The California Legislature has passed Senate Bill ("SB") X1-2, which requires California's electric utilities to increase their renewable generation to 33% by 2020. Passage of the legislation is the culmination of years of effort to increase California's Renewable Portfolio Standard ("RPS") from its current 20%. In 2009, the Legislature passed SB 14, which also would have increased California's RPS to 33%, but the bill was vetoed by Governor Schwarzenegger on the ground that it imposed too many restrictions on the use of out-of-state generation to meet California's RPS requirement. Governor Schwarzenegger then issued an executive order directing the California Air Resources Board to develop its own 33% Renewable Energy Standard under the Board's authority pursuant to Assembly Bill 32, the Global Warming Solutions Act of 2006. Last year, the Legislature again tried to pass another 33% RPS bill, SB 722, but the session expired before the legislation could reach a final vote. Two bills were introduced in this session: SB 23 and SBX1-2. SBX1-2 was identical to SB 23, but it was introduced in special session in an attempt to speed passage of the legislation. SBX1-2 now goes to Governor Brown for signature, and he is expected to sign the legislation into law.
In addition to increasing the RPS to 33% by 2020, SBX1-2 also makes a number of other significant changes to California's RPS. For the first time, the RPS would be extended to publicly owned utilities ("POUs") in California. Under the 20% RPS, municipal utilities were required to develop a standard but were free to choose the amount of renewable energy they would procure under that standard. For POUs, implementation of the 33% RPS would be left to their governing boards, while the California Energy Commission, which is tasked under the legislation with developing an enforcement mechanism for the POUs, would refer any violations to the California Air Resources Board for penalties.
SBX1-2 requires California's electric utilities to reach the 33% RPS in three compliance periods. By December 31, 2013, the utilities must procure renewable energy products equal to 20% of retail sales. By December 31, 2016, utilities must procure renewable energy products equal to 25% of retail sales, and by December 31, 2020, utilities must procure renewable energy products equal to 33% of retail sales and maintain that percentage in following years.
One area of significant disagreement concerning a 33% RPS was the extent to which it would require projects used for RPS compliance to be located in California, or to deliver power to California. SBX1-2 addresses this issue with a rather complicated formula. All energy from eligible renewable resources supplied under power purchase agreements executed prior to June 1, 2010 shall count toward a utility's RPS compliance obligation. Any procurement after June 1, 2010 is categorized into three groups. The first group is composed of products from eligible renewable energy resources that have a first point of interconnection with a California balancing authority or distribution facilities used to serve California end users, or energy that is scheduled from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source (although the use of another source to provide real-time ancillary services required to maintain an hourly or a subhourly import schedule into a California balancing authority is permitted, the energy from the other source providing ancillary services does not count toward a utility's RPS compliance obligation). Any energy from an eligible renewable energy resource delivered to a California balancing authority under a dynamic transfer arrangement is included in this first group as well.
The second group consists of firmed and shaped eligible renewable energy resource electricity products providing incremental electricity and scheduled into a California balancing authority. Firming and shaping consist of providing energy from another source to augment generation from variable resources to smooth out over and under generation from those resources.
The third group consists of any products that do not fit within the first or second group, including unbundled renewable energy credits ("RECs"). Unlike under the 20% RPS, no energy need be associated with the unbundled RECs in order for them to count toward 33% RPS compliance.
For the compliance period ending December 31, 2013, not less than 50% of the energy procured through contracts executed after June 1, 2010 has to meet the requirements of the first group. That percentage increases to 65% for the compliance period ending December 31, 2016, and to 75% thereafter.
For energy that meets the requirements of group two, a utility may procure not more than 50% of those products for the first compliance period, not more than 35% for the second compliance period, and not more than 25% thereafter.
For energy that falls into the third group, a utility may procure not more than 25% of those products for the first compliance period, not more than 15% for the second compliance period, and not more than 10% thereafter. Furthermore, any procurement that falls into this group correspondingly reduces the amount of energy a utility may procure in the second group. (For example, if during the first compliance period a utility procures 25% of its compliance obligation from energy in the third group, it may only procure an additional 25% in second group, as the first group must comprise at least 50% of a utility's procurement during the first compliance period.)[1]
This categorization differs markedly from the way the California Public Utilities Commission ("CPUC") recently handled a similar issue as part of its implementation of the 20% RPS. In March of last year, the CPUC adopted a decision that allowed the use of unbundled tradable renewable energy credits ("TRECs") for compliance with the 20% RPS. However, it put limits on that use. First, it defined a TREC transaction as any transaction with an eligible renewable energy resource that did not have either its first point of interconnection with a California balancing authority, or a dynamic transfer arrangement with a California balancing authority. It then capped the use of TREC transactions for RPS compliance to 25% of the annual compliance obligation for the three largest investor-owned utilities in California (Southern California Edison, Pacific Gas and Electric ("PG&E"), and San Diego Gas and Electric ("SDG&E")). The CPUC later imposed a moratorium on implementation of that decision in response to petitions for modification filed by several parties, but in January of this year lifted the moratorium and extended the cap to cover energy service providers as well. The CPUC also reiterated that it might consider certain types of firm transmission to a California balancing area as a bundled, rather than a TREC, transaction but stated that it would consider that issue in a later proceeding.
In recent filings with the CPUC, PG&E stated that it would exceed the 25% cap in 2011, and data provided by SDG&E showed that it, too, was close to the cap. How close the utilities would be to the cap for the second and third groups in SBX1-2, however, is difficult to calculate for several reasons. First, the first group includes firm transmission, which does not currently count as a bundled transaction under the CPUC's decision. Second, energy deliveries under contracts executed before June 1, 2010 do not count toward the various groups under SBX1-2, whereas under the CPUC decision, those deliveries do count toward the 25% cap, to the extent deliveries result from transactions that are categorized as a TREC transaction. And in the initial two compliance periods, the total caps for groups two and three are greater than the 25% cap that would apply to both these groups under the CPUC decision. However, after 2016, the cap for these two groups would be 25%. For a utility entering into a contract now in excess of 10 years, the post-2016 percentage allocations would be relevant because the contract would extend into that time period.
SBX1-2 also amends the cost-containment provisions for the California RPS. Under the 20% RPS, the CPUC calculated what was called the "market price referent," or MPR, which was a calculation of the long-term ownership, operating, and fixed fuel costs for a new 500 MW combined cycle natural gas-fired gas turbine. The CPUC awarded "above-market funds," or AMFs, to the utilities to pay for any contract costs in excess of the MPR. Once the utility exhausted its AMFs, it was no longer obligated to procure additional renewable generation.
SBX1-2 abolishes the MPR. Instead, it charges the CPUC with establishing, for each utility under its jurisdiction, a limitation on procurement expenditures for all eligible renewable energy resources used to comply with the 33% RPS. The utility will not be required to engage in any procurement that causes its procurement costs to exceed the limitation established by the CPUC.
SBX1-2 also allows investor-owned utilities to apply to the CPUC for permission to construct, own, and operate their own renewable generation for RPS compliance, subject to certain limitations. The CPUC must find, before approving any such application, that the proposed project "utilizes a viable technology at a reasonable cost," and that it provides "comparable or superior value to ratepayers when compared to then recent contracts for generation." Utilities are also limited to constructing and owning resources that supply no more than 8.25% of their anticipated retail sales by December 31, 2020 and thereafter.
The CPUC can also waive enforcement of the 33% RPS if it finds that a retail seller has demonstrated that any of the following conditions are beyond the control of the retail seller and will prevent compliance: (1) inadequate transmission capacity; (2) permitting, interconnection, or other circumstances that delay renewable projects already procured, or an insufficient supply of renewable projects; or (3) unanticipated curtailment of eligible renewable energy resources necessary to address the needs of a balancing authority.
If signed, details concerning the implementation of the new legislation would have to be worked out at various California regulatory agencies, including the CPUC and the California Energy Commission. The legislation will likely spawn numerous regulatory proceedings as the various regulatory agencies struggle to come to grips with the new RPS mandate.
If you have further questions about SBX1-2 or California energy regulatory matters, please contact a key contributor.
[1] Certain multi-jurisdictional and small utilities are not bound by this procurement structure, and a utility may in certain cases obtain permission to vary from these requirements.