BILL ANALYSIS 1 1 SENATE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE MARTHA M. ESCUTIA, CHAIRWOMAN SB 107 - Simitian Hearing Date: April 26, 2005 S As Amended: April 19, 2005 FISCAL B 1 0 7 DESCRIPTION Existing law: 1.Requires the California Public Utilities Commission (CPUC) to reserve a portion of future electrical generating capacity for renewable resources. (Public Utilities Code Section 701.3) 2.Expresses legislative intent to increase renewable electricity to 17 percent of consumption in the state by 2006. (SB 1038 (Sher), Chapter 515, Statutes of 2002) 3.Requires each investor-owned utility (IOU) to increase its existing level of renewable resources by one percent of sales per year until renewable resources account for 20 percent of its generation portfolio, provided sufficient Public Goods Charge (PGC) funds are available to cover any above-market costs. (AB 57 (Wright), Chapter 835, Statutes of 2002) 4.The "Renewables Portfolio Standard" (RPS), requires IOUs and certain other retail sellers to meet essentially the same renewable procurement goals as AB 57, but sets a deadline of 2017 for achieving a 20 percent renewable portfolio and establishes a detailed process and standards for renewable procurement. a. IOUs and other retail sellers must buy renewable electricity from eligible resources to meet their RPS obligations. Buying unbundled "renewable energy credits" (RECs), rather than electricity, won't satisfy RPS obligations. b. To be eligible, renewable resources must be located in or delivered to California. Delivery to a retail seller or the Independent System Operator is required, but there is no explicit requirement for delivery to the purchasing retail seller. c. Local publicly-owned electric utilities are not subject to the same detailed process and standards as IOUs, but are required to implement and enforce their own RPS programs. (SB 1078 (Sher), Chapter 516, Statutes of 2002) This bill: 1. Advances the deadline for achieving a 20 percent RPS from 2017 to 2010 and requires the CEC to review the feasibility of increasing the RPS target to 33 percent by 2020. 2. Authorizes IOUs and other retail sellers to buy RECs instead of renewable electricity pursuant to a REC trading program which allows the sale of the renewable attribute of renewable electricity as a commodity unbundled from the physical production and delivery of renewable electricity, subject to the following conditions: a. RECs may only be counted once (by the retail seller who purchases the REC). b. Any revenues received by an IOU for the sale of excess RECs must be credited to ratepayers. c. The quantity of RECs that can be separately procured (as opposed to buying renewable electricity) to meet a retail seller's RPS obligations may be limited by the CPUC. d. Renewable energy resources included in an IOU's RPS baseline as of January 1, 2004 can't be sold off as RECs. e. RECs must originate from electricity generated by an eligible resource and delivered in state. f. RECs must include all environmental attributes associated with production from an eligible resource, except emission reduction credits (offsets) issued by an air district. g. A system for tracking and verifying RECs must be established by the California Energy Commission (CEC) before RECs may be used for RPS compliance. h. An IOU may purchase RECs pursuant to a 10-year contract only if the underlying electricity is sold in California and it is not feasible or cost-effective to deliver to the IOU's service territory. 1. Requires each local publicly-owned electric utility to report to the CEC: a. PGC expenditures for renewable energy resource development. b. Amounts of each type of renewable energy resource in its portfolio. c. Status of RPS implementation and progress toward RPS goal. 1. Prohibits the CEC from recognizing RECs from a pre-January 1, 2005 contract unless the contract specifies ownership of the RECs. Prohibits the CEC from recognizing RECs from a post-January 1, 2005 contract entered pursuant to the Public Utility Regulatory Policies Act (i.e. a Qualifying Facility contract). 2. Repeals the 20 percent cap for retail sellers, implying the CPUC may require a retail seller to continue buying renewable resources at the rate of one percent per year after the retail seller attains 20 percent. 3. Authorizes recovery from ratepayers of an IOU's "indirect costs" associated with buying renewable resources, such as having to sell excess energy, decrease output from lower cost resources or upgrade transmission lines. 4. Provides an IOU may only receive an award of "new renewable" PGC funds for a project if the project is selected pursuant to a competitive solicitation the CPUC finds complies with the RPS and the CPUC has approved a contract for the project. These "supplemental energy payments" may not be awarded for the purchase of RECs. 5. Repeals the requirement that the CEC direct 10 percent ($13.5 million/year) of renewable funds collected via the PGC for credits to existing renewable direct access customers (the CEC has suspended the customer credit program and redirected the funds to other renewable programs). 6. Permits an IOU serving fewer than 60,000 customers in California that also serves customers in another state (i.e. PacifiCorp and Sierra Pacific Power) to count its out-of-state renewable resources toward its RPS compliance. 7. Requires IOUs and municipal utilities to adopt strategies to achieve efficiency in the use of fossil fuels and to address carbon emissions. 8. Requires the CEC to prepare recommendations for how to "incentivize" municipal utilities to implement and enforce RPS programs according to the standards applicable to IOUs. 9. Repeals several obsolete provisions and makes various other technical and clarifying changes. BACKGROUND The RPS requires IOUs and certain other retail energy providers, collectively referred to as "retail sellers," to buy renewable electricity to the extent PGC funds are available to pay for any costs exceeding a market price set by the CPUC. Each IOU is required to increase its renewable procurement each year by at least one percent of total sales, so that 20 percent of its sales are renewable energy sources<1> by December 31, 2017. Once a 20 percent portfolio is achieved, no further increase is required. The CPUC is required to adopt comparable requirements for direct access energy service providers (ESPs) and community choice aggregators (CCAs). The RPS applies to: 1.IOUs meeting specified creditworthiness conditions. 2.ESPs, for any new customers or new contracts, and for all customers beginning January 1, 2006. 3.CCAs. --------------------------- <1> Eligible renewable technologies are biomass, solar thermal, photovoltaic, wind, geothermal, renewable fuel cells, hydroelectric 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, and tidal current. Existing small hydroelectric, existing geothermal, and a garbage burning plant in Modesto may be counted toward a retail seller's baseline, but are not eligible for supplemental payments from PGC funds. The RPS does not apply to: 1.Co-generation supplying customers on-site and via "over the fence" transactions. 2.The California Department of Water Resources. 3.Municipal and other local publicly-owned electric utilities. These utilities are responsible for implementing and enforcing their own RPS programs. The RPS requires the CPUC to adopt processes for determining market prices, ranking renewable bids according to cost and fit, flexible compliance rules and standard contract terms. The RPS requires IOUs to offer contracts of at least 10 years, unless the CPUC approves shorter contracts. This is intended to support the development of new renewable resources. The "Energy Action Plan" adopted by the CPUC, the CEC and the California Power Authority pledges that the agencies will accelerate RPS implementation to meet the 20 percent goal by 2010, instead of 2017. In his statements on energy, the Governor has endorsed "20 percent by 2010" and proposed an additional goal of 33 percent by 2020. COMMENTS 1. D?j? vu. This bill is similar to SB 1478 (Sher), vetoed by the Governor last year. As approved by this committee last year, SB 1478 permitted REC trading for RPS compliance, but allowed only one trade. The only transaction permitted was sale of the REC by the generator producing it to the retail seller using it for RPS compliance. In effect, this provision prevented resale by retail sellers and a secondary trading market for RECs. The "one trade" condition was removed from SB 1478 in the Assembly and replaced with a provision that allowed two trades - the initial "bundled" sale of energy and a subsequent trade. Even then, SB 1478 was vetoed on grounds including that its remaining REC conditions were "onerous" and it didn't open up the RPS to the entire western region. This bill contains neither the one trade condition nor the two trade condition. This bill does not limit the number of REC trades and allows anyone, not just generators and retail sellers, to trade RECs. 2. Will REC trading further the purpose of the RPS? Past examples of environmental compliance via credit trading programs indicate these programs provide a more convenient way for regulated industry to achieve minimum compliance, but don't necessarily promote investments to improve the environment or effectively mitigate adverse environmental impacts. In this case, allowing retail sellers to purchase RECs rather than the bundled renewable electricity product will allow them more flexibility to comply with the RPS. For example, an IOU with inadequate transmission to deliver sufficient renewable electricity to its load can buy conventional electricity from a local source to serve its load and buy RECs originating from a distant renewable producer to satisfy its RPS obligations. Or, a small retail seller, such as an ESP, who may not be able to sign the long-term contracts necessary to develop new renewable resources, can buy RECs instead. While REC trading may make RPS compliance more convenient, it adds considerable complexity to a policy already bogged down in complex implementation details. It also seems inherently inconsistent with the goal of supporting the development of new renewable resources within California. This bill attempts to overcome this inconsistency by imposing a variety of conditions on RECs. This bill establishes a limited definition of RECs and further limits how RECs can be traded in an effort to prevent a wide-open REC market. However, the current RPS requires retail sellers to purchase the renewable electricity itself, and contemplates IOUs will comply by buying renewable resources via long-term contracts with in-state producers, rather than by buying RECs. The author and the committee may wish to consider whether REC trading is consistent with the goals of the RPS and whether it should be permitted for RPS compliance. If the intent is to authorize RECs as a compliance alternative, the author and the committee may wish to consider the following additional specific limitations on their use in the RPS: a. Permit only one trade of a REC unbundled from renewable electricity. b. Permit only renewable producers and retail sellers to trade RECs. 1. Is there any evidence that REC trading is needed? Proponents of REC trading say it is needed to address either their inability to deliver renewable electricity to their customers or their inability to enter the long-term contracts for renewable electricity contemplated by current RPS law. Sempra wants RECs because it says it doesn't have enough renewable electricity potential within San Diego or deliverable to San Diego using existing transmission lines. So, instead of investing directly in renewable generation itself, it wants to be able to purchase RECs from renewable generation that someone else has invested in. While Sempra's deliverability issue is legitimate, it doesn't require REC trading to solve. It can be addressed through exchanges with other California utilities, while retaining the new investment focus of the RPS. This approach may require a fairly minor clarification of delivery requirements in current law. ESPs want RECs because entering long-term contracts to support development of new renewable resources doesn't fit their business model - which is to buy electricity sufficient to serve their customers on a relatively short-term basis. Sempra and the ESPs are pointing to prospective problems which have not been confronted in RPS implementation to date. Nor have they demonstrated that REC trading is needed to address them. The author and the committee may wish to consider whether REC proponents should show evidence of need prior to permitting REC trading, rather than permitting it based on speculation about prospective problems. 2. 20 percent by 2010, then what? One percent per year is the current rate of renewable additions required by AB 57 and the RPS. This pace leads all IOUs to reach 20 percent on or before 2017. Because Southern California Edison is already near 20 percent, advancing the deadline to 2010 may not have a material impact on its RPS obligations. Pacific Gas & Electric reports a 2004 baseline of 12.7 percent, so would need to increase to about 1.2 percent per year to reach 20 percent by 2010. San Diego Gas & Electric is currently at about 7 percent, so would need to increase to about 2.2 percent per year to reach 20 percent by 2010. In addition to advancing the 20 percent deadline to 2010, this bill removes the 20 percent cap for retail sellers, implying the CPUC may require an IOU or another retail seller to continue buying renewable resources at the rate of one percent per year after attainment of the 20 percent goal. The bill also requires the CEC to review the feasibility of increasing the RPS target to 33 percent by 2020 and report back to the Legislature. 3. Who gets to count RECs from PURPA contracts? In 2003, the Federal Energy Regulatory Commission (FERC) ruled that long-term PURPA contracts with Qualifying Facilities do not necessarily result in the conveyance of RECs to the purchasing utility. FERC reasoned that its "avoided cost regulations did not contemplate the existence of RECs and that the avoided cost rates for capacity and energy sold under contracts entered into pursuant to PURPA do not convey the RECs, in the absence of an express contractual provision." FERC left determinations regarding ownership to the states, noting that "states, in creating RECs, have the power to determine who owns the REC in the initial instance, and how they may be sold or traded; it is not an issue controlled by PURPA." This bill addresses the REC ownership issue teed up by FERC for the states by not permitting the recognition of RECs from PURPA contracts (unless an existing contract specifies ownership of the RECs) and therefore preventing the scenario where RECs would be created and sold apart from the contract, which could result in double payment for the same renewable electricity or disqualification of PURPA contracts now counted toward IOUs' RPS baselines. The provisions in this bill assure renewable power from PURPA contracts count toward the RPS obligations of the purchasing IOU and are similar to provisions in SB 431 (Battin), approved by this committee April 19. 4. Should ratepayers pay for RPS excesses? This bill authorizes recovery from ratepayers of an IOU's "indirect costs" associated with buying renewable resources, such as having to sell excess energy, decrease output from lower cost resources or upgrade transmission lines. As written, this seems like a fairly open-ended and unbalanced obligation on ratepayers. The author and the committee may wish to consider specifying that such indirect costs, in order to be recovered, must be prudently incurred, necessary to comply with the RPS and in ratepayers' interest. In addition, the author and the committee may wish to consider whether such expenses, if they are unique to buying renewable resources, should be funded out of the PGC. 5. CEC reports should be consolidated. The author and the committee may wish consider combining the two CEC reports required by this bill and incorporating them into the CEC's current Integrated Energy Policy Report process. 6. Technical amendments. This bill requires a variety of technical and clarifying amendments to ensure consistent standards, terms, cross references and grammar. 7. Related legislation. Two competing measures based on SB 1478 were introduced in the Assembly, AB 1362 (Levine) and AB 1585 (Blakeslee). AB 1362 appears to permit unlimited REC trading for RPS compliance. As introduced, AB 1585 permitted unlimited REC trading, but was recently amended to remove all provisions except a CEC study of the feasibility of attaining a 33 percent RPS standard. Both bills are set for hearing in the Assembly Natural Resources Committee April 25. POSITIONS Sponsor: Author Support: Clean Power Campaign East Bay Municipal Utility District Independent Energy Producers (if amended) Sierra Club California The Utility Reform Network Union of Concerned Scientists Oppose: California Council for Environmental and Economic Balance Calpine Constellation New Energy Pacific Gas and Electric Company Sempra Energy Southern California Edison Lawrence Lingbloom SB 107 Analysis Hearing Date: April 26, 2005