VII. Comments on Proposed Decision

The proposed decision of the assigned Commissioner in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and Rule 14.2(a) of the Commission's Rules of Practice and Procedure. Comments were filed on November 20, 2006 by Aglet, Aloha Systems (Aloha), ACWA, California Community College System, CAISO, CLECA/CMTA, DRA, EnerNOC, Ice Energy, PG&E, SDG&E, SVLG, SCE, and TURN. Reply comments were filed on November 27, 2006 by ACWA, DRA, EnerNOC, Ice Energy, PG&E, SDG&E, SCE, and TURN.

In response to the comments, we have made several clarifications, corrections and changes to the proposed decision.

SCE argues again that aggregators should not participate in BIP. SCE explains that the utility has designed BIP to be integrated with a particular enabling technology and communications network. The technology gives SCE's Grid Control Center (GCC) "near-real time visibility" of load reductions. Aggregated load cannot be connected to the network in the same way, the GCC may, therefore, discount the contribution of such load. SCE points to the day-of CBP as a more appropriate program for aggregation.⁷²

DRA recommends requiring tests to ensure that aggregator participation will not hinder the existing BIP program.⁷³

Demand aggregators can attract customers that would not otherwise participate in BIP. The load from aggregators will be additive to SCE's existing BIP participation and will not force SCE to change its relationship with its existing BIP customers. Therefore, we do not find SCE's arguments to be persuasive. We also do not see a need to require tests since SCE's existing program will be unaffected. SCE should work collaboratively with aggregators so that the aggregators can provide the level of visibility, on an aggregated basis, that the utility needs.

In relation to BIP, CLECA/CMTA note that a customer has a window from November 1 to December 1 to inform its utility of any increase or decrease in its firm service level. CLECA/CMTA request an extension of the window so that a customer has 30 days from the date of this decision to consider program changes adopted in this decision.⁷⁴ We have modified the decision to authorize an extension.

PG&E explains that the proposed decision's discussion of its AC Cycling proposal in not accurate. PG&E clarifies that it initially requested a $7.5 million budget to install 5,000 switches in 2007 and fund ten years of costs. Alternatively, $7.5 million could fund 15,000 switches in 2007 if the future year costs are approved in a separate application. The utility proposes to establish the final budget through the resolution approving the advice letter.⁷⁵

We support PG&E's proposal to move forward with an AC Cycling program. However, we are concerned that authorizing $7.5 million for an estimated 5 MW may be too expensive relative to other program modifications PG&E has proposed. The Commission needs more information to approve a specific program. We will approve in concept a 5,000 switch program using the existing demand response budget and subject to advice letter review.

SCE is confused by the proposed decision's directive to allow TA/TI funds to be used for direct customer expenses. SCE is concerned that the directive will require an additional payment beyond the normal TA or TI incentive⁷⁶ We are not creating an additional incentive. Rather we are providing the utilities flexibility to use TA/TI funds for a broad range of expenditures, including direct customer costs. If SCE's TA/TI incentives already go toward all of a customer's actual reasonable costs, then the flexibility granted is merely restating the status quo for SCE.

Aloha raises concerns about utility administration of the TA/TI program.⁷⁷ The Demand Response Measurement and Evaluation Committee intends to evaluate the TA/TI program in the future and will consider input such as that provided by Aloha.

Based on comments from PG&E and TURN, we have removed the requirement that PG&E implement soft triggers in its CPP program.

The CAISO encourages the Commission to work with the CAISO and other parties to develop demand response program triggers that are aligned with the needs of the grid. Well-aligned demand response programs can add greater capacity and liquidity to the wholesale market, create greater demand elasticity, and tap into an existing, available resource.⁷⁸

The Commission similarly looks forward to working closely with the CAISO to align and integrate the utilities' demand response programs with the wholesale market and the needs of the grid. We are encouraged that the CAISO is engaged in this area.

In addition to revisions made in response to comments, we have made other minor corrections and clarifications to the proposed decision.