V. Comments on Draft Decision

The draft decision of ALJ Simon in this matter was mailed to the parties in accordance with Pub. Util. Code § 311(g)(1) and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed on September 26, 2005 by CBD, Green Power, ORA, PG&E, SDG&E, SCE, and UCS. Reply comments were filed on October 3, 2005 by CalWEA, SCE, and UCS.

CBD provides a useful summary of the action taken by the Alameda County Board of Supervisors with respect to renewal of the permits of Altamont Pass wind facilities. CBD notes that the permit conditions require only about 40 MW of repowering by 2010, in contrast to PG&E's illustrative planning estimate that it will acquire approximately 400 MW of new and repowered wind by 2010. CBD urges us to develop a special cost mechanism to support such contracts.

We agree with CBD that PG&E cannot expect the conditions in the Alameda County permit renewals to provide the repowered wind resources it needs. We revise the draft decision to strengthen our direction to PG&E on Altamont Pass resources. We will not undertake here any special treatment for Altamont Pass wind resources, since the Legislature has provided the MPR/SEP framework for the costs of RPS procurement. We revise the draft decision to encourage the submission of bids for wind repowering in RPS solicitations where, if the bid meet the least cost/best fit evaluation criteria, a winning bid would be eligible to apply to the Energy Commission for SEPs.

Green Power points out that the utilities must be more aggressive in responding to possible shortfalls in RPS procurement. It notes that many existing contracts will be expiring in 2006, raising the possibility that the utilities' baseline resources may erode. Green Power also notes that many contracts with QFs did not come to fruition, suggesting that a similar problem may occur with RPS contracts.18 Because contracting with a project using a technology that is not commercially tested also has risks of non-completion of the planned project, Green Power recommends applying a discount to the planned capacity estimates of such projects for planning purposes. We agree that the utilities should develop a robust analysis of possible sources of shortfalls in procurement and should take steps to prevent shortfalls due to contract failure. We revise the draft to make this requirement more explicit.19

ORA generally supports the draft decision and emphasizes the importance of contingency planning for the utilities.

PG&E raises several concerns about the draft decision's requirements and timetable for submission of supplements to the utilities' plans, as well as about the coordination of transmission planning processes. PG&E states (as does SCE) that the draft decision's expectation that the supplements will be fully public is not realistic. Much of the information that forms the basis of its planning, PG&E asserts, is confidential material related to its RPS solicitations. We understand this concern, but seek to maximize the quality and quantity of planning analysis that is publicly available. We revise the text of the draft decision to describe our expectations more fully. PG&E also believes that 60 days, rather than 30, is appropriate for submission of the supplements. We agree, and both change the time period and expand on the relationship of the supplements to other submissions.

PG&E asserts that the draft decision misconstrues the transmission component of its plan by failing to acknowledge PG&E's incorporation of its transmission cost ranking report. The TRCR, however, is an aid in annual procurement, not a long-term transmission planning process. PG&E also points out that transmission planning for renewables is a complex process, and filings in this proceeding will be related to those in other proceedings. PG&E suggests that we centralize renewables transmission issues in I.05-09-005, which we initiated last month. Although we intend to coordinate these two proceedings closely, and revise the text of the draft decision to reflect this, we do not believe that RPS procurement planning should proceed without attention to transmission planning and related contingencies.

Finally, PG&E presents its view that repowering of wind facilities at Altamont Pass is a more complex process than the draft decision suggests. We welcome PG&E's statement that it will provide additional information in its supplement about the recent Alameda County permitting process for Altamont Pass facilities. We revise the text of the draft decision to reflect current information about the permitting process and to expand our discussion of repowering options.

SDG&E would like to delay filing its supplement until it has more information available, and suggests that the supplement should be filed either with its long-term plan in R.04-04-003 early in 2006, or by January 15, 2006. We do not adopt either suggestion, but do extend the period of time for preparing the supplement.

SCE, as did PG&E, asserts that the use of confidential information is essential to the planning we requested in the supplement. Like the other utilities, SCE also seeks to extend the period for filing the supplement, either to the 2006 RPS procurement plan or to a time 60 days after the mail date of this decision. We make changes to the draft decision responding to these concerns. SCE also claims that its efforts to engage its current wind resources in negotiations on repowering are not meeting with a great deal of success. We note this issue in the revised text of the draft decision.

UCS focuses its comments on contingency planning. It seeks, among other things, that we require the utilities to analyze transmission issues in the context of contingency planning and that we require plans to include an analysis of possible deviations from expected output. We find merit to some of these specific suggestions, but see the 2006 planning process as the more appropriate time to implement them. We clarify in the text our expectations for the relationship of the supplements to 2006 planning processes.

Findings of Fact

1. It is reasonable for utilities to make estimates of future procurement from specific types of renewable resources for planning purposes.

2. It is reasonable for utilities to plan for the possibility that not all planned renewable developments will deliver the planned-for energy, whether due to erosion of the baseline renewable resources, errors in load forecasting, transmission constraints, or unforeseen difficulties in project development.

3. It is reasonable for utilities to make estimates of future needs for transmission, delivery points, remarketing costs, and other delivery issues for renewable resources for planning purposes.

4. The planning estimates of the utilities for the year 2010 currently identify wind, geothermal, and solar thermal resources as significant sources of renewable energy procurement; these resources may be located in areas that are remote from the utility's load center.

5. The utilities' long-term RPS plans do not adequately address the consequences of the estimated reliance on resources that may be remote from the utilities' load center.

6. The long-term RPS plans of the utilities do not address all areas necessary for adequate RPS planning.

7. It is reasonable to require the utilities to supplement their plans, as needed, with respect to transmission planning, repowered wind resources, and alternative and contingency planning.

Conclusions of Law

1. Utilities should provide analysis and reasoned discussion in their RPS planning of the consequences of reliance for RPS procurement on resources remote from their load centers.

2. Utilities should address in their long-term RPS planning the availability of renewable resources both in and remote from their service territories.

3. Utilities should address in their long-term RPS planning transmission planning, including delivery outside the utility's service territory, curtailablity, remarketing costs and benefits, and other alternatives to building new transmission.

4. Utilities should address in their long-term RPS planning the repowering of wind facilities currently under contract to the utility.

5. Utilities should include in their long-term RPS planning analysis that includes high, low, and base case scenarios.

6. Utilities should address in their long-term RPS planning potentially significant impediments to RPS compliance and include contingency planning addressing the identified impediments.

7. Utilities should explicitly address in their long-term RPS planning lessons learned from previous planning cycles.

8. In order to guard against shortfalls of planned renewable energy deliveries, utilities should provide in their RPS planning for procurement greater than the annual IPT required to reach the goal that 20% of their retail sales of energy be from eligible renewable resources by 2010.

9. Beginning in 2006, utilities' long-term planning for RPS compliance should be integrated with their general long-term procurement planning, in R.04-04-003 or its successor proceedings.

10. In integrating RPS planning with general procurement planning, utilities should specifically identify RPS planning components.

11. In order to begin more complete RPS planning, the utilities should, within 60 days of the mail date of this decision, supplement their current filings as follows:


a. PG&E must include:


c. SDG&E must include:

12. In order for RPS planning to move forward expeditiously, this decision should be effective today.

INTERIM ORDER

IT IS ORDERED that:

1. Not later than 60 days from the mailing date of this decision, Pacific Gas & Electric Company (PG&E) must serve and file a supplement to its long-term procurement plan for the Renewables Portfolio Standard (RPS) program, including at least the following elements:

2. Not later than 60 days from the mailing date of this decision, Southern California Edison Company (SCE) must serve and file a supplement to its long-term RPS procurement, including at least the following elements:

3. Not later than 60 days from the mailing date of this decision, San Diego Gas & Electric Company (SDG&E) must serve and file a supplement to its long-term RPS procurement, including at least the following elements:

4. The utilities' future long-term planning for RPS compliance shall be conducted as part of general procurement planning in Rulemaking 04-04-003 or its successor proceedings.

5. The utilities' future long-term plans for RPS compliance shall include specific and identifiable RPS planning components in general procurement planning documents, and shall address at least the following topics:

This order is effective today.

Dated October 6, 2005, at Los Angeles, California.

Commissioner Dian Grueneich recused herself
from this agenda item and was not part
of the quorum in its consideration.

18 In its initial comments, TURN also suggested, based on its RPS experience, that some proportion of contracts would not result in energy deliveries. 19 Green Power also suggests that the utilities use standardized categories for resource types. We will explore this suggestion in the context of the 2006 RPS procurement plans.

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