to implement a critical peak pricing (CPP) tariff for customers with load of over 200 kW (A.05-01-016 et al.), and PG&E's proposed tariffs to promote demand response as part of its AMI Project (A.05-06-028). Residential and small commercial customers are not currently able to sign up for CPP rates, with the exception of customers already enrolled on the experimental CPP rates that were developed as part of the SPP. Development of non-experimental time differentiated tariff options for these customer classes will need to occur fairly soon, and we direct each utility to include such tariffs in their next rate design application. Since effective implementation of more time-differentiated tariffs for smaller customer classes requires the installation of metering and communications technology more sophisticated than most currently have, requiring the utilities to file proposed time-differentiated tariffs in their next rate design applications will allow us to have more information about whether and when each utility might be deploying advanced metering infrastructure throughout its service territory, and therefore, whether designing a CPP tariff for smaller customers is an appropriate use of the resources of all parties.
Finally, we note that over the course of this proceeding there has been discussion about the importance of how information is communicated to customers on their bill, and that current bill formats may not be the most effective way to convey energy usage information to promote demand response. This is an issue that transcends just demand response; it affects energy customers generally. Having more customer friendly billing formats could assist in meeting demand response, energy efficiency, and other policy goals. Therefore, we direct the Commission's Executive Director to explore opening a new rulemaking to develop more customer friendly billing formats for energy bills and to report back to the Commission at the second Commission meeting in January 2006 on whether the Commission should open such a rulemaking, and if so, the schedule for presenting the rulemaking to the Commission. Several parties recommend a workshop prior to any recommendation to implement a bill format rulemaking. While this recommendation has merit, we will not mandate the process employed by the Executive Director to prepare his recommendation.
4.3 Demand Reserves Partnership
In D.04-11-034, the Commission directed PG&E to negotiate an agreement with the CPA for the future operation and management of the DRP program. The Commission believed that an alternative manager of the DRP program was necessitated because it appeared that the CPA's operating funding for the program would be depleted by the end of November 2004. Since the time that D.04-11-034 was issued, the CPA was able to engage a Fiscal Agent to operate and manage the DRP program. The program has been operating under this approach, without any apparent issues, since that time. Although CPA and PG&E worked to negotiate an agreement to allow PG&E to take over management of the program, sticking points remained. In addition, the Commission itself, along with DWR, identified potential conflict of roles concerns with PG&E assuming the CPA role and also scheduling and dispatching the program under an agency agreement with DWR. Because these issues have not been resolved, the Demand Reserves Purchase Agreement will expire May 2007; however, the CPA Fiscal Agent has been ably managing the DRP program. We see no need to disturb the status quo, and decline to approve the Proposed Management Services Agreement filed on February 4, 2005.
In response to the draft decision, DWR recommends that we consider transferring the DRP program to the utilities immediately. SCE and PG&E oppose this suggestion, stating that they are developing plans to offer a similar program in 2007 when the current program expires, but are not prepared to take over administration now. We are not convinced to modify the decision to require early assumption of the DRP programs. However, we encourage the utilities to incorporate the DRP resources into their respective portfolios so that they are transitioned immediately upon conclusion of the DRP.
In D.05-01-056, the Commission approved an additional $575,000 in funding to cover PG&E's incremental costs of implementing the management services agreement. Since PG&E has not been functioning in this capacity, this funding is unneeded. PG&E may shift those funds into other programs, consistent with the fund shifting guidelines adopted in Ordering Paragraph 4 of D.05-01-056. TURN opposes providing fund shifting flexibility to PG&E for these funds, arguing they should be returned to ratepayers. However, the $575,000 budget was authorized to be collected by PG&E as part of its various memorandum accounts but was not an adopted revenue requirement so there is nothing to return to ratepayers. If PG&E chooses not to shift the $575,000 to another program, nothing will be booked to the memorandum account or collected from ratepayers. We do not disturb the fund shifting flexibility set forth in the draft decision.
4.4 Measurement and Evaluation
One of the struggles that has become clear over the course of this proceeding is between our desire to promote price-responsive demand and how the utilities and the CAISO treat demand response resources for purposes of resource planning and meeting resource adequacy standards. Unlike energy efficiency, which has a long history of success, adopted measurement protocols, and is well integrated into the resource planning process, demand response programs have a shorter history, are not well integrated into the planning process, and do not have adopted measurement and evaluation protocols. At this time, it appears that the CAISO continues to purchase energy in the market in order to ensure sufficient energy in the event that all demand response resources do not deliver. It is our belief that until the industry develops further trust that demand response will deliver demand reductions when needed, demand response will continue to be dismissed in the resource planning and acquisition process. In order to build that trust, we need to develop industry protocols for measuring load response capability and results so that the ratepayers are not paying twice for the same capacity, once for demand response programs, and then again for short-term resource acquisition by the CAISO.4 In addition, more precise demand reduction estimates derived from an accepted measurement methodology are a necessary prelude to performing accurate cost-effectiveness analysis.
By April 3, 2006, agency staff shall prepare a set of draft protocols for estimating load impacts for both price responsive and reliability demand response programs. This effort should be coordinated with efforts underway in the energy efficiency rulemaking, R.01-08-028, or its successor, and the resource adequacy rulemaking, R.04-04-003, or its successor. The draft should address whether the load impacts of all types of demand response programs (e.g., bidding programs, time-differentiated tariffs, reliability programs, interruptible tariffs) should be measured by the protocols. The draft protocols should include a list of data that must be collected on energy use or customer load profiles, program capital and operating costs, and incremental customer costs, including comfort changes or customer costs during curtailments. The draft protocols will provide us with a list of the types of load impacts that need to be estimated and other data collection requirements that any adopted protocols need to include. This information will support assessment of program cost-effectiveness. Several parties recommended that we hold workshops before agency staff serve the draft protocols. While we find the recommendations to have merit, we will not mandate the process employed by agency staff to prepare draft protocols.
Agency staff shall serve the draft protocols on the service list to this proceeding, or any related or successor proceedings, and schedule a workshop for interested persons to provide peer review and feedback. Agency staff shall make any necessary modifications to the draft protocols as a result of the comments and prepare a proposed rulemaking or recommend an alternative procedural approach for Commission consideration no later than six months after the draft protocols are circulated.
4.5 Cost-Effectiveness Methodology
Ensuring useful cost-effectiveness analysis will of course require the use of avoided cost inputs adopted in Rulemaking (R.) 04-04-025, the proceeding where the Commission is developing its general avoided cost principles. Of particular interest to demand response practitioners, is how to estimate avoided costs for the top 100 critical hours of peak, an issue that has been raised in A.05-06-004 et al. Parties with an interest in the avoided cost inputs to any specialized demand response cost-effectiveness tests should participate in R.04-04-025. The issue of developing an avoided cost methodology is separate from developing the cost-effectiveness tests themselves.
An industry accepted methodology for evaluating cost-effectiveness of demand response programs has not yet been established. This issue was identified by the assigned ALJ in A.05-06-006 et al., the 2006-2008 program plan applications. In that application, the ALJ required the utilities to submit cost-effectiveness analyses using the Standard Practice Manual (SPM) tests for energy efficiency as one possible measure of cost-effectiveness. Earlier in this proceeding, parties pointed out various shortcomings associated with using the SPM tests for evaluating demand response resources. The time has come that we should begin a process to adapt the SPM tests to the unique features of demand response programs or develop alternative tests for assessing cost-effectiveness.
Agency staff are directed to host a workshop with the objective of scoping the issues that parties believe must be addressed in developing relevant cost-effectiveness tests for demand response programs and identifying process options for developing the cost-effectiveness tests. The parties may believe that it is appropriate for the Commission to provide guidance on certain questions before beginning to develop cost-effectiveness tests for all types of demand response programs. For example, there may be dispute over the need to evaluate the cost-effectiveness of programs that rely on time differentiated tariffs to motivate demand response, as opposed to programs that provide incentives for customer participation. There may also be disputes over what types of societal costs, e.g., lower lighting levels, value of lost load, etc., should be included when evaluating cost-effectiveness. The workshop shall occur no later than March 2006 and notice of the workshop shall be served on the service list for this rulemaking and any relevant or successor proceedings. Within two months following the workshop, agency staff shall recommend to the Commission's Executive Director whether to open a new rulemaking to provide guidance on this topic, and if so, shall prepare a proposed rulemaking or recommend an alternative procedural approach for consideration. This effort should be coordinated with efforts underway in the energy efficiency rulemaking, R.01-08-028, or its successor. If following the workshop, agency staff believes that a set of proposed cost-effectiveness tests for each type of demand response program can be developed without upfront policy guidance from the Commission, they should prepare, using a process that allows for input from interested persons, a set of proposed demand response cost-effectiveness tests and a proposed rulemaking as the vehicle for adoption. If agency staff moves directly to preparation of a set of cost-effectiveness tests, then the proposed rulemaking and cost-effectiveness tests shall be prepared for Commission consideration no later than six months after the workshop occurs.
3 On October 19, 2005, SDG&E filed a motion in A.05-06-006 et al. to accomplish this same objective. This decision obviates the need for the ALJ to rule on the motion in A.05-06-006.
4 D.05-10-042 provides guidance regarding how emergency demand response resources should be counted for resource adequacy purposes. (See Section 7.2.)
