California Public Utilities Commission Adopts Rules for Tradable Renewable Energy Credits

April 21, 2010

On March 16, 2010, the California Public Utilities Commission issued its long-awaited “TREC Decision”: Decision Authorizing Renewable Energy Credits for Compliance with the California Renewables Portfolio Standard (D.10-03-021). The decision lays out key ground rules for tradable renewable energy credits (TRECs).

The Renewables Portfolio Standard (RPS) requires utilities “to attain a target of generating 20 percent of total retail sales of electricity in California from eligible renewable energy resources by December 31, 2010.” In 2006 the legislature authorized the Public Utilities Commission to allow the use of TRECs to satisfy RPS targets. Since then, the commission has been working on implementing a TREC program.1

The Role of the Renewable Energy Credit in Meeting Renewable Energy Targets

A REC is a bundle of nearly all environmental attributes (greenhouse gas emissions reductions, renewable energy attributes, reductions in other pollutant emissions, etc.) associated with 1 MWh of RPS-eligible renewable power generation.

Prior to the TREC Decision, utilities could only satisfy RPS requirements through the purchase of renewable energy delivered to serve load in California and the RECs associated with that energy. The TREC Decision allows utilities to meet some of their RPS requirements via RECs traded independently of the underlying energy — that is, through TRECs — subject to numerous contingencies discussed in part below. 

California’s Three Largest Utilities May Not Use TRECs to Satisfy More Than 25 Percent of Their RPS Obligations

In the TREC Decision, the commission capped the use of TRECs by Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric at no more than 25 percent of each utility’s annual RPS procurement obligation. This limit expires on December 31, 2011, unless further action is taken by the commission.

The cap’s uncertain expiration date will make utility planning beyond 2011 more difficult. Further complicating the picture, numerous entities have sought rehearing and/or modification of the TREC Decision, suggesting there may be further changes to the cap.

Bundled RECs From Energy Capable of Serving California Load Do Not Count Against the 25 Percent Cap

Bundled transactions (which involve the sale of power and the associated REC together) will not count against the 25 percent cap. A transaction is bundled where either (1) the generator’s first point of interconnection with the grid is with a California balancing authority, or (2) the RPS-eligible energy is “dynamically transferred” to a California balancing authority.2 The decision calls for further study of whether a third class of transaction — contracts with eligible renewable resources supported by firm transmission arrangements — should also be classified as bundled.

REC-Only Transactions, Including Many Transactions Pre-Dating the TREC Decision, Do Count Against the 25 Percent Cap

“REC-only” transactions include either (a) contracts which expressly transfer only the REC and not the underlying energy, or (b) contracts which transfer both energy and RECs, but under which the power cannot serve California load. These definitions mean that many contracts that pre-date the TREC Decision will be classified as “REC-only” and will count against the 25 percent cap. It remains to be seen how much “headroom” the big three utilities have under the cap given their pre-existing long-term contracts that will be classified as REC-only.

In recognition of the possibility that load serving entities (LSEs) could end up with TRECs above the 25 percent cap, the commission permitted LSEs with bundled energy sources to opt to unbundle future RECs for sale, subject to certain restrictions. In addition, LSEs with excess RECs for current compliance may bank the RECs for trade or for future RPS compliance within three years.

RECs From Out-of-State Qualifying Facilities (“QFs”) May Be Used as TRECs for RPS Compliance

The TREC Decision clarifies that out-of-state QFs with contracts entered into pursuant to the Public Utility Regulatory Policies Act (“PURPA”) and executed after January 1, 2008, can be a source of TRECs, subject to certain conditions. In-state QFs with contracts pursuant to PURPA cannot be a source of TRECs.

REC-Only Contracts Are Subject to a Price Cap

The decision imposes a transitional price cap of $50/REC in REC-only contracts used for RPS compliance by all investor-owned utilities. This price cap expires on December 31, 2011, unless further action is taken by the commission.


The TREC decision reflects the ongoing debate over the role that imports will play in satisfying RPS targets, and the interrelated question of what the targets should be. We expect that the rapid evolution of RPS requirements is likely to continue. Stay tuned.

For more information on this alert, please contact the lawyers listed below:

Monica A. Schwebs, Of Counsel, 415.393.2575

1 While the TREC Decision permits use of unbundled RECs for RPS compliance purposes, it does not affect the California Energy Commission’s deliverability requirements. These requirements are statutory (Cal. Pub. Util. Code § 399.12(c); Cal. Pub. Res. Code § 25741.) and are further defined by a CEC guidebook, over which the CPUC has no authority. Neither does the Commission's TREC Decision authorize any wholesale power sales, whether associated with TRECs or not. A wholesale seller within or into California must obtain any required authority from the Federal Energy Regulatory Commission, in the form of QF status for a generator, market-based rate authority for entities deemed competitive by FERC, or other tariff-based authority for other sellers, such as traditional utilities and their affiliates.

2 “Dynamic transfer” encompasses “dynamic scheduling” and “pseudo-ties.” Notably, neither dynamic scheduling nor pseudo-tie arrangements have been implemented with intermittent renewable energy sources.

This article was originally published by Bingham McCutchen LLP.