On April 12, 2011, California Governor Jerry Brown signed Senate Bill 2 of the 1st Extraordinary Session (SB 2X) into law. SB 2X requires California retail electric providers to procure 33 percent of their retail energy sales from eligible renewable sources by 2020. Previously, they were required to procure 20 percent of those sales from renewable sources by 2010.
SB 2X provides a broad mandate to the California Public Utilities Commission (CPUC) and to local publicly owned electric utilities to implement the requirements of the bill, which are both wide-ranging and esoteric. SB 2X also adds regulation that further clouds the ability of out-of-state renewable projects to enter the California renewables market, but may also include a silver lining for existing projects that have entered into power purchase agreements which were previously approved by the CPUC.
This advisory explores that ambiguity and its implications on the California renewables market.
As described in an earlier advisory, the CPUC issued a decision in January 2011 authorizing the use of tradable renewable energy credits (TRECs) to satisfy the requirements of the California Renewables Portfolio Standard (RPS) program (2011 TREC Decision).
Prior to the 2011 TREC Decision, CPUC-regulated entities had been required to procure RPS power exclusively through “bundled” contracts (i.e., an integrated transaction in which the CPUC-regulated entity purchases both the physical energy and TRECs from one seller). The 2011 TREC Decision allows CPUC-regulated entities to procure TRECs separate from their associated energy (i.e., an RPS generator may now sell its physical energy to one entity, and in a separate transaction, sell the TRECs associated with that physical energy to a CPUC-regulated entity). This additional flexibility for CPUC-regulated entities should provide incentives for the development of RPS power by offering additional revenue streams potentially available to RPS project developers, both in- and out-of-state.
Through the 2011 TREC Decision, the CPUC limited the three largest California Investor Owned Utilities’ (IOUs) use of TRECs for RPS compliance to not more than 25 percent of the IOU’s annual RPS megawatt-hour purchases. In addition, the 2011 TREC Decision determined that most, if not all, transactions involving firmed and shaped products that provide incremental power would be considered transactions involving TRECs subject to the 25 percent cap—including contracts involving firmed and shaped products previously approved by the CPUC as bundled.
SB 2X will impact the flexibility of retail electric providers to meet their RPS obligations
Beginning in 2013, SB 2X mandates that retail electric providers meet their RPS compliance obligation through procurement of eligible renewable energy resources in three portfolio content categories, with a minimum of 50 percent procured from in-state and in-state equivalent products, a maximum of 25 percent from unbundled RECs, and the remainder from firmed and shaped products that provide incremental power. Ultimately in 2017, these percentages change to a minimum of 75 percent from in-state and in-state equivalent products, a maximum of 10 percent from unbundled RECs, and the remainder from firmed and shaped products that provide incremental power.
The 2011 TREC Decision made no distinction between transactions involving unbundled RECs and transactions involving firmed and shaped products. Instead, the 2011 TREC Decision lumped these transactions together as TREC transactions and made them all subject to the 25 percent TREC cap. Furthermore, the 2011 TREC Decision set no minimums or maximums as to the amount of transactions involving firmed and shaped products vis-à-vis transactions involving unbundled RECs under the 25 percent cap set for all TREC transactions. SB 2X separates these transactions into two distinct categories with the specific procurement requirements described above.
Thus, SB 2X appears to temporarily provide greater flexibility for retail providers to meet their RPS procurement mandates by increasing the percentage of TREC transactions (involving both unbundled RECs and firmed and shaped products) that a retail electric provider may potentially enter into in 2013 (50 percent) when compared to the 2011 TREC Decision (25 percent). However, by 2017, the percentage of TREC transactions equalizes between SB 2X and the 2011 TREC Decision, since the cap for all TREC transactions (involving both unbundled RECs and firmed and shaped products) is set at 25 percent starting in 2017 under both SB 2X and the 2011 TREC Decision.
In addition, by 2017, SB 2X appears to further reduce the flexibility of retail electric providers to choose among transactions involving firmed and shaped products and transactions involving unbundled RECs when compared to the 2011 TREC Decision. SB 2X mandates that transactions involving firmed and shaped products make up some portion of what the CPUC considers to be TREC transactions if TREC transactions ultimately make up more than 10 percent of the retail electric provider’s procurement in 2017 and beyond.
Out-of-state generators should take note that RPS-eligible generation from an out-of-state project that is “scheduled … into a California balancing authority without substituting electricity from another source” qualifies as an “in-state” product. It appears that the qualification of generation that is “scheduled into” California is intended to enable out-of-state projects that have firm transmission rights and the corresponding right to schedule and deliver power into California to qualify for the most advantageous of the three portfolio content categories as effectively an in-state bundled sale.
SB 2X may provide a silver lining by potentially grandfathering previously approved contracts
SB 2X potentially provides a broad exemption from the limitations on transactions involving both firmed and shaped products and unbundled RECs for existing projects.
Section 13 of SB 2X designates the following existing and prospective RPS transactions as not subject to the limitations on transactions involving both firmed and shaped products and unbundled RECs:
- RPS power from out-of-state resources that is being sold to California utilities in accordance with CPUC-approved power purchase agreements and will “supply electricity to California end-use customers”; and
- “[N]early 7,000 megawatts of additional proposed renewable energy resources located outside of California that are awaiting interconnection approval from the Independent System Operator,” if procured by a California utility.
These exemptions arguably grandfather all prior CPUC-approved power purchase agreements. This would be a significant improvement in the available capacity for future transactions involving both firmed and shaped products and unbundled RECs when compared to the expected available capacity that was to result from the 2011 TREC Decision.
As noted above, the 2011 TREC Decision counted all transactions involving both firmed and shaped products or unbundled RECs to count against the 25 percent TREC cap regardless of whether the transaction had been approved by the CPUC prior to the 2011 TREC Decision. Thus, a significant portion of the available capacity under the 25 percent TREC cap would have already been subscribed by existing CPUC-approved contracts that are now considered TREC transactions by the 2011 TREC Decision.
SB 2X provides additional support that the exemptions of Section 13 noted above are meant to grandfather all prior CPUC-approved power purchase agreements, however, the full extent of the scope of the grandfathering of prior RPS transactions may not be known until the CPUC issues a ruling construing the specific statutory language of SB 2X.