The state of California has long championed renewable energy development initiatives and consumption goals. California has taken the lead in pushing the frontiers of policies to regulate and abate emissions of greenhouse gases (GHG) to combat global climate change, as embodied by the Global Warming Solutions Act of 2006, commonly referred to as Assembly Bill 32 (AB 32). Thus, it is not surprising that California has enacted one of the nation’s most ambitious renewable portfolio standards (RPS) programs. As described in the September 2008 issue of the Hunton & Williams Renewable Energy Quarterly survey of state RPS programs, California currently requires many electric utilities and providers to increase procurement from eligible renewable energy resources by at least 1% of their retail sales annually, until they reach 20% by 2010. In a bid to further raise the bar, on November 17, 2008, Governor Arnold Schwarzenegger signed Executive Order S-14-08, establishing a 33% RPS goal by 2020, a target backed by both the California Energy Commission (CEC) and the California Public Utilities Commission (CPUC), which jointly implement the state’s RPS program, as well as the California Air Resources Board, which is the lead agency overseeing AB 32 implementation.  

What has been surprising to some observers is that, unlike many other states that have enacted RPS programs, California currently has no functioning secondary market for the sale of unbundled and/or tradable renewable energy credits to satisfy its RPS requirements. With the CPUC’s December 2008 release of a draft decision and order, it appears things are about to change. This article provides a brief overview of renewable energy credits (RECs), their slow evolution and interaction with voluntary GHG emission trading markets and evolving GHG emission regulatory regimes in California, and recent developments governing the use of tradable RECs to satisfy California RPS compliance obligations.  

“Unbundled” and “Tradable” RECs in the Context of California’s RPS Program  

RECs, sometimes referred to as green tags, green credits, green tickets or renewable certificates, represent the renewable attributes of electricity generated from renewable sources, and potentially other “green” environmental-related attributes associated with its generation, as a separate commodity from the energy itself. RECs are generally characterized as either “bundled” or “unbundled”. Bundled RECs are sold together with, and undistinguishable from, the underlying renewable energy, while unbundled RECs are sold separately from the underlying energy. The CPUC, however, has made a further distinction between unbundled RECs and tradable RECs. Once unbundled, the REC may be delivered by the renewable generator to one California RPS obligated entity while the underlying energy may be delivered to another entity. Once the REC is unbundled however, the REC cannot be further traded or resold to third parties. Allowing greater flexibility, a tradable REC market similarly “unbundles” the REC from the underlying energy but permits the initial sale to any third party purchaser and subsequent resale after the initial purchase. The market rules proposed by the CPUC establish an open compliance market for tradable RECs (TRECs) without restriction on market participants.  

Development of TREC Attributes and Interplay with California’s AB 32 GHG Regulatory Regime  

In September 2002, California Senate Bill 1078 created the state’s RPS program by requiring many electric utilities and providers to increase procurement from eligible renewable energy resources by at least 1% of their retail sales annually, until they reach 20% by 2017. An acceleration of the program deadline to 2010 was first promulgated in the state’s 2003 Energy Action Plan I. Ultimately, California Senate Bill 107 (SB 107), passed in 2006 and effective January 1, 2007, codified the 2010 RPS compliance deadline and, for the first time, generally defined RECs for purposes of RPS compliance in California as including “all renewable and environmental attributes associated with the production of electricity from the eligible renewable energy resource.” However, although SB 107 established the minimum characteristics for RECs and authorized the potential use of TRECs, it remained unclear what was included in “all environmental attributes” and the decision whether to authorize use of TRECs was left to the discretion of the CPUC. Significant work remained on the CPUC’s environmental plate.  

During this same period California lawmakers were also wrestling with climate change policy via GHG emissions, commonly thought to be the major culprit of global warming. Enacted in 2006, AB 32 established the framework for a comprehensive program of regulatory and market mechanisms to achieve quantifiable GHG emissions reductions. The enactment of AB 32, and subsequent implementation of a GHG cap-and-trade program thereunder, necessitated a clarification by the CPUC of its prior REC definition as it pertains to GHG emissions.  

On August 21, 2008, in Decision 08-08-028, the CPUC again declined to determine whether to allow use of TRECs for RPS compliance obligations but did revisit its REC definition in connection with AB 32 and GHG emissions. The CPUC thought it clear that “all renewable and environmental attributes associated with the production of electricity from the eligible renewable energy resource” inherently included low or no pollution-emissions attributes from the renewable generation itself and the independence from use of fossil fuels generation, but debated whether to also include the benefit of avoided emissions of GHG resulting from a reduction of fossil-fueled generation elsewhere in the power grid. Ultimately, the CPUC determined that RECs include all GHG-avoided emissions attributes and would not be subject to double counting under dueling regulatory schemes. Once a REC is used for RPS compliance purposes and is retired in the Western Renewable Energy Generation Information System (WREGIS), it cannot also be used as a GHG emissions offset under AB 32’s cap-and-trade compliance regulations. Likewise, if a REC is retired due to its use as a GHG emissions offset pursuant to AB 32, then the entire bundle of attributes is retired for that purpose and cannot also be used for RPS compliance obligations.  

With a clearer understanding of REC attributes and their interplay with AB 32, the CPUC recently turned to the longawaited question of whether to authorize a TREC regime for RPS compliance purposes in California. On October 29, 2008 (and revised on December 18, 2008), CPUC administrative law judge Anne Simon issued a draft decision authorizing use of TRECs to comply with the state’s RPS program and outlining the structure and rules for a TREC market and for the integration of TRECs into the RPS compliance program.

Proposed California TREC Compliance Market Rules

As with any new regulatory program the devil is in the details. REC markets are distinguished by the myriad of choices regulators make. By necessity this article is limited to reviewing the results of an important handful of these choices, namely: which RECs are eligible; who is allowed to participate; whether to apply price controls; whether RECs may be banked for future use; and the degree to which standard terms and conditions are required in REC purchase contracts.  

  1. REC Eligibility

Although California RPS-obligated entities currently satisfy RPS compliance obligations via bundled RECs, the CPUC’s proposed rules provide the added option of RPS compliance via TRECs. Such TRECs must be associated with RPS-eligible energy generated on or after January 1, 2008, and tracked in WREGIS. For bundled RECs, the rules allow unbundling from either (1) contracts currently delivering RPS-eligible energy or (2) contracts scheduled to deliver RPS-eligible energy in the future; each may be unbundled and traded separately from the associated energy in the market as TRECs (each subject to the exception). The two exceptions to the permissive “unbundling” of currently bundled RECs are those (1) RECs associated with RPS-eligible energy delivered under procurement contracts signed prior to 2005 with California RPS-obligated load-serving entities or publicly owned utilities and (2) RECs associated with RPS-eligible energy delivered under procurement contracts pursuant to the federal Public Utility Regulatory Policies Act of 1978 with qualifying facilities signed after January 1, 2005.  

  1. Participatory Restrictions

Who may participate in a market significantly affects how it functions. In allowing non-RPS-obligated third-party participants, including brokers and financial institutions, voluntary markets expand the number of buyers and sellers involved in the market. This results in not only lower trading costs for all market participants but also encourages renewable energy development by providing renewable developers the flexibility and incentives inherent in a larger pool of potential buyers. Furthermore, a large number of participants limits the ability of any one participant to leverage power to secure lower prices or corner the market. The proposed rules recognize the benefits of maximizing market participation and place no restrictions on who may participate in the California TREC market (except that market participants must satisfy all requirements established by WREGIS).  

  1. Price Controls

California’s quickly approaching 2010 RPS compliance deadline and a constrained supply of RECs each place short-term upward pressure on REC prices as the deadline approaches. Because the RPS statute allows RPS-obligated entities to recover in their rates the costs associated with purchasing RECs, the CPUC is forced to determine how much is too much for ratepayers to pay for RECs and RPS compliance. Price controls, however, distort natural supplyand- demand equilibriums in a market. In balancing the potential burdens placed on ratepayers against a transparent and efficient market, the proposed rules institute a temporary price cap of $50 per TREC, an amount equal to the penalty RPS-obligated entities face for failure to meet RPS compliance obligations. This price cap, unless terminated earlier by the CPUC, expires upon the earlier to occur of (1) when all required entities have achieved the 20% RPS compliance goal or (2) January 1, 2012.  

  1. Time Restrictions

Deciding when a REC may be used, relative to its date of creation (or the compliance period in which it is created), is a key element of any REC market. Banking allows an entity to apply RECs acquired in a given compliance period in excess of their RPS compliance obligations in that period to future compliance periods. Excess RECs may be purchased when they are perceived at low cost and applied toward compliance obligations in perceived high-cost periods. This tends to smooth price swings in the market as timing is no longer tightly linked between generation and compliance. Excessively long banking periods, however, may create opportunities to game the market and compound boom-tobust cycles of renewable energy development as banked RECs compete with new renewable generation. Limiting banking periods also maintains market liquidity by giving holders of excess RECs a strong incentive to sell prior to the end of the banking period. The proposed rules allow banking and require RPS-obligated entities wishing to use TRECs for RPS compliance obligations to retire TRECs in WREGIS within three compliance years (including the compliance year in which they were created). After TRECs are retired within WREGIS they may be banked indefinitely for RPS compliance purposes.  

  1. Purchase Contract Requirements

Although the drafting of contract language is largely left to market participants, the rules require each contract for the sale of both bundled RECs and TRECs to include nonmodifiable standard terms and conditions. TREC purchase agreements must contain three standard terms and conditions: (1) a REC definition, (2) WREGIS tracking requirement and (3) CPUC approval for utility contracts. Bundled REC purchase agreements must include only the first two requirements — a REC definition and WREGIS tracking requirement. As drafted by the CPUC, the standard terms and conditions for REC purchase agreements are as follows:  

  1. Seller and, if applicable, its successors, represents and warrants that throughout the Delivery Term of this Agreement the renewable energy credits transferred to Buyer conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation. To the extent a change in law occurs after the execution of this Agreement that causes this representation and warranty to be materially false or misleading, it shall not be an Event of Default if Seller has used commercially reasonable efforts to comply with such change in law.  
  2. Seller warrants that all necessary steps have been taken to allow the renewable energy credits transferred to Buyer to be tracked in the Western Renewable Energy Generation Information System.  
  3. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which contains the following terms:  
  1. approves this Agreement in its entirety, including payments to be made by the Buyer, subject to CPUC review of the Buyer’s administration of the Agreement; and
  2. finds that any procurement pursuant to this Agreement is procurement of renewable energy credits that conform to the definition and attributes required for compliance with the California Renewables Portfolio Standard, as set forth in California Public Utilities Commission Decision 08-08-028, and as may be modified by subsequent decision of the California Public Utilities Commission or by subsequent legislation, for purposes of determining Buyer’s compliance with any obligation that it may have to procure eligible renewable energy resources pursuant to the California Renewables Portfolio Standard (Public Utilities Code Section 399.11 et seq.), Decision 03-06-071, or other applicable law.  

CPUC Approval will be deemed to have occurred on the date that a CPUC decision containing such findings becomes final and nonappealable.  

Conclusion  

A transparent and well-regulated TREC market provides California’s RPS-obligated entities the greatest flexibility and therefore best chance of satisfying current 2010 RPS obligations while simultaneously stimulating efficient development of further needed renewable generation to achieve the state’s ambitious 33% target by 2020. Given the enhanced role of California policy makers in key federal agencies influential in shaping the Obama administration’s energy and climate policies, as well as key congressional committees critical to adopting and implementing such policies, the state’s proposed authorization of TRECs as a means of complying with RPS standards and its recent clarification of important REC attributes relevant to the interplay between RPS and climate policy suggest that California is poised to play an increasingly influential role in shaping and, ultimately, implementing analogous federal policy beyond its borders.