3. Parties' Comments on the Issues Posed in the September 19 Ruling

a. AMI Business Case

In general terms, commenting parties supported⁴ the idea of working on the analysis framework as a prelude to entertaining the utilities' actual business cases; however some disagreed with details included in the proposed evaluation framework attached to the September 19 ruling⁵ and felt it was premature to endorse the Attachment⁶ or that an existing PG&E model, if revised in a workshop setting, is a preferable approach.⁷ Other parties proposed variations to the analysis framework. For example, ORA proposed that the business case analysis framework be expanded to include a customer-led roll out as an alternative.⁸ CCEA suggested that Phase 2 develop the list of costs and benefits (categorized as "short term", "long term", and "out of scope") to be included by the utilities in their advanced metering business case applications, filed after this OIR has concluded.⁹ SF Co-op urged us to be mindful that niche marketing of advanced metering infrastructure in transmission-constrained areas may be preferable to mass meter deployment.¹⁰

I am resolved that AMI will be the principal focus of our efforts in Phase 2. We will continue to use a working group format to examine AMI from a broad-based perspective,¹¹ as suggested by CCEA, rather than strictly from the utilities' business case perspective. Because PG&E presented an illustrative business case last year in Working Group (WG) 3, it would be logical to continue the AMI group process in that setting, though AMI efforts obviously affect customers of all sizes. I anticipate that WG 2 will be focused on RFP tariff development, and therefore see WG 3 as the best forum for this work.

Toward this end, I direct the WG 3 moderator to ensure that each interested party be allowed time to present its proposed list of costs and benefits to be included in the AMI analysis at a public workshop. This discussion should include a review of the costs and benefits from three different perspectives - utility (business case), customer, and societal, and must include the costs and benefits described in Appendix A of the September 19 Ruling, as well as a proposal detailing how to measure these costs and benefits. It will be useful to categorize these benefits as short term, long term or out-of-scope as noted above. Thereafter, agency staff will prepare a workshop report. Once the workshop report is published, interested parties will be asked to file comments on the report, including their recommended list of costs and benefits to be included in the AMI analysis, a brief summary of how they plan to gather or estimate either costs or benefits, and whether they agree with the proposal in Appendix A that each utility should examine three scenarios: expected costs under a business as usual case, a full scale rollout of AMI, and a partial roll out where only a selected fraction of each or some customer classes would receive a meter upgrade.

As noted below, this effort should also address how control technologies, including but not limited to residential A/C cycling, might be complementary to core AMI capabilities and allow various types of demand response programs to be implemented in addition to price responsive tariffs.

At the conclusion of the working group process, the Commission should be in a position to issue a template that will result in the respondent utilities filing applications for authority to implement AMI and recover its costs.¹²

b. SPM Revisions

Those commenting on the merits of revising the SPM as part of the preparation for the utilities' advanced metering business cases were generally cautious, suggesting that the issues are complex and may require hearings to resolve. For example, both PG&E and CLECA noted that the SPM is designed primarily for evaluating energy efficiency programs, and may not be entirely useful for evaluating the cost effectiveness of demand response programs. ORA notes that revisions to the SPM are being considered in the current energy efficiency rulemaking (R.01-08-028) and that it would be wasteful to end up with two different standard practice manuals. Other parties, such as SDG&E and TURN conditionally support the suggestion in the September 19 Ruling that a consultant be retained to revise the SPM, with various caveats. For example, TURN believes that evidentiary hearings may be required to resolve revision-related disputes.

Given the above comments, and our need to keep Phase 2 relatively narrow, I believe that revision of the SPM should not be pursued as part of Phase 2. Instead, we may revisit this issue once the revisions underway in the energy efficiency rulemaking are complete.

c. AC Cycling

The parties' views are divided on the issue of comparing AC cycling with price responsive demand options in the AMI business case. PG&E argues that AC cycling and AMI are not comparable and thus AC cycling should not be evaluated at this point. SCE supports investigating the merits of direct load control alternatives within Phase 2, but is concerned that effort not jeopardize its proposal in the ongoing procurement docket to expand deployment of AC cycling. On the other hand, SDG&E notes the September 19 Ruling asks parties to compare AC cycling technologies that support emergency load shedding programs with AMI technology that supports both dynamic pricing and load shedding programs. SDG&E argues that the issues should not be framed as one of mutually exclusive choices. In SDG&E's view, AC Cycling should be considered as one part of a utility's demand reduction portfolio, and in the interests of program design flexibility, policymakers should ensure that over time AC cycling technologies are compatible with dynamic pricing programs; thus, value should be placed on technologies that facilitate both policy choices, AC cycling and AMI. ORA also believes that the only viable AC programs are those that support dynamic pricing and load shedding. TURN supports establishing the framework for comparing AC cycling to price responsive demand response programs. CLECA generally supports the Commission's desire to take a direct look at AC load control as a step in the direction of addressing equity issues between those customers with large AC load and those who do not have such peaky load.

In recognition of the arguments of several parties that the technologies that implement these programs should be complements to AMI (rather than substitutes for it), I will include a review of AC cycling options as part of a parallel review of how control technologies interface with AMI.

Specific control technology proposals should not be approved without a clear understanding of how control technologies interface with core AMI capabilities. There are many unresolved issues about the nature and source of a price signal versus a curtailment signal, the protocols for transmitting such a signal, the devices that would receive, interpret and implement a decision rule to curtail a particular type of end-user equipment, etc. all of which should be examined before any further major IOU investments are authorized.

d. RTP Tariff

In general, parties support continuing RTP tariff development. ORA urges immediate development of a RTP tariff with or without a pilot, prior to Summer 2004. However, both ORA and CLECA note that existing rate designs do not support market-based prices, which are necessary for RTP tariffs. Underscoring the complexity of the issue, CMTA urges the Commission not to rush to complete the task of developing a full-scale RTP tariff by Summer 2004, but to take the time to resolve underlying fundamental issues (principally the fact that the actual rates to be contained in the RTP tariff must be linked to the utilities' cost of service) in order to develop a tariff that customers will actually use. In the meantime, CMTA urges consideration of a small scale pilot program roll-out next summer to test customer response to a particular baseline methodology, market price signals, and other design features.

After weighing these various views, I believe that parties in Phase 2 should proceed to develop a full production tariff, even though this may require more time than we have in Phase 2, and may require evidentiary hearings at some point. In other words, parties should view this task of "getting it right" as an ongoing one, not limited by the delineation of Phase 2.¹³ Parties should use the WG 2 structure to complete this task, and should remain open to CMTA's idea that a small pilot might still be a worthwhile endeavor while the full tariff development is ongoing, as long as the development of a small pilot does not unduly complicate or hinder the group's progress in developing a full production tariff.

e. Revenue Shortfall Recovery

After reviewing ORA's revenue shortfall recovery proposal in Phase 1, the Commission required the utilities to make proposals for recovering net revenue losses from participation in the voluntary CPP tariff from within the class that caused the losses. Commenting parties are divided on how this should be handled going forward. CCEA urges us to adopt a method of recovering revenue shortfalls in Phase 2 based on these filings. Some parties believe we must provide clarity as to where the issue will be resolved: here or in the utilities' general rate cases. ORA, SCE and TURN believe that evidentiary hearings may be needed to address some or all of the revenue shortfall issues associated with the ORA proposal or demand response programs in general. PG&E suggests that we resolve the issue separately from the AMI business case, in order to avoid delaying AMI. SDG&E wants a simpler approach, one that decouples revenue recovery from utility incentives, and is willing to work with all parties to develop a workable incentive program for utilities to recruit and retain customers on demand response programs and tariffs. ORA, the original proponent of the proposal, suggests that the dynamic shortfall discussion be deferred, but that the structural shortfall discussion be completed in Phase 2.

After weighing all of the comments, I conclude that ORA's revenue shortfall proposal should not be pursued in Phase 2. We have much to do in Phase 2 and this particular issue remains somewhat conceptual at this point, given current demand response participation rates; it can be addressed more efficiently in the future. While a future demand response forum effort is appropriate to establish broad policy decisions such as class versus system recovery, the specific mechanics needed to implement such a policy should then be developed in each IOU's general rate case (GRC).

f. CPA DRP

The September 19 ruling noted that there are ongoing implementation difficulties associated with the CPA DRP. Most parties who commented on this aspect of the ruling acknowledge that these issues must be resolved in order to ensure greater demand response participation. I see this as a serious ongoing implementation challenge. To that end, the assigned ALJs will shortly issue a ruling designed to ascertain the precise nature of the obstacles to implementation and thereafter will recommend to the Commission the appropriate actions needed to resolve any outstanding problems.

g. Agricultural Customer Participation

The September 19 ruling noted the need to expand opportunities for additional agricultural customer participation in demand response programs. Not all agricultural customers have interval meters. There is also a significant lag in the deployment of these meters for PG&E agricultural customers, as compared to SDG&E and SCE. There were various comments on these issues, but in general terms, the consensus is that they should be addressed separately, and not as a prime focus of Phase 2. I agree.

Consequently, I have asked the assigned ALJs to continue to develop these issues during Phase 2, independently from the AMI business case. One element of their inquiry will be to determine whether there are any tariffs or versions of CPP that would facilitate the demand response participation of agricultural customers. In addition, the ALJs will issue a ruling shortly that focuses on metering service issues¹⁴. As part of that effort, they will attempt to resolve outstanding concerns about agricultural customers who lack interval meters.

h. Miscellaneous Metering Issues

The September 19 ruling noted that among ongoing implementation matters, there are several meter "clean up" issues related to implementing the specific programs authorized in D.03-06-032, including:

· Uniformity in the provision of metering services for those customers with an Assembly Bill (AB) 29 X- equivalent metering system.

· Installation of AB 29 X equivalent metering systems for new IOU customers added since the AB 29 X conversions that took place between Fall 2001 and Summer 2002.

· Uniformity in the linkage between the existence of AB 29 X equivalent metering systems and automatic transfer of such bundled service customers to a Time of Use(TOU) rate.

In addressing these meter "clean up" issues in Phase 2, my intent is to make uniform the utility practices regarding who gets RTP metering systems, what costs are charged, and what services are provided to demand response program participants. This is consistent with the Commission's recent action in issuing Resolution E-3835. Resolution E-3835 identifies the demand response rulemaking as the appropriate proceeding to develop a cohesive statewide policy regarding meter installation, cost recovery and TOU rate schedules. Furthermore, I am interested in knowing how customers have responded since the AB 29X meters have been installed, and direct agency staff to begin working with the utilities in gathering and analyzing the appropriate data. Interagency staff will continue to work to obtain the necessary information from the respondent utilities, and following notice and comment procedures (as we have throughout this proceeding), the ALJs will draft the necessary decisional documents at the appropriate time during Phase 2 that will accomplish our goals in this meter "clean up" area.

i. Planning to Achieve 2007 Targets

In its comments CCEA proposes that we add to Phase 2 an element that would estimate 2004 planning and preparation activities needed to meet the interagency 2007 5% demand response goal. CCEA states that utilities should be given the option of proposing a planning and preparation scope for 2004, including budgets, for potential approval in the Phase 2 decision.¹⁵ I believe this exercise could be quite fruitful, as a check on the feasibility of our 5% goal. To begin that effort, I will require each respondent to submit a plan containing its specific 2004 plans for meeting the 5% goal in year 2007; each respondent may also include its post-2004 plans to the extent then known. This plan will be due for filing on March 31, 2004, and should include the respondent's position on the need to modify the existing programs authorized in D.03-06-032 to achieve the 2004 goal, preliminary identification of new programs that may be needed to achieve the full 2007 goal, and any proposed changes in the goal based on initial deployment of programs.

⁴ See San Diego Gas & Electric Company's Comments on Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, pp. 1-2.

⁵ Establishing the Scope for The Business Case Structure to Evaluate Advanced Metering, Attachment A to the September 19 Ruling.

⁶ Southern California Edison Company's Comments on Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, pp. 2-3.

⁷ Comments of Pacific Gas and Electric Company on "Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, pp. 4-5.

⁸ Comments of the Office of Ratepayer Advocates on Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, p. 3.

⁹ Comments of the California Consumer Empowerment Alliance on Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, pp. 2-6.

¹⁰ Comments of the San Francisco Community Power Cooperative on Proposed Phase 2, pp. 1-2.

¹¹ Under this approach, costs and benefits would be categorized as "short term," long-term", and "out-of-scope." Id., pp. 4-6. 5

¹² As the September 19 Ruling proposed, respondents will continue to record and track the administrative costs associated with Phase 2, to the extent consistent with the scope of the proceeding outlined in today's ruling, in their Advanced Metering and Demand Response Accounts previously established in Phase 1. The full commission must ratify the reasonableness of these expenses prior to authorizing actual cost recovery.

¹³ If the matter is not resolved by the end of Phase 2, it can easily be rolled into the subsequent OIR planned to follow Phase 2.

¹⁴ See Section 3.h of this ruling.

¹⁵ Comments of the California Consumer Empowerment Alliance on Assigned Commissioner and Administrative Law Judge's Ruling Setting Forth Scope of Phase 2, p 3.