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California Public Utilities Commission Decision Allows Tradable Renewable Energy Credits

Mar 17, 2010 - Stoel Rives, LLP

The decision had been a long time in coming. The legislature had authorized the CPUC to allow the use of TRECS in 2006. On October 29, 2008, the CPUC issued its first proposed decision authorizing the use of TRECs. Since that date, the CPUC had been considering various proposed decisions that would have permitted the use of TRECs until finally adopting the final decision on March 11.

TRECs are renewable energy credits that can be traded separate and apart from the energy associated with their creation. Allowing TRECs, though ostensibly a significant policy statement, was a actually a relatively small step, given the flexible requirements adopted by the California Energy Commission (“CEC”) for determining whether generation should be certified as meeting California’s RPS. Under California law, the CEC, not the CPUC, is tasked with certifying whether generation is an eligible renewable resource that can be used to meet the California RPS. Under California’s RPS statute, power must not only be generated using certain defined renewable resources (wind, solar, biomass, small hydro, geothermal), it also must be delivered to California. The CEC, however, allowed the power delivered to California to be generated at a different time and in a different location than the power associated with the renewable energy credits ("RECs"). This allowed intermittent generation from outside California to firm and shape the power delivered to California; in a number of transactions, utilities bought both the RECs and the power from a renewable generator, then sold the power either back to the generator or to another party, retaining the RECs. It then delivered power to California from a different source, allowing it to count the RECs toward its RPS. Under the CPUC’s decision, the utility can simply purchase the TRECs from the renewable generator, without having to purchase the associated power. The delivery requirement still remains, however. The RECs must be associated with the delivery of some power to California in order to be counted toward a utility’s RPS requirement.

A much more contentious issue in the proceedings was whether any limits should be imposed on TRECs. A number of parties contended that the flexible delivery requirements adopted by the CEC allowed utilities to import brown power into California under the guise of renewable generation. But the CPUC lacked the jurisdiction to change those delivery requirements. To address the issue, however, the CPUC sought to define certain transactions as unbundled transactions—transactions that in the view of the CPUC did not result in the importation of additional renewable generation into California. Those unbundled or TREC transactions would be subject to a cap. The CPUC struggled, however, to distinguish between transactions it viewed as “unbundled” and those that would not be subject to the cap.

The California legislature also got into the act. In several bills that would have raised California’s RPS from 20% to 33%, the California legislature would have required that renewable power generated outside California had to be delivered to California at the same time and from the same source as the energy associated with the RECs to count toward California’s RPS. If those delivery requirements were not met, then the RECs associated with that power could still be counted toward California’s RPS (as long as the generation was located within the Western Electric Coordinating Council, or WECC), but the transactions could only be used to meet 25% of a utility’s RPS requirement. Although the bills passed the California legislature, they were vetoed by the governor, in large part due to the limitations imposed on out-of-state renewable generators.

After the governor’s veto, the CPUC again took up the issue, eventually issuing a proposed decision that would have simply categorized all out-of-state transactions as unbundled transactions, and limiting those unbundled transactions to 40% of a utility’s RPS requirement. The decision adopted last week takes a more measured approach. RECs associated with power dynamically transferred to California will be considered a bundled transaction and will not be subject to any limit. Transactions involving a generator that has its first point of interconnection with a California balancing authority are also considered bundled transactions not subject to the cap. The decision also recognizes that certain transactions with firm transmission arrangements might also qualify as bundled transactions. Although the cap currently will apply to those transactions, the CPUC will consider in the future whether to allow those transactions, or some subset of those transactions, to be considered bundled transactions not subject to the cap.

For contracts that are already in existence, if the transaction would be considered unbundled under the rules adopted in the decision, future deliveries under those contracts will be counted toward the cap. However, if those pre-existing contracts cause a utility to exceed the cap, all of those deliveries will still be permitted to count toward a utility’s RPS.

The cap could ultimately put significant restrictions on the use of out-of-state generation to meet California’s RPS. It remains to be seen, however, whether and when the utilities will reach the 25% cap, and whether the CPUC will take action to extend the cap beyond 2011. The California legislature also continues to consider these issues in Senate Bill 722.

You can view the CPUC decision here.  For more information, please contact:

Steven Hall at (503) 294-9625 or
Seth Hilton at (916) 319-4749 or
Howard Susman at (858) 794-4111 or


Updated: 2003/07/28