4. Policy Issues for 2005 Programs

4.1 Counting MW from Reliability Programs Towards Price Responsive Demand Program Goals

As PG&E points out in its October 15, 2004 filing, "Reliability programs are generally called when "day-of" prices are very high, and price responsive programs are generally implemented in anticipation of these high prices, but on a "day-ahead" basis." (p. 50.) As explained above, we will categorize the MW from any program that provides a day-ahead demand reduction signal, whether it is based on a price, temperature, or reliability forecast, to count towards meeting the utilities' price responsive demand program goals adopted in
D.03-06-032 and D.04-12-048. We characterize these programs as day-ahead notification programs. Programs that are triggered the day-of serve a different purpose, to support immediate system reliability, and do not count toward the program goals adopted in the Energy Action Plan, our procurement decision, or D.03-06-032. We retain this approach for 2005 programs and retain the goals adopted in D.04-12-048.

4.2 Integrated Demand Side Management (IDSM) Marketing

All three utilities advocate a `portfolio' approach to marketing and communicating demand response programs, especially to large customers. This involves analyzing a customer's operations to identify demand management opportunities that include conservation, energy efficiency, time of energy use management, demand response, and self-generation. Integrating demand management options can promote multiple gains through one customer investment. The utilities are in various stages of IDSM marketing development. Similarities among the utilities include the use of informational tools such as website where customers can view their usage data and information displays, such as the Energy Orb, that alerts customers of current rate periods and impending demand response events. Among other items, SCE requests funding for collateral material, PG&E would fund account executive training, and SDG&E's includes a building operator certification program to train building operators in energy efficient operation of buildings.

Conceptually, providing customers with an integrated presentation of their energy management options, that addresses demand reduction strategies, energy efficiency, and other options, makes complete sense and is to be encouraged. We approve the concept and encourage the utilities to pursue such an approach. However, the way that the utilities have addressed their efforts to accomplish this effort in their budget requests is not consistent. SDG&E, for example, identifies a category called Customer Awareness, Education, and Outreach ($2.04 million) that includes their integrated demand management efforts. SDG&E estimates that $900,000 of this line item will be allocated to customer education and awareness efforts for the IDSM effort. PG&E, on the other hand, states that they are requesting funding to implement the integrated marketing, but initially no separate budget was requested, instead the costs appeared to be incorporated into the budgets for each individual demand response program. In comments, PG&E clarified its budget as $2.125 million. SCE, on the other hand, asks for $452,040 for Integrated Energy Efficiency/Demand Response Marketing.

Two elements of the proposed integration stand out: expansion of customer services to include more in-depth audits that will provide both demand response and energy efficiency benefits and extension of these services to more customers. PG&E notes these efforts will be phased over time and what is emphasized in 2005 may be different than what is appropriate in subsequent years.

4.3 Additional Meter Installations and Costs

In their October 15, 2004 filings, the utilities have pointed out that there is some inconsistency between utilities about installation of interval meters in response to AB1X 29 such that not all customers with loads greater than 200 kW have received meters. The utilities should install interval meters meeting the technical standards of the AB1X 29 meters for all customers with loads greater than 200 kW and place those customers on a time-of-use rate until such time that TOU rates for these customers are replaced with a new default tariff consistent with the December 8, 2004 ruling. SDG&E notes that it was only directed to install meters for customers with load of 300 kW or greater under ABIX 29. Although SDG&E has installed interval meters down to 200 kW, the communication infrastructure to support the installed meters for loads between 200 and 300 kW has not been completed and is on hold pending approval of an advanced metering infrastructure. We direct SDG&E to proceed forward with installing necessary communications infrastructure for customers with loads above 200 kW. These costs should be recorded as described for meter costs herein.

In its proposed budget, SCE requests $354,000 for on-going costs not covered by general rate case revenue requirements for meters installed in 2003 in excess of the 12,000 meters authorized by AB1X 29. Any new meters installed are expected to be recovered as part of SCE's authorized revenue requirement. PG&E does not specify their expected costs to install meters for all customers with demand of 200 kW or greater. D.01-05-032 authorized SDG&E to install interval meters for customers 100 kW and above, and therefore SDG&E does not appear to have this same issue.

D.01-05-032 authorized SDG&E to establish a memorandum account to record all capital and operating costs associated with installing the meters. The same decision allowed SDG&E, after Commission review, to recover in rates the recorded costs associated with the interval meters, less any funding provided by the California Energy Commission pursuant to Senate Bill 1X 5 and Assembly Bill 1X 29. Cost allocation methodology was to be subject to a subsequent application. This approach is reasonable for all three utilities for recording costs associated with meeting our goal of having interval meters in place for all customers with demand of 200 kW and above. Review of the costs recorded in the memorandum account should be limited to auditing that the amounts recorded were spent on the approved program. SCE should book the costs it identifies as Real Time Energy Meters into this memorandum account. CLECA's comments on the draft decision express opposition to any proposals to spread the costs of new meter installations across the entire customer base. As the ratemaking approach we adopt expressly defers the issue of cost allocation to a subsequent application, we make no change based on CLECA's comments.

In comments on the draft decision PG&E filed a proposed budget for completing installation meters for customers with demand of 200 kW and greater and for certain costs associated with PG&E's new default rate application. We do not approve (or disapprove) of the budget at this time but we do authorize PG&E to book its meter costs into its Advanced Metering and Demand Response (AMDRA) account, for future cost recovery.

SCE also proposes that customers over 200 kW, who are required to have a real-time or interval meter installed, be placed on a TOU rate. We agree with this requirement for all customers, including direct access customers, on an interim basis as it is consistent with our directive that the utilities install interval meters for all customers with demand of 200 kW and greater. Installation of interval meters would serve less purpose if customers were not taking service under a time-differentiated rate. When the Commission acts upon the January 20, 2005 rate design applications, customers should then be placed on the new default tariff, instead of the current TOU rate. SCE's current tariffs reference installation of the AB1X 29 meters as a precursor to being placed on TOU rates. SCE proposes to remove all references to AB1X 29 so that all customers over 200 kW are placed on TOU rates and outfitted with an interval meter (if they don't already have one). This change in the tariffs is reasonable, and if PG&E or SDG&E also have comparable language in their tariffs, they are authorized to make the same changes as proposed by SCE.

4.4 Authorized Budget Period

All three utilities recommend that we adopt programs and budgets for their demand response efforts through 2008. They argue that multi-year funding would provide program stability and align the budget cycles for demand response efforts with those of energy efficiency programs which would promote development and delivery of integrated programs and demonstrate stability of program design to potential customers. We agree that multi-year program authorization and funding is desirable, but given the newness of these programs, their lack of track record of demonstrated value to ratepayers, and the uncertainty of advanced metering infrastructure deployment (that will be considered in March 15, 2005 applications) that may affect future customer penetration and program plans, we find that the time is not ripe to adopt programs or associated budgets for 4 years. In this decision we will only adopt programs for 2005. Instead, we direct SCE, SDG&E, and PG&E to file applications for 2006 through 2008 demand response programs on June 1, 2005, the same date they will file 2006 through 2008 energy efficiency applications.

SCE continues to advocate for multiyear funding authorization in this decision, stating that nothing will have changed between now and June 1 to change SCE's offerings. As The Utility Reform Network (TURN) points out in its reply comments, deferring consideration of a multiyear budget to a new application will allow the Commission to thoroughly evaluate the proposed programs through an evidentiary process that has not occurred in this rulemaking. Evaluating these programs under a more rigorous process is appropriate for 2006-2008 program years given the large budgets that are anticipated over the three-year period.

4.5 Budgets and Budget Flexibility

The utilities request that remaining budget dollars from the 2003/2004 large customer programs be made available or "carried over" for development of the 2005 programs. They also request the discretion to allocate total budgeted amounts between various demand response programs and their related activities to allow the utilities the flexibility to respond with those programs the market wants most.

The utilities need the flexibility to determine how to allocate demand response funding across the various programs including marketing and many other activities. Because most of these programs are new, to achieve the desired outcome of developing our load reduction capability, we will need to provide flexibility for the utilities to redirect program funds to capture more load reduction capability to successful programs. Approving an overall level of funding and then allowing the utilities the flexibility to manage the allocation of the overall budget will prevent problems associated with over funding or under funding a given area. This approach complements the existing practice of rolling over unused funds to subsequent program years.

We will approve spending flexibility within the following program categories: Day-Ahead Programs, Reliability-Triggered Programs, and all other programs. The utilities should have the flexibility to shift funds between the programs that we approve within each of these broad categories, consistent with SDG&E's recommended fund shifting guidelines. Under SDG&E's proposed guidelines, the utility can shift up to 25% of one program's funds into another program in the same category without prior Commission approval; the load reduction goals for the programs would also shift accordingly. SDG&E proposes that if the budget shift exceeds 25%, and/or the aggregated load reduction goal needs to be changed, the utility should file an Advice Letter (AL) to request that change. We approve these fund shifting guidelines. SDG&E proposes to use the AL process to propose new programs within the authorized budgets. Because we only authorize 2005 programs in this decision, we need not act on this recommendation.

All three utilities filed revised 2005 program budgets and goals as part of their comments on the draft decision to reflect the programs adopted herein. In addition, the utilities separately identified remaining funding from 2003/2004 programs that will be carried over, and how they will distribute that funding amongst the various 2005 program categories. Following the discussion of proposed programs, we identify the adopted budgets and goals for the approved programs.