3. Overview of Plan Requirements and Commission Approach
3.1. Overview of Plan Requirements
Each utility covered by the RPS Program is required each calendar year to procure, with some exceptions, a minimum quantity of electricity generated from eligible facilities powered by renewable energy resources.9 This minimum is measured as a percentage of total retail sales and is generally known as the annual procurement target, or APT. Each utility is also required, with some exceptions, to increase its total procurement from eligible renewable energy resources by at least 1% of retail sales per year until it reaches 20%. This is generally known as the incremental procurement target, or IPT, and results in annual incremental growth in the APT. (§ 399.15.) Each utility must, subject to certain flexible compliance provisions, reach 20% by 2010.10 Procuring utilities have a three-year flexible compliance window to meet each year's target, thereby potentially allowing a utility until 2013 to meet 2010 targets. Failure to reach an annual target exposes the utility to possible penalty.
Each utility, as part of fulfilling these requirements, must prepare a Plan for the procurement of RPS-eligible energy. The Plan must include but is not limited to (a) an assessment of demand and supply to determine the optimal mix of renewable resources, (b) use of flexible compliance mechanisms established by the Commission, and (c) a bid solicitation. (§ 399.14(a)(3).)
IOU Plans are subject to Commission review and acceptance, modification or rejection prior to the commencement of renewable resource procurement. (§ 399.14; D.03-06-071.11) An IOU must update its Plan when required by the Commission. (§ 399.14.) For MJUs, we review the biennial IRP (with limited supplemental information) and, in years without an IRP, an expanded Supplement to the IRP.12 (D.08-05-029.) The Commission does not require the MJUs to engage in the same solicitation cycle required of the IOUs. Therefore, the MJUs need not await Commission action before their commencement of renewable resource procurement.
Appendix C contains links to IOU draft Plans and MJU Supplements which we review in this decision.
3.2. Overview of Commission Approach
We have followed an approach of "flexibility with accountability" as we allow utilities to fulfill their duties under the Program. That is, we have granted RPS-obligated utilities considerable flexibility in the way they satisfy RPS Program goals. In exchange, each utility must meet its RPS Program targets, within application of flexible compliance criteria, subject to penalties for unexcused failures to meet targets.
Our responsibility includes accepting, rejecting or modifying IOU Plans (or updates to those Plans) before solicitations may begin. We also review the MJU IRPs and IRP Supplements. We do not, however, write any Plan, IRP or Supplement, or dictate with precise detail the specific language of any Plan, IRP or Supplement. Nor do we micromanage what is in the Plan, IRP or Supplement. Rather, each utility has considerable flexibility to develop and propose its own Plan, IRP, and Supplement. Our review is at a reasonably high level. Similarly, we do not take over the procurement process. Each utility is ultimately responsible for achieving successful procurement using its Plan, IRP or Supplement pursuant to, and consistent with, the RPS Program.
Our responsibility also includes reviewing the results of solicitations. It includes accepting or rejecting proposed contracts, based on consistency with approved Plans, when the contracts are submitted for approval. (§ 399.14(d).) The Plans accepted herein are a fundamental, but not necessarily the only, part of that review.13 Similarly, the Supplements will be a fundamental, but not necessarily the only, consideration when reviewing an MJU's compliance with RPS Program obligations.
We have conditionally accepted prior Plans, provided guidance, taken steps to broaden and enhance the quantity and quality of RPS bids, and improved the contracting process.14 We continue to do so here. We do not repeat existing Commission directions, requirements, and guidance. Rather, all existing directions and guidance remain unchanged unless specifically addressed otherwise herein.
In this order, we discuss limited issues which require our attention before the next solicitation. We first address several issues common to most if not all Plans. We then examine issues specific to a particular Plan or Supplement. We conclude by adopting the schedule for 2011 Plan solicitations, and the process for considering 2012 Plans.
9 Exceptions include, for example, the use of provisions which allow flexible compliance.
10 While statutes provide for 20% by 2010, a goal of 33% by 2020 has been established in other ways. For example, as early as October 2005, the California Energy Commission (CEC) and this Commission jointly adopted Energy Action Plan II (EAP II) identifying as a key action item the implementation of 33% by 2020 (subject to cost-benefit and risk analysis). (EAP II at 8.) In February 2008, we concluded that retail sellers should be expected to increase RPS procurement each year toward a goal of 33% by 2020 but should not be subject to penalties for failure to procure more than 20% by 2010. (D.08-02-008, Conclusion of Law 13.) On November 17, 2008, the Governor established an RPS target by which all retail sellers shall serve 33% by 2020. (Executive Order (EO) S-14-08.) On December 11, 2008, the California Air Resources Board (CARB) adopted a Scoping Plan for implementation of California's greenhouse gas statute (AB 32; Stats. 2006, ch. 598, codified at Health & Safety Code §§ 38500 et seq.). CARB's Plan includes implementing 33% renewable resources in the electricity sector by 2020. (D.08-12-058 at 6.) On September 15, 2009, the Governor ordered CARB, as part of CARB's implementation of the California Global Warming Solutions Act of 2006 (AB 32), to adopt a regulation consistent with the 33% target established in EO S-14-08. (EO S-21-09.) On September 23, 2010, CARB adopted a 33% renewable energy standard (RES). CARB is finalizing the RES regulations. SDG&E offered to commit, upon the approval of the Sunrise Powerlink Transmission Project (Sunrise), to achieve 33% by 2020. On December 18, 2008, we accepted SDG&E's commitment to reach 33% by 2020, and approved the project. (D.08-12-058 at 260.) Recently adopted SB 1X2 adds a statutory requirement of 33% by 2020.
11 Also see D.05-07-039, D.06-05-039, D.07-02-011, D.08-02-008, and D.09-06-018.
12 All RPS-obligated load serving entities (LSEs) must meet five basic elements of the RPS Program. These are: (1) 20% by 2010; (2) increase annual procurement by 1%; (3) report on progress; (4) use of flexible compliance; and (5) uniform penalty provisions. The LSEs include not only large utilities but also MJUs, small utilities, electric service providers (ESPs) and community choice aggregators (CCAs). The MJUs (Sierra and PacifiCorp) must file IRPs and certain Supplements to IRPs. ESPs must file annual procurement plans. (See D.11-01-026.) The small utilities (i.e., Bear Valley, Mountain Utilities) and CCAs are not required by the Commission to file annual procurement plans. (See D.06-10-019 and D.08-05-029.)
13 The review is also described in D.06-05-039, D.07-02-011, and D.09-06-018.
14 For example, we require IOU Plans to: (a) include consideration of proposals with delivery points anywhere in California; (b) incorporate reasonable margins of safety (e.g., allowing for some possible project delays or failures while still meeting Program targets); (c) include interest on deposits; and (d) clearly state the evaluation criteria used in the least-cost/best-fit (LCBF) selection process. We have also (a) adopted revised standard terms and conditions (STCs) for model contracts to increase contracting flexibility; (b) included solicitation of short-term contracts within approved Plans to promote flexibility; (c) recognized individual utility initiative as part of the utility's Plan in order to facilitate creativity, while accepting the utility's proposal to defer certain decisions (e.g., SCE Biomass Program); (d) permitted eligible contracts to be treated as a pool rather than require that the earmarking process identify a specific contract for future satisfaction of a deficit; (e) addressed issues unique to the Sunrise project; (f) adopted a project viability evaluation methodology and required its use; and (g) required that an IOU permit bids of any duration (e.g., in excess of 20 years) in the language it uses in its request for proposal (consistent with STC 5). (See, for example, D.06-05-039, D.07-02-011, D.07-11-025, D.08-02-008, and D.09-06-018.)
