2.1. Commission Guidance
For the last several years, this Commission has encouraged California's investor-owned energy utilities to increase demand response (DR) and implement dynamic pricing tariffs as a means of reducing electricity demand during peak periods. In order to implement dynamic pricing, utilities must deploy advanced meters that can measure energy usage on a time-differentiated basis.
In June 2002, the Commission initiated Rulemaking (R.) 02-06-001, with the goal of increasing the level of DR "as a resource to enhance electric system reliability, reduce power purchase and individual consumer costs, and protect the environment."1 The Rulemaking clarified that the "Commission anticipates that full scale implementation of AMI will provide all customers in all rate classes with the option to choose between dynamic and static rate structures."2 AMI consists of metering and communications infrastructure as well as the related computerized systems and software. SCE filed its AMI application in response to the directives of this rulemaking.
On July 21, 2004, a joint assigned Commissioner and Administrative Law Judge (ALJ) Ruling was issued in R.02-06-001 that established a business case analysis framework for AMI. The ruling specified that the following parameters should be used consistently for each required scenario analyzed:
1. 2006 to 2021 analysis period.
2. Benefits and costs calculated relative to the Base Case.
3. Costs and benefits presented as 2004 present value dollars, with annualized nominal values in work papers.
4. An extensive literature search to identify data or methods used by other electric or gas utilities to estimate benefits shall be performed. Some combination of the specific methods for gathering benefit and cost information (use of Requests for Proposals (RFP), benchmarks from other utilities, indirect benchmarks, in-house cost analysis and actual in-house costs) should be used to estimate the benefits for all of the categories above.
5. Potential costs and benefits that cannot be easily quantified or for which no dollar value can be derived because of uncertainty or lack of data should be reflected in the analysis by including a qualitative assessment of that value.
6. Discount rate equals utility cost of capital.
7. DR savings estimates based on weighted average of savings under average and hot weather conditions developed using Monte Carlo or other simulation techniques.
8. Avoided peak demand cost = $85/kilowatt-year (kW-yr); Avoided energy cost = $63/megawatthour (MWh).
This Ruling provided guidance for this application, as well as the applications filed on March 15, 2005, by SDG&E (A.05-03-015) and Pacific Gas and Electric Company (PG&E) (A.05-03-016).
In D.06-07-027, the Commission authorized PG&E to deploy a new AMI, including authorization for PG&E's rate proposal for critical peak pricing tariffs. The Commission concluded it was reasonable for PG&E to deploy its AMI system, finding PG&E's proposal had sufficient probable and quantifiable economic operating and DR benefits, including sufficient flexibility to upgrade for enhanced features, over the expected 20-year useful life.3 The decision authorized ratepayer funding for $1.6846 billion of project costs, with associated ratemaking provisions. On December 12, 2007, PG&E filed Application (A.) 07-12-009 requesting an additional $623 million4 to upgrade the previously approved system.
On April 16, 2007, the Commission adopted D.07-04-043, a settlement among San Diego Gas & Electric Company (SDG&E), DRA and Utility Consumers' Action Network (UCAN) to allow $572 million in ratepayer funding for SDG&E's proposed AMI Project from 2007 through 2011. The Commission found that there are between $40 million and $51 million in net benefits under the SDG&E Settlement Agreement.
2.2. Procedural History
On July 31, 2007, SCE filed an application seeking authorization of its AMI deployment activities and associated cost recovery mechanism.5 This application is the third related to SCE's proposed AMI project. SCE's application on Phase 1 of its AMI project resulted in a settlement adopted by the Commission in D.05-12-001. The Phase 1 decision authorized SCE to spend up to $12 million to develop the requirements for and work with industry to determine the availability of an AMI with the functions proposed by SCE. SCE completed Phase 1 in late 2006 and filed its Phase 2 AMI application on December 21, 2006. In Phase 2, SCE requested approval and funding for AMI pre-deployment activities related to developing and testing specific AMI technology solutions and preparing its deployment business case. In D.07-07-042, the Commission authorized $45.22 million for specified pre-deployment activities.
In A.07-07-026, SCE requests Commission approval of over $1.6 billion for activities associated with the proposed deployment of SCE's SmartConnectTM AMI system during a five-year period beginning in 2008. In addition, this application requests Commission approval to implement a voluntary Programmable Communicating Thermostat (PCT) load control program and to conduct outreach, marketing, and education on dynamic rates and demand response program offerings for customers receiving the new AMI meters. SCE also requests approval of its proposed cost-recovery mechanism for its AMI deployment costs. SCE's original application estimated that its AMI proposal would deliver about $109 million in net benefits, with operational savings covering approximately 63% of the AMI deployment costs. SCE expected demand response and energy conservation benefits to cover the additional costs and provide the estimated net benefits.
The Commission received three timely responses to this application. On August 30, 2007, Southern California Gas Company (SoCalGas) filed a response expressing its intention to monitor this proceeding, and stating that it may later choose to request full party status. The Alliance for Retail Energy Markets (AReM), an organization of electric service providers (ESPs) that serve most direct access customers in the state, filed a response on September 4, 2007. AReM's response noted that some customers that would be included in SCE's AMI deployment proposal are direct access customers, and requested that the scope of this proceeding include issues of interest to ESPs and their direct access customers. Also on September 4, 2007, DRA filed a protest to this application. DRA expressed its intention to conduct an analysis of several general issues related to SCE's AMI deployment proposal and cost recovery mechanism, and suggested a schedule that included evidentiary hearings for resolving issues found to be within the scope of this proceeding.
Following a prehearing conference on September 26, 2007, the assigned Commissioner and ALJ issued a Scoping Memo and Ruling on October 17, 2007, establishing a schedule for this proceeding, under which DRA and other parties were to serve testimony by December 14, 2007.
On December 5, 2007, SCE served updated testimony reflecting several changes to the estimated costs of its project, and shortly thereafter provided parties with updated work papers. According to DRA, representatives of SCE, TURN, and DRA (the main parties active in this proceeding) met and conferred, and agreed on a proposed schedule that they believed would provide DRA and TURN with sufficient opportunity to analyze the changes to SCE's testimony and address these changes in their own opening testimony.
On December 24, 2007, the assigned ALJ issued a ruling extending the schedule to allow parties sufficient time to review SCE's updated testimony and prepare rebuttal testimony. The extended schedule also adjusted the dates for hearings and briefs. On March 10, 2008, SCE filed two motions, one for adoption of a settlement agreement between SCE and DRA, and one for adoption of numerous stipulations between SCE and TURN. All items contained in the stipulations between SCE and TURN are also contained in the settlement agreement filed the same day, but unlike the settlement agreement, the stipulations do not represent an agreement to resolve all contested issues in the case.6 Hearings addressing the testimony and the settlement agreement were held from March 12-14, 2008. Parties filed opening briefs on third party metering issues, as well as separate briefs on the rest of the issues in the case, on April 4, 2008;7 most parties filed reply briefs on April 18, 2008.8
1 Order Instituting Rulemaking (R.) 02-06-001, p. 1.
2 Joint Assigned Commissioner and Administrative Law Judge Ruling dated February 19, 2004 in R.02-06-001, p. 5.
3 D.06-07-027, p. 9.
4 PG&E later revised the upgrade costs to $572 million.
5 AMI consists of both metering and communications infrastructure.
6 RT 5, Janet Combs: "There are more points agreed to in the settlement with DRA than are agreed to in the stipulations, but all of the points that are agreed to in the stipulations are also contained in the settlements."
7 DRA, TURN and SCE filed opening briefs on the settlement agreement and related issues, and SCE, SoCalGas, and DRA filed additional briefs related solely to issues of third-party metering.
8 TURN and SCE filed reply briefs on the settlement agreement and related issues, and SCE and SoCalGas filed additional reply briefs related solely to issues of third-party metering.