11. 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 comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments were filed on June 30, 2008 by BOMA, CLECA, CMTA, DRA, EPUC, Ice Energy, PG&E, SDG&E, and TURN. Reply comments were filed on July 7, 2008 by PG&E, SCE, SDG&E, and TURN.
The following discussion addresses parties' comments that identified factual, legal, or technical errors in the proposed decision. Comments that merely reargue prior comments have been accorded no weight.
PG&E requested several changes to the timetable to allow more time for customer education and billing system upgrades.137 In response, the timetable adopted by the decision has been changed in several respects so that PG&E has additional time to prepare its filings and additional time after Commission decisions and prior to rates going into effect for customer education and billing system upgrades.
Specifically, the requirement that PG&E file a proposal to revise its large customer CPP rate 30 days after adoption of the decision has been eliminated. Instead PG&E will be required to revise the rate when it files default CPP rates for large C&I customers. Also, the effective dates that PG&E is to propose for default CPP for medium C&I and default TOU for small and medium agricultural customers have been moved from 2010 to 2011 to give the utility more time for system upgrades and customer education. Other related changes have also been made.
A new section has been added addressing PG&E's comments related to incremental costs to implement dynamic pricing and recommending an appropriate process for PG&E to seek cost recovery.
PG&E and DRA argue against requiring PG&E to address changes to the large customer meter roll-out in A.07-12-009, the Smart Meter Upgrade application. PG&E says that it would need to spend money in the near-term and cannot wait for a decision in A.07-12-009 before starting work.138 DRA is concerned that adding additional issues and costs to the proceeding could delay it.139 We continue to believe that A.07-12-009 is the appropriate forum to address changes to the advance metering roll-out. We will authorize PG&E to record expenditures it incurs prior to a decision in A.07-12-009 in a memorandum account and to seek recovery in A.07-12-009.
BOMA and CLECA requested that the Commission direct PG&E to offer customers tools so that customers can determine bill impacts.140 We agree that PG&E should provide customers such tools so that customers understand the implications of different rates, so we have added that requirement.
CMTA asks the Commission to establish a timeline to ensure that PG&E puts in place the necessary communications systems to support RTP in 2011. We have added the requirement that PG&E include a timeline in its 2011 GRC Phase 2 application.
CLECA and PG&E ask the Commission to pay special attention to the interactions between default dynamic pricing and interruptible and other demand response programs.141 We agree that the relationship between dynamic pricing and demand response programs requires special attention and recommend that PG&E and other parties address this relationship in the specific dynamic pricing rate design applications.
BOMA, CLECA, and EPUC argue that residential customers should not be offered a flat rate as an option after the AB1X rate protections have been lifted.142 We believe it is premature to address whether a non-time differentiated rate should be an option for residential customers after the AB1X rate protections are gone. Therefore, we have removed the requirement that PG&E propose a flat rate as an option for residential customers after the AB1X rate protections have been lifted.
TURN recommends that the Commission pay greater attention to the connection between rates and actual procurement costs. According to TURN, if the Commission adopts policies that emphasize rates linked to spot prices while procurement is focused on longer time horizons, the utility could experience significant revenue balancing challenges.143 We agree that the relationship between retail rates and procurement policy requires further attention. One of the policy goals of this decision is to more closely link rates and costs, but this decision is just a first step. For example, if the Commission adopts default dynamic pricing rates, we will learn more about individual customers' risk preferences and preferred rate structures. These customer choices could in turn influence the Commission's and utilities' procurement policies. However, we are not convinced that dynamic pricing will lead to larger revenue imbalances than the current rate structures that also result in large under- and over-collections due to the regulatory lag between changes in costs and retail rates.
The discussion, findings of fact, conclusions of law and ordering paragraphs have been changed consistent with the discussion in this section. Other clarifying edits have also been made.
137 PG&E Opening Comments on Proposed Decision, pp. 6-9.
138 PG&E Opening Comments on Proposed Decision, p. 7.
139 DRA Opening Comments on Proposed Decision, pp. 1-2
140 BOMA Opening Comments on Proposed Decision, p. 4; CLECA Opening Comments on Proposed Decision, pp. 1-2.
141 CLECA Opening Comments on Proposed Decision, pp. 4-5; PG&E Opening Comments on Proposed Decision, p. 5.
142 BOMA Opening Comments on Proposed Decision, p. 8; CLECA Opening Comments on Proposed Decision, p. 3; EPUC Opening Comments on Proposed Decision, p. 8.
143 TURN Opening Comments on Proposed Decision, pp. 3-4.
