The California Public Utilities Commission recently made another step that will bring the state's utilities closer to achieving their Renewable Portfolio Standard goals. On December 23, 2009 the CPUC issued a Revised Proposed Decision tentatively authorizing the use of tradable renewable energy credits (TRECs) and unbundled REC contracts for RPS compliance. While not a final decision, implementation of this ruling would let California's utilities meet up to 40 percent of their annual RPS compliance targets with TRECs. The near term impact of this decision is likely minimal. In the long-term the ability to use TRECs could further stimulate the development and installation of renewable energy projects in California and other Western Electricity Coordinating Council states.

Prior to this decision, California's utilities could only meet RPS obligations through the procurement of bundled contracts for RECs and electricity under power purchase agreements or through the construction of utility owned generation. A REC represents the environmental attributes of one MWh of renewable generation.  As I discussed last week, this favored the development of multi-hundred megawatt renewable energy projects within California. Currently, 7 GW of new, RPS-eligible renewable capacity has received CPUC approval and is under development in the state, with an additional 4.8 GW of capacity awaiting CPUC approval.

The advent of TRECs and unbundled REC contracts would bolster the CPUC's new emphasis on smaller projects that face fewer development hurdles. It would also provide an opportunity for customer-sided distributed generation projects to access an additional revenue stream, further defraying the costs for homeowners to install DG PV systems. Currently, DG systems (with the limited exception of projects less than 3 MW participating in California's standard offer feed-in tariff) are not considered RPS compliant by the California Energy Commission.

However, in the RPS Eligibility Guidebook, the CEC notes it "will not certify distributed generation facilities as RPS-eligible unless the CPUC authorizes tradable RECs". If the TREC decision is approved, California may see a surge in the number of residential and commercial DG PV projects constructed since the project owners could register their RECs with the Western Renewable Energy Generation Information System and receive revenue from utility purchases of TRECs.

The TREC program would be limited in scope during its first 24 months of operation. Under the proposed decision, utilities may only use TRECs for 40 percent of their annual RPS compliance and the TRECs themselves would be subject to a price cap of $50/MWh. This price cap is equal to the compliance penalties the CPUC assesses to utilities who fail to meet annual RPS goals. The 40 percent limitation was implemented to "maximize the benefits of reducing California's fossil fuel use and gain the attendant benefits of reduction in air pollution, improvement in public health, and reduction in energy price volatility" consistent with the development of in-state renewable capacity, according to the CPUC. Otherwise, the CPUC argues California's utilities could purchase TRECs off WREGIS from projects in any WECC state, thus depriving developers in California of the incentive to develop in-state projects.

Comments on the proposed decision are due at the end of January, with implementation expected to begin on March 1, 2010. In the first years of the program, the CPUC - as well as most utilities, ratepayer advocates, non-profits, and developers who have provided comments to CPUC - acknowledge that demand for TRECs will exceed their available supply. This is largely because all RPS-eligible projects under development already have PPAs that bundle RECs and electricity. Additionally, a provision in the proposed decision would prevent utilities from unbundling RECs from PPAs with facilities under development for the first three years of operation.

In the absence of a price cap on TRECs, the CPUC acknowledges a limited supply would have the same upward impact on TREC prices as a fast approaching compliance deadline has on the price of bundled RECs. Additionally, all things being equal, we can assume a utility would much rather purchase a high-priced TREC and pass the cost on to is customers than force its shareholders to pay a $50/MWh compliance penalty. The CPUC authorized the $50/MWh price cap on TRECs to avoid this situation.

The major long-term impact of the TREC decision is the added flexibility it gives California's utilities in meeting their RPS goals. It may also stimulate additional project development in states where demand for RECs is low or where utilities have made sufficient progress towards their RPS goals, like Nevada or Colorado. Finally, the TREC program could provide an additional source of growth for California's customer-sided DG PV market because owners of these systems could register their RECs with WREGIS and receive revenue from utility purchases. Ultimately, an unlimited TREC market in California could provide fluidity to the notoriously lumpy market for large-scale project development. Incentivizing developers to construct renewable energy projects without bundled contracts may provide a market opening outside the RPS RFP process, leading potentially to a development market that is similar to the one that exists for traditional generation.