In a decision announced late last week and issued Tuesday, March 16, 2010, the California Public Utilities Commission (CPUC) authorized the use of tradable renewable energy credits (TRECs) for use in the California Renewables Portfolio Standard (RPS) program. The program currently requires CPUC-regulated entities to obtain 20 percent of their retail sales from renewable energy sources as of 2010. As explained below, the CPUC decision allows TRECs to increase the possible sources of RPS supply while imposing restrictions on the amount of out-of-state power which may qualify as RPS-eligible. Thus, the overall consequences on the California RPS market are unclear.

RECs are a certificate of proof that one unit of renewable energy has been generated and provide an audit trail demonstrating that California electricity sellers have procured sufficient megawatt hours (MWh) to satisfy their respective annual RPS procurement obligations. Allowing the use of TRECs is meant to provide more flexibility for CPUC-regulated entities to comply with California RPS mandates.

The CPUC decision limits the three largest California investor-owned utility's (IOU) use of TRECs for RPS compliance to not more than 25 percent of the IOU’s annual RPS MWh purchases. In addition, all IOUs in California may not purchase a TREC at more than an interim price cap of $50. These limitations do not apply to other CPUC-regulated entities, and are slated to automatically sunset at the end of 2011. However, the CPUC retains the option to extend or modify these limitations.

Previously, for RPS compliance CPUC-regulated entities were required to procure exclusively "bundled" RPS contracts, (i.e., a transaction in which the CPUC-regulated entity purchases both the physical energy and RECs). The CPUC decision will allow CPUC-regulated entities to procure RECs separate from its associated energy. On its face, this additional flexibility for CPUC-regulated entities should provide incentives for the development of RPS power by offering additional revenue streams potentially available to RPS project developers both in state and out of state.

However, the CPUC decision also effectively reclassifies several categories of transactions involving out-of-state generation. Under the RPS regulations promulgated by the California Energy Commission (CEC), these transactions have been determined to be “bundled” RPS transactions. These reclassified transactions will now be subject to the 25 percent cap on TREC purchases. Effectively, the CPUC decision would classify as a REC-only transaction any transaction with an out-of-state developer that does not have either (i) its first point of interconnection with the California ISO, or (ii) its RPS-eligible energy dynamically transferred into the California ISO.

The implementing RPS legislation vests the CEC with the exclusive jurisdiction to determine the RPS eligibility of out-of-state generation. Many parties accordingly asserted that the legislation and principles of “regulatory certainty” dictate that the CPUC should accept the CEC’s “guidelines” regarding the RPS eligibility of out-of-state power. However, the CPUC maintained that “its long-standing authority over all aspects of utilities’ RPS procurement” as well as its “authority and discretion over the conditions for the use of TRECs for RPS compliance by all [Load Serving Entities]” authorizes the CPUC to also determine whether an agreement involves a “bundled” or a “TREC-only” transaction.

Therefore, the status under the CPUC decision of current and contemplated transactions by out-of-state RPS developers that involve firming and shaping, a buy-back of energy, or some other contract structure previously approved by the CEC as “bundled” and thus RPS-eligible, is uncertain. Given that if these projects are ultimately determined to be TREC-only transactions they will be subject to the 25 percent cap, one effect of the CPUC decision may be to preclude at least some out-of-state projects from participation in the California RPS market.

The scope of these possible market consequences of the decision’s restrictions on out-of-state RPS power is unclear. The CPUC decision provides no information regarding how much of any IOU’s 25 percent cap on TRECs may already be subscribed. It also fails to consider how the limitations on RPS eligible supply would impact prices (i.e., normally, governmental restrictions on supply serve to increase prices; yet, California needs out-of-state power to meet its ambitious RPS goals).

The CPUC decision strongly suggests, but defers presently ruling, that contracts with generators outside of California who deliver their RPS power into California through the use of “firm transmission” arrangements should also qualify as “bundled” RPS-eligible power. The CPUC decision directs its staff to conduct workshops to elicit more facts regarding firm transmission arrangements, and ultimately determine a procedure to consider whether an out-of-state RPS generator delivering power into California with firm transmission capacity should also qualify as a “bundled” RPS transaction. Developers may wish to participate in these workshops.