California Utilities Poised to Commence Renewable Energy Procurement

more+
less-

At its November 14, 2013 Commission meeting, the California Public Utilities Commission (the “CPUC”) conditionally accepted the renewables portfolio standard (“RPS”) procurement plans filed by various California utilities. With this decision, California’s utilities — in particular Pacific Gas & Electric (“PG&E”), Southern California Edison (“SCE”) and San Diego Gas & Electric (“SDG&E”) — are poised to start their 2013 renewable procurement programs. Utilities will be refiling their final procurement plans by December 2, 2013, and should be issuing their Request for Offers (“RFOs”) in mid-to-late December (the decision precludes the utilities from filing before December 9 but offers them some flexibility to issue the RFOs after that date). [1]  Shortlists of bidders must be submitted on or around March 14, 2014 (within 120 days after the decision is mailed).

In addition to defining the schedule for the 2013 procurement plan, the CPUC addressed a number of important issues concerning the plans originally filed by the major three utilities. These include contract terms and negotiations, bidding requirements and the process of evaluating bids, all of which will be critically important to the RFO participants.

Contract Terms and Negotiations
Utility contracts with renewable generators have a complex history which has historically restricted the amount of negotiation that is permissible. With the market maturing, the CPUC appears to be relaxing this restriction. Pro forma contracts were included in the utility filings and parties raised a number of issues regarding those contracts. While the CPUC addressed some of the issues, the CPUC expressed a general preference that the parties negotiate terms and have the contracts reviewed “in their totality” for approval. The specific contract issues the CPUC addressed are discussed below.

Shortlist Exclusivity. One of the more significant changes to the bidding process is removing the restriction that shortlisted bidders negotiate only with one utility. With the increased competitiveness of the renewable industry and the utilities typically shortlisting more bidders than they intend to contract with, the CPUC is permitting shortlisted bidders to negotiate with one or more utilities.  

Green Attributes. Historically, the RPS contracts had a non-modifiable definition of the Green Attributes that had to be transferred to the utilities along with the energy. The CPUC found that the existing definition was outdated and proposed a new definition. The CPUC also stated that even this new definition may not be appropriate in all circumstances and has permitted parties to modify this term in negotiations. The ultimate definition is still subject to various requirements designed to ensure the utilities receive the appropriate environmental benefits associated with renewable energy.

Integration Cost Adders. The cost of integrating intermittent energy resources is generally an issue raised in the context of evaluating bids. PG&E, however, proposed that if the CPUC did not adopt an integration cost adder in the bid evaluation process then PG&E would require that sellers bear all integration costs. The CPUC rejected PG&E’s proposal noting that integration costs are still an evolving issue and are being addressed in other ways, both by the CPUC and the California Independent System Operator (“CAISO”). 

Time-of-Delivery Factors. Time-of-Delivery (“TOD”) factors adjust the price of electricity paid to the seller based on the time of day that the seller delivers the contracted energy. Higher prices are paid for energy delivered on-peak and lower prices paid off-peak. The CPUC has maintained its policy of permitting utilities to develop their own TOD factors. While different than the 2012 TOD factors, the utilities’ proposed 2013 TOD factors were found to be reasonable and appropriate for use in the 2013 procurement process.

Reduced Payments for Excess Energy. The CPUC authorized the utilities to reduce — or eliminate — payments for excess energy. SDG&E and SCE both proposed to reduce the energy payments to zero when energy delivered in a given settlement period is more than 110% of the energy originally expected. All three utilities proposed to pay sellers 75% of the energy price if the energy delivered exceeds 115% of the expected annual production and SDG&E proposed to pay this same price if deliveries in any TOD period exceed 115% of the expected amount. These proposals were all approved and will be incorporated into the final procurement plans.

Curtailment and Loss of Production Tax Credits. SDG&E and SCE proposed a limited ability to curtail seller output, while PG&E proposed that it be able to curtail the full output of any facility. SDG&E’s proposal (which is the same as that used in 2012) allows SDG&E to curtail up to 5% of the expected annual generation and SCE’s proposal allows it to curtail a limited number of hours without compensation and to pay for curtailment during on-peak hours (except for curtailment ordered by the CAISO, the relevant transmission provider or resulting from an emergency). The CPUC approved the curtailment provisions proposed by SDG&E and SCE and rejected PG&E’s proposal. PG&E will need to propose alternate curtailment options in its final procurement plan. The CPUC retained its existing policy of not requiring utilities to compensate, or prohibiting utilities from compensating, sellers for the loss of production tax credits associated with curtailment.

Responsibility for Negative Prices. SCE proposed requiring that sellers be responsible for any negative pricing. Such pricing can occur in congested transmission areas and results in generators being paid to reduce output. The CPUC rejected this proposal.

Bilateral Contracts. In 2012, SCE was prohibited from entering into contracts that resulted from bilateral negotiations rather than an RFO process. This restriction was imposed because SCE did not conduct an RFO in the 2012 procurement plan. Given that SCE will be conducting an RFO under the 2013 plan, SCE is again permitted to negotiate bilateral agreements.

Bidding Requirements
Minimum Project Size.
The CPUC retained the existing 1.5 MW minimum project size for participating in the RPS program. However, the utilities are permitted to give preferences to larger projects.

Resource Specific Preferences. All three utilities included varying resource preferences relating to location, delivery start dates, contract term and portfolio content. There is no apparent restriction on what resources may bid into the RFO but the utilities are permitted to give preferences to resources that fit their particular needs.

Interconnection Status. The CPUC modified the requirements related to the interconnection status of bidders. Historically, bidders were only required to have completed the CAISO Generation Interconnection Procedures (“GIP”) Phase I study to be eligible to participate in the RFO process. Now, bidders must have completed the CAISO Generation Interconnection and Deliverability Procedures or the CAISO GIP Phase II studies, or equivalent, where the bidder is not connected to the CAISO grid or is not exempt from these requirements (in particular with respect to existing resources).

Project Development Security. PG&E proposed to substantially increase the project development security to $300/kW for certain projects in an effort to provide a greater incentive to achieve delivery on time and to limit bidders to those that are more viable and have more experienced counterparties. The CPUC rejected this request and required PG&E to include security requirements more in line with SCE’s security of $90/kW for baseload and $60/kW for intermittent resources and SDG&E’s security of $10/MWh.

Bid Evaluation
Imperial Valley Connections.
Several parties supported requiring the utilities to take actions to further support the use of the Sunrise Powerlink Transmission Project. The CPUC rejected this request, finding that there is (at least currently) ample evidence that this project will be adequately (if not fully) utilized without such incentives.

Existing Facilities/Expiring Contracts. No preference is being given to existing facilities or those facilities that have expiring contracts. According to the CPUC, these sellers will need, and are encouraged, to participate in the RFO process before the utilities fill their mandates, and any sellers doing so will receive sufficient benefits in the bid evaluation process with respect to project viability and interconnection scoring.

Integration Cost Adders. The CPUC declined to adopt any bid adjustments based on the expected integration costs of intermittent resources. As noted above, this issue is being addressed in other ways and will not be included in the RFO process unless and until it is appropriate based on the results of other proceedings.

Third-Party Resource Adequacy. Bidders are not permitted to rely on third-party providers to satisfy any resource adequacy requirements.

Contract Term. PG&E requested to include its Portfolio-Adjusted Valuation Methodology in its procurement process. The CPUC approved this request, but required PG&E to remove from this methodology an adjustment that gave preference to short-term contracts.

Congestion Adder. SCE proposed an adjustment to its “Least-Cost/Best-Fit” methodology that included an adder related to congestion charges for energy-only projects. While the issue of additional transmission costs associated with energy-only products remains open, the CPUC did approve SCE’s request.
With this decision, we can expect a significant amount of activity over the next three months with respect to renewable procurement in California. Additional details will be available in early December.

Notes:
[1] These dates assume the decision is mailed on November 14th. The decision requires final RPS procurement plans to be filed 14 days after the decision is made and RFOs issued no sooner than 24 days after the decision is made.