Using Tradable Renewable Energy Credits in California

Using Tradable Renewable Energy Credits in California

March 11, 2011

A decision by the California Public Utilities Commission in January lets California utilities satisfy part of their 20%-by-2010 renewable procurement requirements by buying “unbundled” credits from renewable generators in other states.

Credits are “unbundled” if they are purchased separately without also buying electricity.

Before this decision, a utility could not use unbundled credits—called tradable renewable energy credits or TRECs—to fulfill renewable procurement requirements. A controversial March 2010 decision and a subsequent stay on the decision had left the ability to rely on renewable energy credits purchased out of state in doubt. Even with the January decision, the issue remains highly contentious and may not have been settled.

After nine years, the extent to which TRECs can be used in California and even what qualifies as a TREC remain under debate. The ultimate answers may differ for the 20%-by-2010 renewable portfolio standard or “RPS” and the 33%-by-2020 renewable electricity standard or “RES.”

Background

Investor-owned utilities and retail energy service providers in California are required to provide 20% of their electricity from renewable energy sources beginning in 2010, although flexible compliance rules in the RPS program effectively extend the compliance deadline to 2013. (A retail service provider is an entity that competes with investor-owned utilities to sell electricity to retail customers directly.)

The California Public Utilities Commission administers this 20%-by-2010 RPS program. The program has been underway since 2002 and is mostly well defined. The ability of utilities to use TRECs to meet their compliance obligations is among the few remaining aspects of the program that have not yet been finalized.

All California utilities, including retail service providers and public and municipal utilities not under CPUC jurisdiction, will be required to procure 33% of their electricity from renewable energy sources beginning in 2020. This 33%-by-2020 RES was approved by the California Air Resources Board in September 2010 and in many respects remains a work in progress. Notably, the authority for this program currently stems from an executive order issued by then-Governor Schwarzenegger; however, legislative efforts to enact a bill establishing a 33%-by-2020 renewable energy obligation continue. If a bill is passed, then the bill and its legislative requirements will supersede the executive order and the CARB regulatory framework.

A Tortured History

Parties have been asking the CPUC to authorize the use of TRECs for RPS compliance from the very earliest days of the RPS program, but the path toward establishing rules regarding use of TRECs has been tortured.

The CPUC initially considered the use of TRECs for RPS compliance as the parties were seeking, but fearing the issue would delay implementation of the RPS program, the CPUC decided to table the matter.

The CPUC subsequently revisited the issue in several proceedings and began focusing seriously on the TREC issue in 2006, when legislative activity on the matter also heated up. But once again the CPUC put off a decision to authorize the use of TRECs for RPS compliance, committing only to revisit the matter at a later date. Since that time, parties have held numerous workshops, filed briefs, and waited for the CPUC to act.

Finally, in March 2010, the CPUC issued a decision authorizing the use of TRECs for RPS compliance. However, rather than closing the issue, the March 2010 decision simply ignited more controversy.

TRECs Under the RPS

Before the March 2010 decision authorizing the use of TRECs, utilities and retail service providers could comply with their RPS requirements only through “bundled” contracts, in which physical energy and renewable energy credits were purchased in the same transaction.

The March 2010 decision expanded compliance options by allowing the use of unbundled TRECs for RPS compliance. It also allowed TRECs to be banked and used for RPS compliance for up to three years following the physical delivery of renewable energy to the grid. However, for the state’s three large IOUs for the years 2010 and 2011, the decision limited the use of TRECs to 25% of the utility’s annual RPS obligation. The CPUC also capped the price during these years at $50 per megawatt-hour for TRECs used for RPS compliance. (A subsequent decision extended these limitations to retail service providers.)

 The March 2010 decision sparked controversy among both utilities and renewable energy project developers primarily on account of the 25% TRECs limit combined with the expansive definition of a TREC transaction, which redefined some already approved bundled contracts as TREC contracts.

Under the decision, all transactions are defined as TREC transactions unless they include either (1) physical energy deliveries from a generator that has its first point of interconnection with a California balancing authority such as the California Independent System Operator or (2) energy deliveries that are dynamically transferred to a California balancing authority area.

Under this sweeping definition, contracts with out-of-state generators are nearly always considered TREC contracts, even if they include physical energy deliveries.

However, the CPUC left open the possibility that out-of-state transactions that include firm transmission arrangements, but not dynamic transfers to a California balancing authority, could be reclassified as bundled contracts since, prior to the March 2010 decision, such transactions had been considered bundled transactions.

The narrow definition of bundled contracts imposed by the March 2010 decision and the application of the definition to already-approved contracts limit additional out-of-state procurement.

The chart below, which was created by The Utility Reform Network, a consumer advocacy group, shows the utilities’ annual TREC procurement under the CPUC’s adopted definition. As shown, San Diego Gas & Electric has already exceeded the 25% TREC usage limit in nearly each year through 2020 under this definition. This means that SDG&E would be able to enter into new RPS contracts with out-of-state generators only under very narrow circumstances. (SDG&E would be allowed to use deliveries from contracts exceeding the TREC usage cap for RPS compliance as long as the contracts were approved before March 11, 2010.)

The other two utilities approach the 25% limit for much of the first half of the decade and would have the opportunity for significant new out-of-state procurement beginning only around 2016. The utilities objected to being hamstrung by these limitations since they restricted procurement options, and developers of out-of-state renewable projects objected to being pushed out of the California market.

IOU Renewable Procurement

Approved/Submitted TREC contracts as a fraction of expected RPS procurement targets

Prepared by Matt Freedman (TURN) using public data provided by the IOUs

As a result of this controversy, the CPUC stayed the March 2010 decision in May 2010 and placed a moratorium on approving contracts that would be classified according to that decision as TREC contracts. The CPUC and interested parties then spent an additional eight months debating the issue, resulting in no less than six revisions to the administrative law judge’s initial proposed decision as well as a competing proposed decision from a commissioner (which was also revised). Finally, the commission adopted a “final” decision in January 2011, reinstating the March 2010 decision in nearly all respects, except for extending the TREC usage and cost limitations until 2013. This decision also lifted the moratorium on approving TREC contracts.

Given the similarity between this decision and the highly unpopular March 2010 decision, it is not surprising that the controversy continues. In February, several parties submitted applications to rehear the January decision. Once again, their arguments primarily revolve around the very restrictive definition of bundled transactions.

Further revisions to the January 2011 decision are still possible. Only three sitting commissioners approved the January decision. (Two commissioner seats were vacant at that time.) The term of one of the three commissioners has since expired. Incoming Governor Jerry Brown appointed new commissioners to two of the three vacant seats. Thus, any future decisions on the TREC issue will be taken up by a commission that currently has four members, two of whom did not vote on the January decision. (A fifth appointment is still pending.)

TRECs Under the RES

The controversy at the CPUC over TRECs relates specifically to the 20%-by-2010 RPS, but the controversy could easily spill over to the 33%-by-2020 RES. This is because CARB has decided to defer to the CPUC on the TRECs matter. The CARB resolution approving the 33%-by-2020 RES requires CARB to initiate a rulemaking within 30 days of adoption of the CPUC decision “to ensure continued harmonization of the two programs, specifically incorporating provisions related to Tradable Renewable Energy Credits for all regulated parties under the RES regulation.” This 30-day period ended on February 13, 2011, but CARB has not yet initiated the required rulemaking.

On the other hand, the discussion at the CPUC could also be substantially moot if the legislature passes 33%-by-2020 RPS legislation. A new 33% RPS bill currently moving through the California legislature identifies three categories of renewable energy resources rather than trying to define what is or is not a bundled transaction. One category is resources with a first point of interconnection with a California balancing authority or that would be dynamically transferred to a California balancing authority (i.e., the CPUC’s restrictive definition of bundled resources). Another category is firmed and shaped resources that are scheduled into a California balancing authority (i.e., transactions that were redefined in the CPUC decision from bundled to TREC-only). The third category is all other resources (TREC transactions under all definitions).

The legislation sets separate procurement requirements or limits for each of these categories in three different time periods. For example, beginning in 2017, at least 75% of renewable resources must come from the first category, which is the equivalent of the CPUC requirement that no more than 25% come from TREC-only transactions. However, the legislation further specifies that of the remaining transactions, only 10% can come from the third category. These restrictions are outlined in Table 1 below.

Table 1: Comparison of TREC Usage Limits  in California Programs

First-point of interconnection with or dynamically transferred into California balancing authority

Firmed and shaped and scheduled into California balancing authority

All other
out-of-state, REC only contracts

20%-by-2010 (CPUC January 2011 decision)

2010-2013

At least 75%

No more than 25%

No more than 25%

2014+

No limit

No cap

No cap

33%-by-2020 (CARB, September 2010 decision)

To be “harmonized” with CPUC rules

33%-by-2020 (SBX1 2, active bill in legislature)

Prior to 2013

At least 50%

No more than 50%

No more than 25%

2014-2016

At least 65%

No more than 35%

No more than 15%

2017+

At least 75%

No more than 25%

No more than 10%

The bottom line is that the recent decision by the CPUC to allow RPS-obligated entities to use TRECs to meet part of their RPS compliance obligations is an important first step to finally realizing a tradable REC market in California. But the CPUC framework applies only to the 20%-by-2010 RPS, creating uncertainty as to what the TREC rules might be under a 33%-by-2020 RES. The framework may also not be final, as it remains highly controversial.

This uncertainty will linger while the CPUC continues to grapple with TRECs rules for the 20% RPS and the legislature continues to debate 33% RPS legislation.

Even once these debates are completed, the two RPS (or RES) programs will need to be harmonized, which could provide another opportunity for modifications to the TRECs program and more uncertainty for out-of-state developers interested in selling renewable power into California.