BILL ANALYSIS SB 14 Page A Date of Hearing: July 6, 2009 ASSEMBLY COMMITTEE ON UTILITIES AND COMMERCE Felipe Fuentes, Chair SB 14 (Simitian) - As Amended: June 23, 2009 SENATE VOTE : 21-16. SUBJECT : Renewable Portfolio Standard SUMMARY : Increases California's Renewables Portfolio Standard (RPS) to require all retail sellers of electricity and all publicly owned utilities (POUs) to procure at least 33% of electricity delivered to their retail customers from renewable resources by 2020. Makes changes to current renewable procurement rules and procedures for siting renewable generation and transmission. EXISTING LAW : 1)Requires investor-owned utilities (IOUs) and certain other retail sellers to achieve a 20% RPS by 2010 and establishes a process and standards for renewable procurement. 2)Provides that POUs are not subject to the same detailed procurement process and standards as IOUs, but are required to implement and enforce their own RPS programs. 3)Defines eligible renewable technologies to include biomass, solar thermal, photovoltaic, wind, geothermal, renewable fuel cells, small hydroelectric (30 MW or less), digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, and tidal current. 4)Provides that eligible renewable resources that are located outside of California may count toward the California RPS if the generator commences operation after January 1, 2005, and the facility is directly connected to California's transmission grid or the associated electricity is delivered to California. 5)Creates a cap on above-market costs of renewable electricity each IOU is required to spend under the RPS. If the cost cap is reached, IOUs are not required to sign any renewable SB 14 Page B contract that exceeds the market cost of electricity. 6)Requires PUC to develop flexible rules for compliance for the RPS that allows a retail seller that cannot not meet its annual targets to delay compliance for up to three years and avoid penalties under certain conditions. 7)Requires the California Energy Commission (CEC) to certify electric generation facilities for the construction and operation of thermal powerplants of 50 MW and larger. 8)Precludes an electrical corporation from constructing a line, plant, or system without having first obtained a permit from PUC that the present or future public convenience and necessity require or will require such construction, (a certificate of public convenience and necessity or CPCN). THIS BILL : 1)Requires retail sellers of electricity to procure at least 20% of electricity delivered to retail customers from renewable sources by 2012, 23% by 2014, 26% by 2016, 30% by 2018, 33% by 2020. 2)Modifies the definition of eligible renewable resources under the RPS as follows: a. For renewable resources located outside of California, the electricity from the resources must be scheduled into California at the same time it is produced by the renewable facility. b. The renewable facility must commence initial operation after January 1, 2010, or the electricity from the facility that commenced operation prior to January 1, 2010, was sold to a retail seller prior to May 31, 2009. 3)Allows retail sellers and POUs to count the renewable output from renewable facilities that do not comply with the definitions of eligible renewable resources toward the RPS if the retail seller or POU had executed a contract prior to May 31, 2009, to procure resources from a facility that met the requirements of a renewable resource prior to passage of this bill. SB 14 Page C 4)Eliminates current rules that allow retail sellers to postpone compliance with annual RPS targets for up to three years in the future. Replaces those rules with provisions that allow the PUC to grant a retail seller the ability to delay compliance for up to two years if the PUC makes specific findings that there is insufficient transmission to meet the RPS or there were unforeseen delays in permitting or interconnecting projects. The findings must consider whether the retail seller made all reasonable efforts to construct new transmission and made prudent decisions in procuring resources. The retail seller must also show that it has made all reasonable efforts to procure distributed generation resources and to procure RECs. 5)Requires all retail sellers to procure renewable resources beyond the specified targets to account for the risk that some planned resources will not being developed. The margin of the over-procurement shall be set at the same level for all retail sellers. 6)Requires renewable procurement plans prepared by IOUs and approve by the PUC to include a process to consider the viability of proposed projects when ranking project bids. 7)Provides that the Market Price Referent (MPR) shall be used to determine above-market costs of renewable electricity. The MPR shall be set based on the value of different generation products within a utility's portfolio and the value of current and anticipated environmental compliance costs. 8)Provides that an IOU does not have to procure additional renewable resources in a particular year if the total above-market cost of the renewable electricity procured under the RPS program or bilateral contracts for that year exceeds 6% of the IOUs total bundled electricity sales. 9)Requires the PUC to adopt mechanisms to limit the influence the MPR has on how sellers price their renewable proposals and buyers select their contracts. 10)Creates a mechanism to allow the PUC to approve an IOU application to own its own renewable generation and then recover in rates the cost of that generation plus a reasonable rate of return, if the PUC finds the renewable generating facility has a reasonable cost and provides a comparable value SB 14 Page D to ratepayers as compared to other solicitations for eligible renewable resource. Caps the total amount of renewable generation an IOU can own at 8.5% of the IOU's total load. 11)Allows retail sellers and POUs to use RECs from out-of-state renewable resources that do not deliver electricity into California (undelivered RECs) toward their RPS obligations, but caps the total amount of undelivered RECs at 20% of the retail seller's or POU's renewable procurement targets. 12)Provides that retail sellers and POUs can count all undelivered RECs from contracts executed by the retail seller or POU prior to May 31, 2009. 13)Requires the PUC to approve an application to build new transmission lines that are reasonably necessary to develop renewable resources within one year of the filing of a completed application, if the new transmission line does not threaten substantial harm to the environment that necessitates a longer time for review under the California Environmental Quality Act (CEQA). 14)Clarifies that an IOU shall be allowed to recover in rates the costs of constructing transmission lines that will primarily deliver electricity generated within a competitive renewable energy zone identified by the Renewable Energy Transmission Initiative (RETI) or the transmission line is needed to deliver electricity that is to be generated by generation facilities in an area where at least 50% of the generation capacity is from renewable resources. 15)Requires the California Independent System Operator (CalISO) to adjust its market structure to achieve, in the most cost effective manner, the 33 percent RPS threshold by 2020, develop annual statewide transmission plans, seek proposals from and propose transmission projects to POUs that can be jointly owned, and eliminate barriers over transmission lines in its control area. 16)Requires the Department of Fish and Game (DFG) to establish an internal division for the purpose of performing planning and streamlined environmental compliance services with a priority given to the building of eligible renewable energy resources. SB 14 Page E 17)Requires the PUC to prepare, on an annual basis, reports to the Legislature containing information on the status of meeting the RPS, possibilities of retail sellers exceeding caps on above-market costs, overall cost of the RPS compliance, and the status of permitting and siting renewable facilities. 18)Requires POUs to comply with the same RPS mandates as retail sellers and to meet specified public notice and reporting requirements. Provides that the POUs shall retain discretion over specific renewable procurements decisions necessary to meet the RPS mandates. 19)Requires the CEC to establish and enforce a 33% RPS for each POU. 20)Requires the CEC in consultation with California Air Resource Board (ARB) to adopt regulations for the enforcement of the RPS on POUs. Provides that the ARB shall, until such time there is a market mechanism to distribute emissions allowances for greenhouse gasses, have the authority to impose penalties on POUs for failure to comply with the RPS. 21)Clarifies that a public utility district receiving 100 percent of its electricity pursuant to a preference right pursuant to the federal Trinity River Diversion Act of August 12, 1955 is in compliance with the renewable energy procurement requirements of the RPS Program. FISCAL EFFECT : Unknown COMMENTS : Background : In 2002, the Legislature approved SB 1078 (Sher), Chapter 516, Statutes of 2002, which created the RPS. Under the RPS, Investor Owned Utilities (IOUs) and competitive energy service providers (ESPs) of electricity were required to increase their renewable procurement each year by at least 1% of total sales, so that 20% of their sales are from renewable energy sources by December 31, 2017. This goal was accelerated to 20% renewable power by 2010 by SB 107 (Simitian), Chapter 464, Statutes of 2006. The PUC reports that for 2007, the IOUs have achieved varying SB 14 Page F levels of progress toward the 20% goal: PG&E = 11.4%; SCE =15.7%; SDG&E = 5.2%. While each IOU added renewable resources in 2007, the percentage of renewables compared to the rest of the portfolio declined from 2006 due to total load growth. All agencies and stakeholders agree that the IOUs will not meet the 2010 deadline. However, the PUC reported in October 2008 that the IOUs should be in compliance in or around 2013. This month the PUC completed a report with preliminary results on analyzing the feasibility and costs of advancing the RPS targets from 20% to 33% by 2020. According to the report, "achieving 33% RPS by the year 2020 is highly ambitious, given the magnitude of the infrastructure buildout required." The report also looked at the costs of achieving a 33% RPS. Under the PUC's analysis, the incremental cost of moving from the current 20% RPS mandate to a 33% RPS would result in a 7.1% increase in utility costs. The increased cost include the costs of more expensive generation resources, new transmission, and other resources that will be needed to provide back up generation when renewable electricity is not available. The cost increases assumes the utility will continue the same balance of renewable technologies that they are perusing today, which includes a large reliance on wind and solar energy. The cost increases also assume the direct costs of building new renewable facilities remains unchanged over time and do not take into account potential decreases in technology costs overtime. 1) The New targets : SB 14 eliminates the requirement that retail sellers procure 20% of their electricity by 2010 and instead requires that following procurement targets: a) 20% by 2012. b) 23% by 2014. c) 26% by 2016. d) 30% by 2018. e) 33% by 2020. While this new procurement schedule acknowledges the reality that no retail sellers will comply with the 20% by 2010 targets, it also does not acknowledge the difficulty retail sellers will have moving beyond 20% until several new transmission lines are constructed. While two needed transmission lines should be completed by 2013, the PUC estimates a total of 7 new lines will need to be constructed, and those lines will likely take 5 to 10 SB 14 Page G years to complete. Given these transmission limits, a procurement schedule that requires slower renewable growth early in the program and larger incremental increases as 2020 approaches may be more realistic. The committee and the author may wish to consider amending the bill to provide for a renewable growth pattern that better tracks transmission development such as 20% by 2012, 23% by 2015, 28% by 2018 and 33% by 2020. 2) Eligible Resources : Current law defines renewable electricity as electricity that comes from biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 MW or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current. While the definition of renewable resources is generally accepted, there is debate over the definition of what types and size of hydroelectricity facilities can count toward the RPS. Current law provides that a hydroelectric facility must have a capacity of 30 MW or less and must meet other specified streamflow standards to count toward the RPS.<1> Most of the POUs would like to have this definition changed to increase the allowable capacity to 50 MW. This change would allow the POUs to continue to count some existing small hydroelectric facilities to count toward their RPS obligations. However, it is unlikely that the change would result in the construction of new facilities that are larger than 30 MW but smaller than 50 MW. Additionally, PG&E has requested that small hydroelectric facilities in British Columbia count toward its RPS obligation if the facilities comply with British Columbia's environmental standards but not California standards. Another resource that currently cannot be counted as renewable is conversion of solid waste, where solid waste is turned into a gas that can then be used to produce electricity. Advocates for solid waste conversion believe that these facilities can process solid waste that cannot be recycled and thus prevent the waste from entering landfills. Opponents of solid waste conversion counting toward an RPS requirement are concerned that some of the converted waste could actually be recycled and in most --------------------------- <1> Current law also allows all electric generation that is the result of efficiency improvements to existing hydroelectric facilities to count toward the RPS, regardless of the size of the original output of the facility. SB 14 Page H circumstances recycling has better environmental benefits than conversion. Some opponents also believe that since most of the material that will be converted was originally produced from oil by-products (plastics) that the material being used is actually a fossil fuel and not renewable. Current law also allows for renewable generation to be owned by retail sellers or for the retail sellers to contract to purchase renewable electricity from merchant generators. Prior to 2008, federal tax rules made utility ownership of renewable generation economically unfeasible. However, new tax rules make IOUs eligible for tax credits for owning renewable facilities. Even with the changes in tax rules IOUs are reluctant to pursue owning their own renewable generation under most circumstances to do concerns over their ability to recover all costs of the generation in rates. SB 14 includes a provision to clarify the process in which IOUs can recover the cost of building their own generation, but also caps the total amount of renewable generation they can directly own. 3) Location, deliverability, and renewable energy credits : To count toward a retail seller's RPS obligation, the renewable facility must meet several requirements including that the facility be located in California or deliver its electricity to California. The definition of "deliver" in current law was written to allow an out-of-state renewable generator that wants to serve California load to comply with CalISO rules that require out-of-state electricity to be scheduled into California at specific times and amounts. Since renewable resources like wind and solar are intermittent, they cannot be scheduled at specific times and amounts. The intent of the language was for the renewable energy to come to California at some point and then offset the need for fossil fuel generation within California. However, the CEC, which sets the eligibility rules, interpreted the statutory language to allow for transactions where the renewable electricity never comes to California to count toward the RPS as an eligible resource. SB 14 potentially limits the amount of out-of-state generation that can count toward the RPS by changing the definition of "deliver." With the limited exception discussed under the renewable energy credits section below, the new definition requires that electricity from an out-of-state facility that is not directly interconnected to a California control area must be simultaneously scheduled into California. This means that the SB 14 Page I renewable electricity must come into California at the same time it is produced or it cannot count toward the RPS. This new definition prevents a utility from counting transactions toward the RPS where it purchases wind generation from an out-of-state generator but then sells that electricity to another out-of-state entity and instead imports electricity from a fossil fuel facility. However, the definition also makes it almost impossible to purchase electricity from a solar or wind facility that is located out-of-state, since these resources cannot be simultaneously scheduled into California. A REC represents the renewable attributes of renewable generation. A REC can remain bundled with the associated energy. In that case, the utility buys the renewable electricity and uses the RECs to meet its RPS obligation and uses the associated electricity to meet its own load. RECs can also be traded separate from the underlying electricity (tradable RECs or tRECs). In this case, one retail seller purchases the tREC and applies it toward its RPS obligation and another retail seller purchases the associated electricity to meet its own load. The second retail seller cannot count that electricity toward its own RPS obligations. Current law allows the use of tRECs to meet RPS obligations, but the tRECs must come from a facility that meets all of the requirements to be an eligible renewable resource. The tREC must come from a facility that is located in state or from an out-of-state facility that delivers the associated electricity into California. While current law allows for tRECs, it also requires the PUC to develop specific rules on tREC eligibility before retail sellers can count tRECs toward their RPS obligations. A decision to implement the tREC rules is pending at the PUC. Most retail sellers and some renewable generators have advocated for broader use of RECs. The retail sellers and the Clean Power Campaign state that the RPS should not limit the use of RECs or put restriction on the geographic location or deliverability of the associated renewable resource. They believe this broad REC market would give retail sellers more procurement options and could reduce the cost of complying with the RPS. A number of environmental groups, the Coalition of Utilities Employees, the Large Solar Association, and California Wind Energy Association have all advocated for a very limited SB 14 Page J allowance for out-of-state RECs. They fear that a wide-open REC market will lead to "paper compliance with the RPS" and will not result in the construction of any renewable generation within California. SB 14 continues to allow for unlimited tRECs if they are associated with an eligible renewable facility. The bill also allows a retail seller to meet up to 20% of its RPS obligations with tRECs from out-of-state facilities that cannot meet the new delivery requirements established in SB 14. The end result of the change in the delivery requirements and the tREC requirements is that there is now a 20% cap on most forms of out-of-state generation. 4) Cost containment : Current law provides that if the above-market costs of renewable electricity exceed set limits an IOU is not required to acquire any additional renewable resources that are priced above the market price. The market price is determined by the PUC based on forecasts of the estimated cost of running a natural gas fired power plant plus the cost of carbon emissions from a natural gas facility. The market price is referred to as the market price referent (MPR). The MPR is not a cap on project costs. An IOU must purchase renewable electricity even when contract costs exceed the MPR. However, an IOU is required to acquire this higher-cost renewable electricity only to the extent that sum total of all the above-market costs from renewable procurement is less than the a statutorily set cost cap. If the above-market costs exceed the cost cap, then the IOUs are not required to sign any additional contracts that exceed the MPR. However, if there are suitable contracts which cost less than the MPR the IOU would still be required to procure power under those contracts. The above-market cost cap was not established based on a determination of the perceived reasonable cost of renewables, ratepayer benefits, or tolerable ratepayer impacts. Instead, it was based on the amount of funds that were to be collected for a prior renewable electricity grant program. Consequently, it is possible that the cap was set at a level that makes achieving a 20% RPS or a 33% RPS impossible. While the current cost cap has not been reached, the PUC testified at a hearing of the Select Committee on Renewable resources that is likely that a determination will be made in the next month that the cap has SB 14 Page K been reached. Over the past year, there has been significant debate over how to best contain costs of renewable contracts under a mandatory renewable procurement program. Parties have settled on two basic approaches. The first is leave the structure of the current system in place but alter the MPR so it is not based so heavily on natural gas forecasts and then increase the caps on above-market costs to reflect the actually expected costs of complying with a 33% mandate. The second approach is to eliminate the cap on the total cost of the RPS and instead require the PUC to only look at the cost of the individual renewable contracts a IOU signs and determine if that contract offers a fair value to rate payers and is just and reasonable. SB 14 takes the first approach by modifying the MPR process so that it takes into account more factors and will not be based solely on natural gas. The bill also sets the cost cap at 6% of an IOU's annual total revenues. This new cost cap allows the Legislature to determine how much impact renewable electricity should have on a retail sellers' overall cost structure and then set the cost cap at that level by basing it on a percentage of overall revenue. SB 14 also calculates the caps on above-market costs of renewables on an annual basis instead of over the life of the program as current law does. This means that if in one year the IOU had reached its above-market cost for that year it would not have to procure more renewable electricity for that year, but could have to restart procurement the next year. It is not clear how this annual cost cap would work with a multiyear procurement process. Most renewable contracts are for 10 to 20 years in length. Often times, utilities do not actually begin paying for electricity under a contract for several years after the contract is completed since the renewable facility is not yet constructed. Utilities may sign a number of large contracts in one year and then only a few the next year. This all means the triggers that would require utilities to procure more or less renewable electricity may not come into play until several years after an IOU must make the actual procurement decisions and could result and less certainty and transparency for projects bidding into the RPS. Since procurement trends do not coincide well with an annual cap on costs, a cap based an utility's revenue in the past year multiplied by 10 to use as a 10-year cap may be a more effective means of monitoring SB 14 Page L above-market costs . Under current law, the cost cap is only applied to renewable contracts signed under a competitive solicitation process. It does not apply to any other efforts the IOUs took to procure renewable electricity, including signing bi-lateral contracts and purchasing electricity through standard offer contracts. These rules have created loopholes that allow utilities to sign a number of contracts that are not subject to the cost cap. The loophole means that the actual total costs of the RPS are not actually included in the mechanism intended to control above market costs. SB 14 leaves this loophole in place. The committee and the author may wish to clarify this by providing that the calculations of total above-market costs shall include all procurement activities that apply to a retail seller's RPS obligations . The caps on above-market costs in SB 14 only apply to the IOUs. As drafted, SB 14 does not provide the same cost protections to ESPs or the POUs. The committee and the author may wish to consider amending the bill to provide a similar cap on above-market costs for other retail sellers of electricity and for POU's. 5) Enforcement and off Ramps : Current law requires the PUC to enforce IOU and ESP compliance with the RPS. The PUC may fine an IOU or an ESP that fails to meet its year-to-year RPS target. The PUC has set the penalties at 5 cents per kilowatt hour by which the retail seller falls short of its RPS target. The PUC has capped the total amount of penalties that can be charged in a year at $25 million. Current law does not direct the use of these penalty monies, which will be deposited in the state General Fund. Current law also requires the PUC to develop rules of flexible compliance that would allow retail sellers to avoid penalties for non-compliance under certain conditions. The flexible compliance rules allow retail sellers to miss RPS goals in one year provided that it meets that goal within three years. This means that a retail seller will not be penalized for failing to meet the 20% by 2010 goal if it actually procures 20% of its power from renewable resources by 2013. A second flexible compliance rule allows the PUC to waive penalties for a retail seller if the PUC finds that there was SB 14 Page M insufficient transmission to meet the RPS goals. SB 14 provides that the PUC may grant a retail seller an additional two years to meet compliance targets if the PUC finds, after an evidentiary hearing, that there is inadequate transmission capacity to meet the RPS or there were unanticipated permitting delays for planned eligible renewable electricity projects. The retail seller must also show that it made reasonable efforts to procure cost effective distribute generation resources and to procure RECs. Under current law, there is no penalty or enforcement mechanism for POUs since there is no specific RPS mandate for the POUs. SB 14 provides that CARB may enforce penalties on the POUs if they fail to meet their RPS targets. 6) Publicly Owned Utilities : Current law does not require POUs to meet the same RPS that other electricity providers are required to meet. Rather, current law directs each POU to put in place and enforce its own RPS and allows each publicly owned utility to define the electricity sources that it counts as renewable. No state agency enforces POU compliance or places penalties on a publicly owned utility that fails to meet the renewable energy goals it has set for itself. SB 14 requires most POUs to meet the 33% RPS by 2020 requirement. While the bill requires each POU to set its own RPS, the bill also provides that the CEC shall establish a 33% RPS for each POU and enforce the RPS upon the establishment of the RPS standards. It also requires the CEC, in consultation with CARB, to adopt regulations for the enforcement of the RPS on POUs. CARB then has the authority to impose penalties on POUs for failure to comply with the RPS Most of the POUs do not object to creating a specific POU RPS mandate. However, they believe that they should be allowed to make most of the procurement decision on their own and the requiring the CEC to establish an RPS and regulations for enforcement is unnecessary and hinders their local control. The POUs have also argue that all penalty costs would simply result in a rate increase for their customers and would not result in helping that POU actually procure renewable resources. 7) Siting transmission and generation: Current law provides the SB 14 Page N CEC with theauthority to site electric thermal generation facilities with a capacity of greater than 50 MW. As part of compliance with the California Environmental Quality Act (CEQA), other state agencies provide input, such as the Coastal Commission and/or the Department of Fish and Game. A number of renewable generators do not fall under CEC jurisdiction because they are smaller than 50 MW or they do not use thermal technologies, and therefore, are approved and sited by local jurisdictions. Any major transmission lines needed to connect renewable regions of the state with the high-voltage transmission grid must be approved by the CalISO, the PUC, and the Federal Energy Regulatory Commission (FERC). If a generator or an IOU wants to develop a project on federal land, then the project must also be approved by at least one federal agency. Additionally, most POUs do not need approval from either the CalISO or the PUC to construct new transmission lines; instead, they follow their own local approval process This complex approval process has delayed the development of a number of proposed projects. There is evidence that even when one state agency wants to streamline approval of a specific process approval is almost always delayed once the agency has to coordinate activates with other state agencies or with the federal government. Using funds from a grant from the CEC, a group composed of representatives from renewable developers, utilities, environmental groups, land owners, the PUC, and the CEC began convening meetings over a year ago to develop long-term development and transmission plans for renewable energy in California. The group, know as the Renewable Energy Transmission Initiative (RETI), has already identified a number of Clean Renewable Energy Zones (CREZs) where there is large potential for renewable development and has started the work of fine tuning these zones and identifying specific transmission corridors that could be developed to connect the CREZs to the main transmission grid. While the RETI process includes participation from a broad range of interests including the CEC and the PUC, it is a stakeholder driven process that has not been subject to state open meeting laws. Consequently, it is likely that some parties that could be affected by the development of CREZs or transmission corridors have not had adequate opportunity to comment on the proceeding SB 14 Page O and that RETI has not developed a sufficient legal record to allow transmission and generation permitting agencies to adopt RETI recommendations without public review. SB 14 tries to address the problems in permitting new renewable generation and transmission by requiring: 1)The PUC to approve the application to construct a transmission line within one year of filing if the line is needed to provide transmission to achieve the goals of the RPS if the transmission line does not threaten substantial harm to the environment that necessitates a longer time for review under the CEQA. 2)Requires the CalISO to undertake all feasible efforts to cooperate with POUs and IOUs to develop statewide transmission plans that incorporate POU plans and potential joint transmission ownership plans between IOUs, POUs, and private entities. 3)Requires the CEC to facilitate the development of annual statewide transmission plans that incorporate POU transmission plans and IOU plans. 4)Requires the CEC to facilitate the siting and approval of new transmission lines that can be jointly owned by POUs, IOUs, and merchant generators. This last provision could be read to give the CEC authority to site transmission lines. The CEC does not have this authority under current law and instead the authority rests with the PUC or FERC. Without removing the PUCs authority, this provision could actually create another layer of complexity and delays to transmission siting. The committee and the author may wish to consider removing this new authority from the bill . 8) Transition Issues : SB 14 changes some of the current rules regarding what resources are eligible and how resources can be procured. Given the fact that these rule changes will impact already committed investments needed to build renewable resources, it is important that the transition from the current rules to the new rules is carefully addressed. A prior version of SB 14 addressed the transition from the current procurement rules to the new rules by allowing the current rules of procurement to continue to apply to procurement SB 14 Page P needed to meet the 20% RPS, and then applied the new rules to all procurement beyond 20%. The current version of SB 14 takes a more abrupt approach and changes the eligible rules for all renewable resources effective January 1, 2010, even for resources that are already under contract. SB 14 does contain grandfather clauses that allow utilities to continue to count renewable resources that are made ineligible by SB 14 toward their RPS obligations if the utility had signed a contract or procured actual electricity from the facilities prior to the passage of this bill. The clauses, however, appear to leave some gaps and could result in renewable resources that are already serving California load today or are under development to meet California's RPS being ruled ineligible under the new RPS rules. The PUC and Evolution Markets, a firm that runs markets for trading of REC, have both expressed concerns that retroactive nature of the transition clauses in the bill could hinder renewable development if current investments in renewable energy appears to not count toward California's RPS. 1)Technical amendments : 1) On page 10, line 13, strike "at least 20" and insert "33", Strike line 15 and insert "by December 31, 2020." 2) On page 13, line 39, strike "The" and replace "sold to" with "procured by" 3) Move definition of "delivered" located in the Public Resources code into the 399.12 of the Public Utilities Code. 4) On page 47, line 23, replace "may" with "shall" 5) On page 49, replace "may" with "shall" 6) On page 50, strike lines 9 through 25 7) On page 66, line 32, replace "report prepared pursuant to Section 910" with "reports prepared under SB 14." 8) On page 65, strike lines 1 - 28. REGISTERED SUPPORT / OPPOSITION : Support California Public Utilities Commission (CPUC) (if amended) California State Association of Electrical Workers SB 14 Page Q California State Pipe Trades Council California Wind Energy Association (CalWEA) (if amended) Coalition of California Utility Employees Natural Resources Defense Council (NRDC) (if amended) Planning and Conservation League (if amended) TURN (if amended) Union of Concerned Scientists (UCS) (if amended) Western States Council of Sheet Metal Workers Opposition California Biomass Energy Alliance California Manufacturers & Technology Association (CMTA) City of Roseville Clean Power Campaign Covanta Energy Evolution Markets, Inc. (unless amended) Independent Energy Producers Pacific Power (unless amended) Renewable Alliance Terra-Gen Power Western States Petroleum Association (WSPA) (unless amended) Analysis Prepared by : Edward Randolph / U. & C. / (916) 319-2083