All Party Meeting Concerning California's 2011 RPS Procurement

My partner Seth Hilton attended last Friday's all-party meeting on California's 2011 RPS procurement and prepared the following update:

On February 11, 2011, California Public Utilities Commission (CPUC) Administrative Law Judge Burton Mattson issued a Proposed Decision (PD) conditionally accepting the 2011 Renewables Portfolio Standard (RPS) Procurement Plans for Southern California Edison (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas and Electric Company (SDG&E). If adopted, the Decision would set a schedule for the utilities’ 2011 RPS solicitation. The PD was on the agenda for the CPUC’s March 24, 2011 business meeting, but was held at Commissioner Florio’s request until the April 14 meeting.

On March 25, Commissioner Florio held a well-attended all-party meeting on the PD. Among the issues raised by Commissioner Florio was where California’s investor-owned utilities stood relative to the current RPS procurement targets and the targets contained in pending legislation (SBX1-2), and whether a 2011 RPS solicitation was necessary.

 

All three investor-owned utilities—PG&E, SCE and SDG&E—stated that holding a 2011 RPS solicitation would be prudent. PG&E stated that it was on track to meet the current 20% RPS this year and through 2013. However, future compliance, especially with the higher procurement targets under SBX1-2, is dependent on several large projects that are scheduled to come online in the next few years. Any delay or failure of those projects would require PG&E to procure additional resources to get to the 2016 target under SBX1-2, and therefore holding a solicitation this year made sense. 

 

According to SCE, a 2011 solicitation would be prudent for a number of reasons, not only to assist SCE to reach the goals in SBX1-2. SCE noted that a solicitation would be beneficial for current contract administration by setting the price for any replacement power and that annual RPS solicitations were important for maintaining a vigorous RPS market. 

 

SDG&E stated that it too was not done with procurement and would need further procurement to comply with the 2016 goal under SBX1-2. 

 

Other parties also advocated in favor of a 2011 solicitation, with TURN noting that there may be some bargains available to the utilities due to the fact that no RPS solicitation was held last year and that competition would be fairly robust for RPS contracts. 

 

The Division of Ratepayer Advocates was one of the few dissenters (along with CARE), arguing that because a new cost containment mechanism would apply under SBX1-2, the CPUC should consider waiting until it had addressed cost containment before commencing a new RPS solicitation. 

 

The parties also discussed various issues to be resolved by the PD, including how economic curtailment should be handled in the pro forma RPS contract, congestion adders and integration cost adders. As currently drafted, the PD would require all three utilities to amend their pro forma agreements to use the economic curtailment provisions proposed by PG&E, which would allow utilities to economically curtail projects up to five percent of the project’s expected annual generation, for which PG&E would pay the project the full contract price but would not reimburse the project for any lost production tax credits. The California Wind Energy Association noted that although it supported PG&E’s proposal, the proposal should be amended to make it clear that the cap applies to any economic curtailment caused by the utility, even if the curtailment was in fact ordered by the California Independent System Operator, and to provide for the payment of any lost production tax credits as well.

 

As for congestion adders, the PD would require the utilities to consider congestion costs when evaluating projects and order the utilities to release congestion cost information in their 2012 and future plans, so that project developers will be fully informed when making siting decisions.

 

Finally, the PD declined to allow the use of integration cost adders when evaluating bids, despite both SCE’s and SDG&E’s requests that they be permitted to do so. 

 

If you have any further questions on this all-party meeting or any other California energy regulatory issue, please contact:

Seth Hilton at (916) 319-4749 or sdhilton@stoel.com

Bill Holmes at (503) 294-9207 or whholmes@stoel.com

Jennifer Martin at (503) 294-9852 or jhmartin@stoel.com

The California Public Utilities Commission Lifts Moratorium on Approval of Tradable Renewable Energy Credit Transactions; Limits Use of Out-of-State Generation for California RPS Compliance

A legal update from our colleague Seth Hilton:

Ten months after initially authorizing the use of tradable renewable energy credits (TRECs), the California Public Utilities Commission (CPUC) today lifted its moratorium on approval of TREC transactions. CPUC Dec. 11-01-025. Today’s decision, however, retains restrictions on TREC transactions that could limit the amount of out-of-state generation that the three major investor-owned utilities can use to meet their California Renewable Portfolio Standard (RPS) obligations.

At its March 11, 2010 meeting, the CPUC authorized the use of TRECs for compliance with the RPS, subject to certain limitations. CPUC Dec. 10-03-021 (March Decision). Among the limitations that the March Decision imposed was a cap limiting the use of TRECs for RPS compliance for the largest investor-owned utilities (Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric) to 25% of their annual RPS compliance obligations. That cap was to remain in place until December 31, 2011, when the CPUC would consider modifying or removing that limitation. The March Decision also imposed a price cap of $50 per TREC. The price cap was also set to expire on December 31, 2011.

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