8. Positions of the Parties
Including the three applicants, 10 parties participated actively in hearings, and several other parties filed briefs. Certain parties, such as BluePoint Energy, Transphase, and SF Community Power limited their participation to relatively narrow areas of interest, while other parties, such as TURN and DRA, conducted reviews of several facets of the applications and made overall recommendations for the handling of the applications. This section contains brief summaries of the positions taken by the main non-applicant parties in this proceeding.
8.1. BluePoint
BluePoint advocated for the Commission to allow certain types of backup generation (BUGs) to receive demand response funds through the Technical Assistance and Technology Incentives program. BluePoint argues that this is appropriate because BUGs are demand-side resources that reside behind the utility electric meter, and can be configured to look like demand response and function as participating load.29 In addition, BluePoint argues that BUGs can use renewable fuels such as biogas to reduce demand on the grid at peak times. BluePoint also recommends that the Commission allow demand response aggregators to access the energy market through the utility, with the utility acting as scheduling coordinator.30 BluePoint argues that this will benefit both utilities and aggregators.
8.2. Transphase
Transphase focuses on expanding the availability of permanent load shifting. Transphase proposes that the Commission require the utilities to offer rebates and incentives directly to customers who choose to install thermal energy storage or permanent load shifting. Under the Transphase proposal, utilities would be required to provide a permanent load shifting "standard offer" program that would offer rebates of up to $1,400 per installed kilowatt of permanent load shifting over the 2009-2011 period.
8.3. SF Power
SF Power makes several proposals related to demand response programs in and around the San Francisco area. In particular, SF Power proposes the continuation of its Small Commercial Aggregation Pilot Program (SCAP) adopted and expanded by the Commission in 2007, and the adoption of a municipal pump load demand response pilot.31 In addition, SF Power requests that the approval of certain PG&E proposals in the San Francisco area be contingent on crediting the energy saved by those programs towards the power otherwise provided by certain generators that operate primarily at peak times ("peakers") within San Francisco, such as the Potrero Power Plant, in order to hasten the retirement of those generators.32 SF Power also recommends that the Commission provide incentives to third parties to enroll customers in available demand response programs in lieu of approving PG&E's proposals for marketing, education, and outreach.33 In addition, SF Power advocates for various changes in PG&E's Capacity Bidding Program34 and Automated Business Energy Coalition program,35 the replacement of APX as the provider of data and Web-based services for demand response programs,36 expansion of access to the technical incentives program, termination of the Peak Student Energy Actions Program,37 and consolidation of multiple meters at a single facility in appropriate situations.38
8.4. CLECA
CLECA advocates for the continuation of the Base Interruptible Program as a separate program rather than as an option under "cafeteria style" programs such as PG&E's Peak Choice program.39 CLECA argues that the structural differences between the Base Interruptible Program and many other programs would cause confusion for customers and reduce the effectiveness of the Base Interruptible Program model if Base Interruptible Program were subsumed in another program. CLECA also argues that customer participation in multiple programs should be allowed as long as customers are not paid more than once for the same load reduction, and advocates for an agreement between SDG&E and CLECA under which SDG&E will track Peak Time Rebate payments to customers also participating in SDG&E's Summer Saver program, in order to allow dual program participation without duplicative payments.40
8.5. CDRC
The CDRC, which represents a group of demand response aggregators, argues that the avoided costs used to calculate the benefit to cost ratios are too low, that the avoided costs of transmission and distribution should be included in the cost effectiveness calculations, and that the utilities have underestimated the customer benefits used in the cost effectiveness analysis. CDRC also advocates for timely approval of third-party aggregator contracts, and for changes in the baseline methodologies used by the utilities for settlement purposes. In addition, CDRC encourages the Commission to expand customer participation in demand response activities by allowing customers to participate in more than one demand response program at a time.41
8.6. TURN
TURN argues that the cost effectiveness analyses used in the utilities' applications is flawed, and that the administrative costs associated with many of the proposed programs are excessive. In general, TURN argues for reductions to the funding of many of the utilities' proposed programs and pilots, and especially for the reduction of costs related to administration, education, and marketing.
8.7. DRA
DRA contends that in evaluating demand response proposals, "[c]ost-effectiveness should be considered the most important factor that reveals whether further analysis is warranted."42 DRA argues that, with few exceptions, the other identified criteria are either taken into account in the cost effectiveness analysis or in the utilities' Load Impact analysis, or cannot be meaningfully evaluated until the Commission more clearly defines certain policies and goals for demand response. One exception, according to DRA, is the criterion requiring adaptability to changes in the structure of the electricity market, which DRA includes in its own proposed ranking system for evaluating the proposals made in this proceeding. DRA's ranking proposal incorporates the utilities' cost effectiveness estimates with their Load Impact analysis and the probability that a program can be integrated into the new CAISO markets. DRA ranks programs as follows:
29 BluePoint Opening Brief, p. 3.
30 BluePoint Opening Brief, p. 5.
31 SF Power Opening Brief, p. 27.
32 SF Power Opening Brief, pp. 10-14.
33 SF Power Opening Brief, February 4, 2009, pp. 2-5.
34 SF Power Opening Brief, pp. 5-9.
35 SF Power Opening Brief, p. 10.
36 SF Power Opening Brief, p. 9.
37 SF Power Opening Brief, p. 13.
38 SF Power Opening Brief, pp. 29-31.
39 CLECA Closing Brief, p. 6.
40 CLECA Closing Brief, pp. 8-9.
41 CDRC Opening Brief, p. 3 (summary).
42 DRA Opening Brief, p. 7.
