AB 64 (Krekorian, Bass & Blakeslee) - Energy: renewable energy resources: generation and transmission

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STATE OF CALIFORNIA		Public Utilities Commission San Francisco
M e m o r a n d u m
Date:	February 11, 2009

To:	The Commission (Meeting of February 20, 2009)

From:	Pamela Loomis, Director Office of Governmental Affairs (OGA) - Sacramento

Subject:	AB 64 (Krekorian, Bass & Blakeslee) - Energy: renewable energy resources: generation and transmission As introduced: December 9, 2008

LEGISLATIVE SUBCOMMITTEE RECO: OPPOSE UNLESS AMENDED

SUMMARY OF BILL:

This bill would modify the Renewable Portfolio Standard (RPS) program to, among other things, increase the minimum amount of renewable energy that must be procured by retail sellers and publicly owned utilities to 25% of their retail deliveries by 2015 and 35% by 2020, with a goal of 50% by 2035. This bill would also modify the feed in tariff (FiT) program for small scale renewable facilities by, among other things, increasing the size of eligible facilities from 1.5 MW to 5 MW. Finally, this bill would create the Renewable Infrastructure Authority (RIA) to plan, site, and permit, as well as potentially finance, own and operate, renewable generation and transmission facilities.

SUMMARY OF SUPPORTING ARGUMENTS FOR RECOMMENDATION:

The CPUC supports the advancement of the renewable portfolio standard beyond 20% by 2010 towards a goal of 33% by 2020.¹ Indeed, the Commission considers increased procurement from renewable sources to be a critical element of meeting AB 32's emission reduction goals and greening California's power production and consumption. However, the CPUC is concerned that this bill is overly prescriptive and will impede the Commission's ability to react to market conditions in order to support utility compliance while preserving ratepayer cost protections. The Commission would prefer RPS legislation that is simple and flexible. The CPUC will continue to work with the Legislature and the Governor to design a workable statutory framework for advancing RPS.

DIVISION ANALYSIS (Energy Division):

A. Renewable Portfolio Standard (RPS) program (Articles 1 - 5)

This bill would require the implementation of higher RPS targets in 2015 and 2020, with a higher goal in 2035, and would modify several aspects of program implementation.

Increased RPS Targets

This bill would require investor-owned utilities (IOUs), energy service providers (ESPs), and publicly-owned utilities (POUs) to increase their procurement of renewable energy to 25% of retail sales by 2015 and 35% by 2020, with a goal of 50% by 2035.

Although the CPUC supports increasing the RPS beyond 20%, it remains concerned about mandating hard targets without conducting analysis on the feasibility of attaining the targets, given potential supply, transmission availability, and permitting timelines in California. The CPUC recommends either: 1) requiring retail providers to annually increase their renewable procurement by a set percentage of delivered energy per year (i.e. 1.5%) without mandating 35% by 2020; OR 2) mandating 25% by 2015 and 33% by 2020 without requiring annual incremental increases. The CPUC strongly encourages the Legislature and Governor to consider building into any statutory framework an opportunity for a mid-course correction. For example, this bill could be amended to require the CPUC to report to the Legislature and Governor before the end of 2015 on the costs and benefits of the RPS program during the five year period of 2010 through 2014. Based on this information, the Legislature and Governor could reassess the viability of proceeding to 33% by 2020 based on actual data from the program.

Eligibility

Proposed PU Code section 953 states that to be eligible for the RPS program, a facility either has to be located in state or, if located out of state, has to deliver its energy to California. However, in Article 5, this bill would also allow renewable energy credits (RECs) without a delivery requirement to count for the RPS program.

Suggested amendment: Modify proposed PU Code section 953 to allow: 1) bundled delivered energy; and 2) REC-only transactions from out of state facilities with no delivery requirement. Further, keep existing language that gives the CPUC the authority to determine the appropriate cap on such REC-only transactions.

Existing PU Code section 953(b)(4) requires facilities that do not have their first point of interconnection in California, and that are located outside of the United States, to be "developed and operated in a manner that is as protective of the environment as a similar facility located in the state." This provision should also apply to facilities located outside the United States but have their first point of interconnection in California.

Suggested amendment: Add the language from proposed PU Code section 953(b)(4) to 953(a) in order to be consistent. Without this change, facilities that are located in Mexico, but have their first point of interconnection in California, would not be required to operate in the environmentally-preferable manner prescribed in section 953(b)(4).

Procurement Plan and Contract Evaluation Methodologies

Proposed PU Code section 962 is overly detailed and complex. Rather than prescribe the requirements for renewable energy procurement plans, bid solicitations, contract duration, and the like, the statute should establish the basic framework for procurement planning and evaluation and allow the CPUC to promulgate the details according to experience and market conditions.

For example, proposed PU Code section 962(b) requires a utility's RPS Procurement Plan to include a methodology for ranking renewable energy projects bid into its solicitation. The language says that the methodology should be proposed "so that each electrical corporation's total renewables portfolio benefits ratepayers." This provision is unclear. Under current law (PU Code section 701.1), the Commission is already required to consider ratepayer impacts when evaluating proposed utility Procurement Plans.

Suggested amendment: If the Legislature believes it is necessary to include a statement regarding ratepayer benefits in section 962(b), the CPUC recommends eliminating "so that each electrical corporation's total renewables portfolio benefits ratepayers" and replacing it with a period followed by: "This process shall consider, but shall not be limited to, the cost impact of procuring the eligible renewable energy resources on the electrical corporation's electricity portfolio, system reliability, and the environmental and economic benefits and costs of procuring renewable energy."

"California supplier"

The CPUC generally supports a Western regional approach to increasing renewable generation, and, as such, is cautious about proposed preferential treatment of in-state renewable energy resources over out-of-state resources. A national RPS program is supported by the new U.S. President, and will likely be adopted by Congress. California, as a renewable-rich state, has the potential to be a renewable energy exporter in the future. The state should be cautious about setting a precedent among its sister states for in-state preferential treatment.

Specifically, the language in proposed PU Code section 962(g) relating to "California supplier" seems to have been gleaned from another PU Code that was specifically written for the Self Generation Incentive Program to provide preference to a California fuel cell manufacturer. This language does not translate well to other renewable resource types. Also, it would be complex, impractical, and inefficient for the CPUC to implement this preference when it is reviewing contracts. If the Legislature decides to move forward with this preference, then it should instead require the utility to incorporate a preference for a "project located in California" (perhaps as an "adder") as part of its bid evaluation process in proposed PU Code §962(b).

Cost Containment Mechanism

The CPUC is committed to cost containment within the RPS program. Pursuant to PU Code §701.1, the CPUC has an obligation to ensure that the principal goal of electric utilities' resource planning and investment is to minimize the cost to society of reliable electric services, and to improve the environment and to encourage renewable energy resources.

However, the CPUC generally supports replacing the Market-Price Referent (MPR) approach to cost containment, which essentially caps the amount by which a renewable energy contract's costs can exceed those of gas-fired alternatives. Stakeholders have rightly questioned why there should be a cap on what the state pays for renewable energy when there is not a cap on the cost of fossil-fired power. In the present context of climate policy, the more appropriate comparison may be between renewable energy costs and those of other GHG reduction measures.

Proposed PU Code section 963 would adopt a "benchmark price" to evaluate the price of renewable energy contracts by comparing them to non-renewable alternatives. Unfortunately, a benchmark price would suffer from the same problems as the MPR that it is intended to replace. Also like the MPR, the CPUC's development of a benchmark price would require a complex calculation and invite significant litigation.

Instead, the CPUC should develop a methodology to evaluate individual contract prices, as this is the CPUC's most fundamental responsibility. Pursuant to PU Code section 454.5, the CPUC has existing authority to approve IOU Procurement Plans and contracts that comply with the Plan. Renewable procurement should be treated no differently than other forms of procurement, which are evaluated based on comparable market prices and the reasonableness of project costs relative to other projects bid into the same solicitation.

Commission staff has presented a proposal in the context of the Long Term Procurement Planning proceeding to use a long term portfolio analysis to evaluate all utility procurement decisions from the perspective of cost, system reliability, and greenhouse gas impact. This approach would be consistent with the CPUC's existing statutory authority and could potentially support comparisons with other GHG reduction measures within the electric sector.

Suggested amendments:

Delete the last sentence of proposed PU Code §963(b), which requires the cost limitation to be calculated as a percentage of a utility's revenue requirement. This method of total cost limitation is overly prescriptive and could result in complicated rules that are difficult to administer.

Delete proposed PU Code §963(c): it would not be a rational policy to allow all retail sellers to limit their procurement because one utility exceeded its cost limitation.

Delete proposed PU Code §963(d): This clause was necessary in previous legislation because certain contracts (e.g. bilaterals) did not count toward the cost limitation. However, the CPUC may wish to require all contracts to count towards a utility's cost limitation.

Renewable Energy Credits (RECs)

The CPUC generally supports tradeable RECs, and the use of out-of-state RECs with no delivery requirement.

The CPUC supports allowing RECs as a procurement tool because, given the long lead time for building projects in California, allowing RECs would increase the liquidity of the renewables market, which, in turn, could lead to a more competitive market and lower RPS compliance costs. It would also facilitate compliance for some retail sellers, at a potentially lower cost, because signing long-term energy contracts doesn't fit the business model of smaller retail sellers.

A delivery requirement is not necessary because it creates complexity without creating a hedging benefit for ratepayers. Bundled contracts should have a requirement of delivery of the energy to California because they provide a hedging benefit since the underlying energy is bought at a fixed price. However, out-of-state eligible REC contracts should not have a delivery requirement because REC contracts implicitly never provide a hedging benefit because, by definition, the utility buying the REC is not buying the energy. Because RECs provide other benefits to ratepayers, however, we support allowing their use to reach 33%.

Also, the proposed section's concept of a declining percentage over time of RECs with no delivery requirement moves away from the preferred outcome of this procurement tool - a robust renewables and REC market that allows for cost-effective compliance to the benefit of ratepayers.

Suggested amendments: If the Legislature wishes to have a broadly applicable RPS program that takes advantage of the GHG reduction potential of renewables in the Western Region as a whole, REC-only contracts associated with energy not delivered to California should be included in the definition of "procure" in proposed PU Code section 952(d) as follows:

"Procure" means that a retail seller or local publicly owned electric utility contracts for renewable energy credits or receives delivered electricity generated by an eligible renewable energy resource that it owns or for which it has entered into an electricity purchase agreement.

B. Feed in Tariff (FiT) for Small-Scale Renewables (Article 6)

The CPUC generally supports the use of FiTs for small-scale renewable distributed generation facilities. Under the Commission's existing program (established by AB 1969 of 2006, and modified by SB 380 of 2008), the CPUC has established feed-in tariffs for energy generated by an eligible renewable electric generation facility of no more than 1.5 MW, at a price established at the "market price referent" and adjusted by the Commission for time of delivery.

This bill would modify the program to raise the applicable facility size from 1.5 MW to 5 MW, to require the facilities to be strategically located near load, and to allow the Commission to adjust the price for "any other attributes of renewable generation." This bill would also require publicly-owned utilities with 75,000 or more customers to offer this tariff, which they are currently not required to do.

The CPUC has an open proceeding on FiTs (R.08-08-009) in which it is considering whether: facilities up to 20 MW should be allowed to take the tariff; performance standards in FiT contracts should be changed; or third party ownership should be allowed.

This bill seems to be aimed at providing the CPUC with additional flexibility in its implementation of the FiT program. But it may inadvertently limit the CPUC's ability to maintain a viable program in the future. As such, the Commission recommends the following:

· Allow the Commission flexibility to set the total program cap in conjunction with the needs of the RPS program and according to the total capacity needs identified in the long-term procurement planning proceeding.

· Allow the Commission flexibility to designate a per project size, up to 20 MW per project, for the FiT program.

· Allow the Commission flexibility to determine the price paid for projects under the FiT based on the best available information in the RPS contracting pool. Delete any references to market price referent (MPR) and "attributes of renewable generation" as the basis for determining price. Delete any references to "indifference."

· Allow the Commission to set the price above avoided cost provided that the "above market funds" are kept within the same cost cap or cost containment mechanism that applies to the rest of the Renewable Portfolio Standard (RPS) program. Cost containment for the FiT program should be addressed as part of the Commission's regular procurement-related activities.

· Omit discussion of third-party ownership from statute since it is currently under consideration at the Commission. The Commission should be able to retain discretion over what types of ownership structures are required at the facilities that are eligible to participate in the FiT program.

Suggested amendment: Repeal PU Code section 399.20 since this bill's proposed PU Code section 985 is duplicative.

C. Renewable Infrastructure Authority (Article 7)

Developing an Annual Renewables Investment Plan

Under AB 64, RIA would be responsible for developing an Annual Renewables Investment Plan and take into account, among other things, reliability, resource adequacy, storage, demand reduction opportunities, environmental quality, and a "least cost electrical supply plan." In fact, such broader planning criteria and objectives are, and will continue to be, explicitly and extensively addressed by the CPUC in fulfilling its responsibilities regarding ratemaking and reliability of service. This includes the CPUC's administration of resource adequacy and long term procurement programs, which are being increasingly coordinated with California ISO activities, in terms of planning assumptions, scenarios and results, especially to address transmission and system integration implications of renewable resource priorities.

Thus, besides duplicating existing efforts, any renewable energy plans or priorities produced by the RIA would need to be coordinated and mutually consistent with other resource planning activities that are legally required and go beyond the scope of the RIA. If AB 64 were to transfer the renewable resource planning function which is an essential component of over-all utility supply planning, to a new entity, the CPUC would not be able to fulfill its constitutionally mandated duty to fully regulate electric rates. These interdependencies are a major reason for CPUC's close involvement and interest in transmission planning and transmission access issues.

The CPUC's long term procurement planning process is in the midst of refinement to more explicitly and robustly address renewable energy priorities, options and risks, incorporating information from RETI, from RPS procurement and CAISO interconnection results to date, and from the CAISO's transmission planning process and assessment of renewables integration challenges. It is not clear how RIA would result in improved renewable resource planning.

Funding Renewable Infrastructure Development

If RIA funds certain projects and thus takes a financial or other interest in certain renewable generation projects (or transmission) within a capital intensive renewable generation market that is hoped to be competitive and innovative, there can very well be a perception and even a reality of the RIA having an elevated interest in expediting those projects in which the RIA invests, as well as the associated transmission. Not surprisingly, we have already encountered complaints that California's efforts to prioritize renewable generation areas and associated transmission are going too fast in "picking winners and losers." Such complaints will become more forceful and more difficult to counter if the permitting entity itself has a financial interest in certain projects but not others.

Transmission Planning and Permitting

Among other things, RIA would "....designate and prioritize renewable energy and associated transmission corridor zones, certify (site and permit) all renewable generators above 5 MW and all transmission".² The bill would give the new RIA "exclusive power to certify all electric transmission lines..." As discussed below, it is neither appropriate nor legally possible to separate the CPUC's transmission certification authority from its overall ratemaking authority, such as to transfer that authority to another entity.

The need for a new transmission line and its environmental impacts are tightly intertwined with the project's costs and its impact on retail electric rates paid by California utility customers. These factors are interrelated and must be balanced. Since transmission remains a regulated monopoly in California, transmission projects currently subject to CPUC jurisdiction are being proposed primarily by monopoly utility providers. When a regulated utility is authorized to build a transmission line, it is also guaranteed recovery of its costs plus a rate of return. In order to protect consumers from unreasonable rate increases, the review and approval of a new transmission line must include an analysis of not only its environmental impacts as required under CEQA, but also an analysis of its impacts on rates as required under the CPUC's ratemaking responsibilities.

As part of its constitutional authority to regulate public utility rates, the CPUC has the authority to certify (site and permit) electric transmission facilities proposed to be built by regulated public utilities. The California Attorney General has expressly found that the CPUC's authority to site transmission lines, as described in Public Utilities Code sections 1001, 1003, and 1005, is constitutional in nature. (Attorney General letter to Little Hoover Commission, June 23, 2005, pp. 6-9.)

Thus, neither the governor nor the legislature can legally remove constitutionally-granted functions from the CPUC.³ Accordingly, exclusive power to certify transmission facilities cannot be transferred to the new RIA.

The complexity of environmental issues and coordination with federal agencies in transmission permitting

Because of the specific locations of California's high quality renewable resources, transmission lines to access those resources will very often require approvals from federal land management agencies and/or Native American tribes. The main reason that the transmission permitting process is so time consuming is the complexity of environmental issues, the existing legal requirements to address such impacts and the need to coordinate such environmental reviews with federal agencies that are not under the same time constraints as California agencies. RIA would not avoid or reduce this complexity.

Enhancing efficiency and coordination among various agencies

The CPUC has recently streamlined its permitting process, including increased attention to pre-filing activity such that when an application reaches the CPUC, it is more likely to be complete or nearly so.

The statewide collaborative Renewable Energy Transmission Initiative (RETI) involves the CPUC, CEC, CAISO, transmission owners, load serving entities, and renewable energy developers. It is providing important input to the transmission planning and permitting process both at the CPUC and CAISO programs. A new RIA, designating and prioritizing renewable resource zones and associated transmission corridors and projects, would duplicate both RETI's purpose and its outputs. It is unclear how the two would be reconciled and coordinated, or how ongoing resource and transmission planning processes which are being coordinated and preparing to use RETI information, would accommodate yet another source of renewable resource priorities and plans. Basically, it is unclear why it would be necessary or desirable to overlay an entirely new renewable energy prioritization process on top of RETI.

The CPUC supports and participates in the CAISO's transmission planning process and supports improved joint planning and operating ("seams") arrangements between the CAISO and non-CAISO transmission owners. CPUC staff also participate extensively in FERC proceedings regarding transmission access, planning, and cost recovery, since these matters tend to be both FERC jurisdictional and of considerable import to ratepayers and other California interests.

RIA's role, among other things, in identifying sites for transmission and performing "environmental, engineering and feasibility" studies, is duplicative of exiting efforts and would have to be reconciled with existing transmission planning processes and requirements, particularly the California ISO's FERC-regulated, FERC-approved open planning process and responsibilities⁴, which entail numerous provisions and requirements for participation, nondiscrimination, transparency and coordination with other planning entities. This is embedded within broader west-wide transmission planning centered on WECC and involves numerous procedures and requirements to maintain system reliability as well as communication and cooperation among transmission operators. WECC and individual transmission operators are all responsible to NERC and ultimately to FERC, for planning and operating standards and practices that impact reliability. (And, most do impact reliability.) The RIA's new planning role would have to address the transparency, nondiscrimination and collaboration requirements for transmission planning required by FERC's Order 890⁵ and embodied in the CAISO's recently reformed planning process.

In summary, the RIA would become another layer in transmission planning, necessarily having to be reconciled and explicitly coordinated with existing layers. Furthermore, the transmission planning role envisioned for the RIA involves only renewable energy objectives, and would in any event have to be incorporated into the bigger transmission planning picture, including wider economic and reliability issues.

Proposed RIA will slow things down

The proposed RIA would slow things down by switching to a new method of deriving renewable resource and transmission priorities relative to priorities being established via RETI, via the CAISO's interconnection queue and planning process, and via the CPUC-administered long term procurement process including RPS solicitations. These processes are being increasingly coordinated and already represent more than enough renewable generation projects to meet the 33% goal. It is unlikely that five years from now the RIA could reach the state of effectiveness that the present interacting processes will reach with the progress already made.

Additionally, the different proposed RIA functions each require substantial public process that must attain nontrivial levels of efficiency, transparency and stakeholder confidence. As previously discussed, most proposed RIA functions are already being performed elsewhere, and, in fact, they already incorporate effective and established public process, whether it be via the CPUC's long term procurement and transmission permitting processes, the CAISO's transmission planning and other stakeholder processes, or via RETI. It would be challenging, laborious, contentious, arguably infeasible, and, what is most important, unnecessary, to recreate these multiple dimensions of public process at a reasonable level of efficiency within a single new multi-dimensional organization, in a short time.

Transmission Cost recovery

In the process of permitting transmission projects, the CPUC establishes cost caps, and as a result of Decision 06-06-034 (implementing Public Utilities Code § 399.25), may approve eligibility for recovery in retail rates of transmission costs incurred in support of renewable energy goals in the event FERC disallows recovery. The CPUC also participates on behalf of California interests in proceedings through which FERC approves rates for recovery of transmission costs, including costs of major projects permitted by the CPUC.

Establishing Charges to Recover Rates

AB 64 would authorize RIA to establish and collect charges for the projects funded by it including energy production. CPUC is the entity constitutionally responsible for setting energy rates for all customers of CPUC jurisdictional investor owned utilities. The transmission component of these rates is established by FERC and is included in CPUC approved rates. RIA would have no legal authority to establish or collect such charges.

PROGRAM BACKGROUND:

RPS Program

The RPS program was adopted in SB 1078 (2002), and subsequently modified by SB 107 (2006) and SB 1036 (2007). The CPUC is statutorily responsible for 1) requiring each utility to submit an RPS Procurement Plan, 2) adopting a pricing benchmark to evaluate RPS contracts, 3) adopting a process that utilities must use to evaluate renewable energy projects bid into their solicitations, 4) adopting RPS compliance rules, 5) reviewing and approving or rejecting utilities' RPS contracts, and 6) reporting to the Legislature, on a quarterly basis, on the RPS program. The CPUC has adopted approximately 30 decisions to implement these aspects of the RPS program and has approved over 110 RPS contracts for nearly 7,000 megawatts (1,000 megawatts of which have already begun delivering RPS-eligible energy).

Every year, the utilities each submit an RPS Procurement Plan, which includes, in part, a description of their renewable energy procurement supply and demand and a description of how they will evaluate RPS bids. The CPUC evaluates and approves each Plan. Then, the utilities issue a request for offers to solicit for renewable energy project bids. After receiving the bids, the utilities rank each one, select which bids to negotiate with, and execute a number of contracts. The CPUC evaluates each executed contract in light of its compliance with the utility's Plan and other CPUC decisions, the reasonableness of the contract price, and the viability of the project. In order to contain the costs of the RPS program, if the contract price is at or below a CPUC-calculated price benchmark (based on the cost of a fossil fuel plant), the price is considered reasonable. However, if it exceeds the benchmark, the utility has a limited amount of funds that it can use towards those above-market contract costs.

The CPUC has also become involved in other activities to improve the RPS program, to coordinate with agencies statewide to facilitate renewable energy development in California, and to provide robust information to the public and Legislature on the progress of the RPS program and the trends in the renewable energy market. For example, we started the Renewable Energy Transmission Initiative (RETI), and involved the CEC, CAISO, developers, and environmental groups in order to facilitate statewide renewable transmission planning for new renewable energy projects. We maintain numerous databases of project characteristics and viability and produce robust analyses on the barriers facing renewable energy development. We have also begun an analysis of the feasibility and cost of a 33% RPS, which will result in a better understanding of the barriers and solutions for reaching a higher RPS target in California.

Feed-in-Tariff for Small Scale Renewables

Public Utilities Code § 399.20 requires each electrical corporation to establish a tariff for the purchase of electricity from an eligible renewable water or wastewater facility at a market price determined by the Commission. The Commission implemented § 399.20 by D. 07-07-027 on June 26, 2007. The decision adopted tariffs and standard contracts for the purchase of this electricity up to 1.5 MW from water and wastewater customers, and additionally it made the same program available to all other renewable customer generators in PG&E and SCE territory. Later, the Commission expanded the program to all customers in SDG&E's territory. The Commission's implementation of § 399.20 is considered phase 1 of the Tariff and Standard Contract Implementation for RPS Generators. The Commission is currently considering phase 2, which includes consideration of expanding the contract to facilities up to 20 MW under R.08-08-009.

On September 28, 2008, SB 380 amended Public Utilities Code § 399.20 to allow purchase of electricity for any eligible renewable electric facility and increased the statewide cap from 250 MW to 500 MW, and it removed any requirement that the tariff be available to water or wastewater facilities. Comments have been filed with the Commission concerning implementing the changes mandated in SB 380, and the Commission is currently working on a Decision to implement SB 380.

The California Energy Commission (CEC) has been investigating feed-in tariffs. They held staff workshops on June 30, 2008 and October 1, 2008 in order to discuss policy directions for feed-in tariffs. Prior to the October 1, 2008 workshop a draft consultant report was issued entitled "California Feed-in Tariff Design and Policy Options". Based on that report and workshops, the CEC has recommended that the Commission immediately implement a feed-in tariff program for all RPS-eligible generating facilities up to 20 MW in size. They recommend that such a program should include must-take provisions as well as cost-based technology-specific prices that generally decline over time and are not linked to the MPR.

As a part of R.08-08-009, the Commission's Energy Division staff issued a data request on January 28, 2008 in preparation for a workshop to be held on February 10, 2008. The purpose of the workshop is to determine if the existing feed-in tariff contract should require additional terms and conditions if the Commission were to expand the existing feed-in tariff contract from 1.5 MW up to 20 MW. Examples of additional terms and conditions include performance standards. Participants of the workshop will review the existing feed-in tariff contract, proposed additional terms and conditions, and parameters of terms and conditions. The workshop will result in clarification of party positions and identification of areas of consensus.

Transmission siting and permitting

Existing constitutional authority exists for CPUC jurisdiction over transmission siting and approval. Also, per the California Environmental Quality Act (CEQA), the CPUC has discretionary authority (CPCN process) regarding electric infrastructure owned and / or operated by investor owned utilities, therefore CPUC is the lead agency in preparing the environmental impact report (CEQA).

Currently, for siting transmission lines to be constructed by investor owned utilities, the IOU prepares a plan of service and submits it to the CAISO for approval. After the CAISO approves the project based on economic and reliability analysis, the IOU prepares an application and Proponent's Environmental Assessment (PEA) and submits it to the CPUC. Once the application is filed with and deemed complete by the CPUC, an environmental document is prepared. During the process of preparing the environmental document, the CPUC staff holds extensive public meetings and agency consultations in order to site a transmission line. Preparation of the environmental document and the CPUC's CPCN process take place concurrently. Eventually, the environmental document is used in the CPCN process. When the applicant receives the CPCN approval, they may start construction.

Currently, the CEC permits thermal power facilities greater than 50 MW. A developer files an application with the CEC and CEC staff reviews the application and determines if the application is adequate. When the application is adequate, the CEC staff prepares a draft and final staff assessment. When the Commission approves the application, the developer can construct the power facility.

CPUC staff currently participate in the CAISO's transmission planning process including issues related to renewable and other resource priorities as well as the need for and efficiency of transmission projects.

CPUC staff plays a leading role in the RETI process to prioritize renewable energy zones and associated transmission, and generally works closely with CAISO and stakeholders to coordinate supply and transmission planning on an increasingly forward-looking basis.

STATUS: This bill is currently in Assembly Utilities & Commerce Committee awaiting hearing. The bill has been double referred to the Assembly Natural Resources Committee as well.

SUPPORT/OPPOSITION:

Unknown.

STAFF CONTACTS:

Pamela Loomis, Director, OGA (916) 327-8441 pcl@cpuc.ca.gov

Date: February 11, 2009.

BILL LANGUAGE:

BILL NUMBER: AB 64 INTRODUCED

BILL TEXT

INTRODUCED BY Assembly Members Krekorian, Bass, and Blakeslee

DECEMBER 9, 2008

An act to amend Section 25500 of, and to repeal Chapter 4.3

(commencing with Section 25330) of Division 15 of, the Public

Resources Code, and to amend Section 454.5 of, to amend and repeal

Section 387 of, to add Section 399.23 to, to add Chapter 4.5

(commencing with Section 950) to Part 1 of Division 1 of, and to

repeal Article 16 (commencing with Section 399.11) of Chapter 2.3 of

Part 1 of Division 1 of, the Public Utilities Code, relating to

energy, and making an appropriation therefor.

LEGISLATIVE COUNSEL'S DIGEST

AB 64, as introduced, Krekorian. Energy: renewable energy

resources: generation and transmission.

(1) The Public Utilities Act imposes various duties and

responsibilities on the Public Utilities Commission with respect to

the purchase of electricity and requires the commission to review and

adopt a procurement plan and a renewable energy procurement plan for

each electrical corporation pursuant to the California Renewables

Portfolio Standard Program. The program requires that a retail seller

of electricity, including electrical corporations, community choice

aggregators, and electric service providers, but not including local

publicly owned electric utilities, purchase a specified minimum

percentage of electricity generated by eligible renewable energy

resources, as defined, in any given year as a specified percentage of

total kilowatthours sold to retail end-use customers each calendar

year (renewables portfolio standard). The renewables portfolio

standard requires each retail seller to increase its total

procurement of eligible renewable energy resources by at least an

additional 1% of retail sales per year so that 20% of its retail

sales are procured from eligible renewable energy resources no later

than December 31, 2010. Existing law requires the State Energy

Resources Conservation and Development Commission (Energy Commission)

to certify eligible renewable energy resources and to design and

implement an accounting system to verify compliance with the

renewables portfolio standard by retail sellers. Under existing law

the governing board of a local publicly owned electric utility is

responsible for implementing and enforcing a renewables portfolio

standard for the utility that recognizes the intent of the

Legislature to encourage renewable resources, while taking into

consideration the effect of the standard on rates, reliability, and

financial resources and the goal of environmental improvement.

This bill would recast the renewables portfolio standard program,

to be operative on January 1, 2011, to require that a retail seller

and a local publicly owned electric utility: (1) procure at least 20%

of the electricity delivered to its retail customers from eligible

renewable energy resources by December 31, 2010, (2) procure at least

25% of the electricity delivered to its retail customers from

eligible renewable energy resources by December 31, 2015, (3) procure

at least 35% of the electricity delivered to its retail customers

from eligible renewable energy resources by December 31, 2020, and

(4) have a goal of procuring at least 50% of the electricity

delivered to its retail customers from eligible renewable energy

resources by December 31, 2035. The commission would be responsible

for implementing these requirements for retail sellers, while the

governing board would be responsible for implementing these

requirements for a local publicly owned electric utility. The bill

would require the commission to establish annual procurement targets

for retail sellers that are sufficient to reach the above-stated

requirements. The bill would require that an electrical corporation's

renewable energy procurement plan include a process that provides

criteria for the rank ordering and selection of eligible renewable

energy resources to comply with the above-stated procurement

requirements so that each corporation's total renewables portfolio

benefits ratepayers. The bill would require the commission to

annually establish and adopt a benchmark price for electricity

generated by an eligible renewable energy resource, for terms

corresponding to the length of contracts, in consideration of

specified matter, and for each electrical corporation, to establish a

limitation on the total costs expended above the benchmark prices

for procurement of electricity pursuant to the renewables portfolio

standard. The bill would require the commission to allow an

electrical corporation or other retail seller to limit its

procurement to the quantity of eligible renewable energy resources

that can be purchased at or below the cost limitation if insufficient

to support the total costs expended above the benchmark price. The

bill would revise existing law with respect to the use of renewable

energy credits to meet the renewables portfolio standard procurement

requirements to and would allow retail sellers and local publicly

owned electric utilities to utilize a declining percentage of credits

earned on electricity that is not delivered, as defined, to the

state.

Existing law requires every electrical corporation to file with

the commission a standard tariff for electricity generated by an

electric generation facility, as defined, that is owned and operated

by a retail customer of the electrical corporation. Existing law

requires that the electric generation facility: (1) have an effective

capacity of not more than 1.5 megawatts and be located on property

owned or under the control of the customer, (2) be interconnected and

operate in parallel with the electric transmission and distribution

grid, (3) be strategically located and interconnected to the electric

transmission system in a manner that optimizes the deliverability of

electricity generated at the facility to load centers, and (4) meet

the definition of an eligible renewable energy resource under the

California Renewables Portfolio Standard Program. Existing law

requires that the tariff provide for payment for every kilowatthour

of electricity generated by an electric generation facility at a

market price referent established by the commission pursuant to the

program. Existing law requires the electrical corporation to make

this tariff available to customers that own and operate an electric

generation facility within the service territory of the electrical

corporation, upon request, on a first-come-first-served basis, until

the combined statewide cumulative rated generating capacity of those

electric generation facilities equals 500 megawatts, or the

electrical corporation meets its proportionate share of the 500

megawatt limit based upon the ratio of its peak demand to total

statewide peak demand of all electrical corporations. Existing law

authorizes the commission to modify or adjust the above-described

requirements for any electrical corporation with less than 100,000

service connections, as individual circumstances merit. Existing law

provides that the electricity generated by an electric generation

facility counts toward the electrical corporation's renewables

portfolio standard and provides that the physical generating capacity

counts toward meeting the electrical corporation's resource adequacy

requirements.

This bill would instead require an electrical corporation to file

with the commission a standard tariff for the electricity purchased

from a small-scale renewable distributed generation facility, as

defined, that is owned, leased, or rented by a retail customer of the

electrical corporation. The bill would revise the first requirement,

discussed above, to instead require that the small-scale renewable

distributed generation facility have an effective capacity of not

more than 5 megawatts, subject to the authority of the commission to

reduce this megawatt limitation, discussed below. The bill would

require that the tariff provide for a base payment rate for every

kilowatthour of electricity purchased from a small-scale renewable

distributed generation facility at the benchmark price established by

the commission pursuant to the California Renewables Portfolio

Standard Program, for a period of 10, 15, or 20 years, as authorized

by the commission. The bill would authorize the commission to adjust

the payment rate to reflect the value of the electricity on a

time-of-delivery basis and any other attributes of renewable

generation and require, with respect to rates and charges, that

ratepayers that do not receive service pursuant to the tariff are

indifferent, with respect to rates and charges, to whether other

ratepayers receive service pursuant to the tariff. The bill would

require the electrical corporation to make the tariff available to

any customer that owns, leases, or rents a small-scale renewable

distributed generation facility within the service territory of the

electrical corporation, upon request, on a first-come-first-served

basis, until the combined statewide cumulative rated generating

capacity of those facilities subject to tariffs with electrical

corporations reaches 500 megawatts, or its proportionate share of

that limit. The bill would provide that the electricity purchased

from a small-scale renewable distributed generation facility count

toward meeting the electrical corporation's renewables portfolio

standard and that electricity generated by the small-scale renewable

distributed generation facility count toward meeting the electrical

corporation's resource adequacy requirements. The bill would require

the commission, in consultation with the ISO, to monitor and examine

the impact on the transmission and distribution grid and any effects

upon ratepayers resulting from small-scale renewable distributed

generation facilities operating pursuant to the bill's provisions,

would require the commission to establish performance standards for

any small-scale renewable distributed generation facility that has a

capacity greater than one megawatt to ensure that those facilities

are constructed, operated, and maintained to generate the expected

annual net production of electricity and do not impact system

reliability, and would authorize the commission to reduce the 5

megawatt capacity limitation if the commission finds that a reduced

capacity limitation is necessary to maintain system reliability

within that electrical corporation's service territory. The bill

would recast the existing authority of the commission to modify or

adjust the above-described requirements for any electrical

corporation with less than 100,000 service connections, as individual

circumstances merit.

This bill would require a local publicly owned electric utility

that sells electricity at retail to 75,000 or more customers to adopt

and implement a tariff for electricity purchased from a small-scale

renewable distributed generation facility meeting certain size,

deliverability, and interconnection requirements and to consider

certain factors. The bill would require the local publicly owned

electric utility to make the tariff available to customers that own

and operate a small-scale renewable distributed generation facility

within the service territory of the utility, upon request, on a

first-come-first-served basis, until the combined statewide

cumulative rated generating capacity of those small-scale renewable

distributed generation facilities, subject to tariffs with local

publicly owned electric utilities, reaches 250 megawatts. The bill

would provide that the electricity purchased from a small-scale

renewable distributed generation facility count toward meeting the

local publicly owned electric utility's renewables portfolio standard

annual procurement targets.

(2) Existing law creates the California Consumer Power and

Conservation Financing Authority, with powers and responsibilities as

prescribed, including the issuance of revenue bonds, for the

purposes of augmenting electric generating facilities and to ensure a

sufficient and reliable supply of electricity, financing incentives

for investment in cost-effective energy-efficient appliances and

energy demand reduction, achieving a specified energy capacity

reserve level, providing financing for the retrofit of inefficient

electric powerplants, and renewable energy and conservation. Existing

law creates in the State Treasury the California Consumer Power and

Conservation Financing Authority Fund, and continuously appropriates

all money in the fund, except as specified, for the support of the

authority. Existing law prohibits the authority from approving any

new program, enterprise, or project, on or after January 1, 2007,

unless authority to approve such an activity is granted by statute

enacted on or before January 1, 2007.

This bill would establish the Renewables Infrastructure Authority,

with powers and responsibilities as prescribed, including the

issuance of revenue bonds of up to $6,400,000,000, for the purposes

of financing projects and programs, as defined, to build eligible

renewable energy resources and electric transmission lines, as

defined, to deliver the electricity generated to retail customers.

The authority would have a 9-member governing board, as prescribed.

The bill would establish the Renewables Infrastructure Authority Fund

and continuously appropriate moneys in the fund, except as

specified, for the authority's purposes.

The bill would authorize the authority to designate an area as a

renewable energy designation zone, as defined. Each city or county

would be required to consider the designated zone when making a

determination regarding a land use change within or adjacent to the

zone that could affect its continuing viability to accommodate energy

generation facilities, related transmission lines, transmission

corridor zones, or other facilities appurtenant to the designated

zone. Notwithstanding provisions of law that give the Energy

Commission authority to certify certain thermal powerplants and

related facilities, the authority would have the authority to certify

all sites and related facilities in a designated renewable energy

designation zone, including new sites and related facilities and

changes or additions to an existing facility.

The bill would authorize the authority to certify all electric

transmission lines, remote resource interconnection lines, electric

transmission facilities and facilities appurtenant thereto, and

related facilities in the state, except any electric transmission

lines or facilities appurtenant thereto for which the commission has

issued a certificate of public convenience and necessity, or which

any municipal utility has approved, before January 1, 2010, and

electric transmission lines that connect generation facilities to the

high-voltage transmission grid that are under the certification

authority of the Energy Commission.

(3) Existing law authorizes the Energy Commission to designate a

transmission corridor zone on its own motion or by application of a

person who plans to construct a high-voltage electric transmission

line within the state. Existing law provides that the designation of

a transmission corridor shall serve to identify a feasible corridor

where a future transmission line can be built that is consistent with

the state's needs and objectives as set forth in the strategic plan

adopted by the commission. Existing law prescribes procedures for the

designation of a transmission corridor zone, including publication

of the request for designation and request for comments, coordination

with federal agencies and California Native American tribes,

informational hearings, and requirements for a proposed decision.

This bill would repeal these provisions of law, and would give to

the Renewables Infrastructure Authority the authority to designate

transmission corridor zones.

(4) Under existing law, a violation of the Public Utilities Act or

an order or direction of the commission is a crime. Because some of

the provisions of this bill would require an order or other action of

the commission to implement its provisions, and a violation of that

order or action would be a crime, the bill would impose a

state-mandated local program by creating a new crime. By placing

additional requirements upon local publicly owned electric utilities,

which are entities of local government, and new requirements upon

city and county governments, the bill would impose a state-mandated

local program.

The California Constitution requires the state to reimburse local

agencies and school districts for certain costs mandated by the

state. Statutory provisions establish procedures for making that

reimbursement.

This bill would provide that no reimbursement is required by this

act for specified reasons.

Vote: majority. Appropriation: yes. Fiscal committee: yes.

State-mandated local program: yes.

THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:

SECTION 1. Chapter 4.3 (commencing with Section 25330) of Division

15 of the Public Resources Code is repealed.

SEC. 2. Section 25500 of the Public Resources Code is amended to

read:

25500. (a) In accordance with the

provisions of this division, and except as otherwise provided in

Article 7 (commencing with Section 990) of Chapter 4.5 of Part 1 of

Division 1 of the Public Utilities Code, the commission shall

have the exclusive power to certify all sites and related facilities

in the state, whether a new site and related facility or a change or

addition to an existing facility. The issuance of a certificate by

the commission shall be in lieu of any permit, certificate, or

similar document required by any state, local or regional agency, or

federal agency to the extent permitted by federal law, for such use

of the site and related facilities, and shall supersede any

applicable statute, ordinance, or regulation of any state, local, or

regional agency, or federal agency to the extent permitted by federal

law.

~~After~~

(b) After the effective date of

this division, no construction of any facility or modification of any

existing facility shall be commenced without first obtaining

certification for any such site and related facility by the

commission, as prescribed in this division.

SEC. 3. Section 387 of the Public Utilities Code is amended to

read:

387. (a) Each governing body of a local publicly owned electric

utility shall be responsible for implementing and enforcing a

renewables portfolio standard that ~~recognizes the intent of~~

~~the Legislature to encourage renewable resources, while taking into~~

~~consideration the effect of the standard on rates, reliability, and~~

~~financial resources and the goal of environmental improvement.~~

accomplishes all of the following:

(1) Procures at least 20 percent of the electricity delivered to

its retail customers from eligible renewable energy resources, as

defined in Section 952, by December 31, 2010.

(2) Procures at least 25 percent of the electricity delivered to

its retail customers from eligible renewable energy resources, as

defined in Section 952, by December 31, 2015.

(3) Procures at least 35 percent of the electricity delivered to

its retail customers from eligible renewable energy resources, as

defined in Section 952, by December 31, 2020.

(4) Establishes a goal of procuring at least 50 percent of the

electricity delivered to its retail customers from eligible renewable

energy resources, as defined in Section 952, by December 31, 2035.

(b) Each local publicly owned electric utility shall report, on an

annual basis, to its customers and to the State Energy Resources

Conservation and Development Commission, all of the

following:

(1) Expenditures of public goods funds collected pursuant to

Section 385 for eligible renewable energy resource development.

Reports shall contain a description of programs, expenditures, and

expected or actual results.

(2) The resource mix used to serve its customers by fuel type.

Reports shall contain the contribution of each type of renewable

energy resource with separate categories for those fuels that are

eligible renewable energy resources as defined in Section 399.12,

except that the electricity is delivered to the local publicly owned

electric utility and not a retail seller. Electricity shall be

reported as having been delivered to the local publicly owned

electric utility from an eligible renewable energy resource when the

electricity would qualify for compliance with the renewables

portfolio standard if it were delivered to a retail seller.

(3) The utility's status in implementing a renewables portfolio

standard pursuant to subdivision (a) and the utility's progress

toward attaining the standard following implementation.

(c) This section shall remain in effect only until January 1,

2011, and as of that date is repealed, unless a later enacted

statute, that is enacted before January 1, 2011, deletes or extends

that date.

SEC. 4. Section 399.23 is added to the Public Utilities Code, to

read:

399.23. This article shall remain in effect only until January 1,

2011, and as of that date is repealed, unless a later enacted

statute, that is enacted before January 1, 2011, deletes or extends

that date.

SEC. 5. Section 454.5 of the Public Utilities Code is amended to

read:

454.5. (a) The commission shall specify the allocation of

electricity, including quantity, characteristics, and duration of

electricity delivery, that the Department of Water Resources shall

provide under its power purchase agreements to the customers of each

electrical corporation, which shall be reflected in the electrical

corporation's proposed procurement plan. Each electrical corporation

shall file a proposed procurement plan with the commission not later

than 60 days after the commission specifies the allocation of

electricity. The proposed procurement plan shall specify the date

that the electrical corporation intends to resume procurement of

electricity for its retail customers, consistent with its obligation

to serve. After the commission's adoption of a procurement plan, the

commission shall allow not less than 60 days before the electrical

corporation resumes procurement pursuant to this section.

(b) An electrical corporation's proposed procurement plan shall

include, but not be limited to, all of the following:

(1) An assessment of the price risk associated with the electrical

corporation's portfolio, including any utility-retained generation,

existing power purchase and exchange contracts, and proposed

contracts or purchases under which an electrical corporation will

procure electricity, electricity demand reductions, and

electricity-related products and the remaining open position to be

served by spot market transactions.

(2) A definition of each electricity product, electricity-related

product, and procurement related financial product, including support

and justification for the product type and amount to be procured

under the plan.

(3) The duration of the plan.

(4) The duration, timing, and range of quantities of each product

to be procured.

(5) A competitive procurement process under which the electrical

corporation may request bids for procurement-related services,

including the format and criteria of that procurement process.

(6) An incentive mechanism, if any incentive mechanism is

proposed, including the type of transactions to be covered by that

mechanism, their respective procurement benchmarks, and other

parameters needed to determine the sharing of risks and benefits.

(7) The upfront standards and criteria by which the acceptability

and eligibility for rate recovery of a proposed procurement

transaction will be known by the electrical corporation prior to

execution of the transaction. This shall include an expedited

approval process for the commission's review of proposed contracts

and subsequent approval or rejection thereof. The electrical

corporation shall propose alternative procurement choices in the

event a contract is rejected.

(8) Procedures for updating the procurement plan.

(9) A showing that the procurement plan will achieve the

following:

(A) The electrical corporation will, in order to fulfill its unmet

resource ~~needs and in furtherance of Section 701.3, until a~~

~~20 percent renewable resources portfolio is achieved, procure~~

~~renewable energy resources with the goal of ensuring that at least an~~

~~additional 1 percent per year of the electricity sold by the~~

~~electrical corporation is generated from renewable energy resources,~~

~~provided sufficient funds are made available pursuant to Sections~~

~~399.6 and 399.15, to cover the above-market costs for new renewable~~

~~energy resources~~ needs, procure resources from

eligible renewable energy resources in an amount sufficient to meet

its procurement requirements and goals pursuant to the renewables

portfolio standard .

(B) The electrical corporation will create or maintain a

diversified procurement portfolio consisting of both short-term and

long-term electricity and electricity-related and demand reduction

products.

needs through all available energy efficiency and demand reduction

resources that are cost effective, reliable, and feasible.

(10) The electrical corporation's risk management policy,

strategy, and practices, including specific measures of price

stability.

(11) A plan to achieve appropriate increases in diversity of

ownership and diversity of fuel supply of nonutility electrical

generation.

(12) A mechanism for recovery of reasonable administrative costs

related to procurement in the generation component of rates.

electrical corporation's procurement plan. The commission's review

shall consider each electrical corporation's individual procurement

situation, and shall give strong consideration to that situation in

determining which one or more of the features set forth in this

subdivision shall apply to that electrical corporation. A procurement

plan approved by the commission shall contain one or more of the

following features, provided that the commission may not approve a

feature or mechanism for an electrical corporation if it finds that

the feature or mechanism would impair the restoration of an

electrical corporation's creditworthiness or would lead to a

deterioration of an electrical corporation's creditworthiness:

(1) A competitive procurement process under which the electrical

corporation may request bids for procurement-related services. The

commission shall specify the format of that procurement process, as

well as criteria to ensure that the auction process is open and

adequately subscribed. Any purchases made in compliance with the

commission-authorized process shall be recovered in the generation

component of rates.

(2) An incentive mechanism that establishes a procurement

benchmark or benchmarks and authorizes the electrical corporation to

procure from the market, subject to comparing the electrical

corporation's performance to the commission-authorized benchmark or

benchmarks. The incentive mechanism shall be clear, achievable, and

contain quantifiable objectives and standards. The incentive

mechanism shall contain balanced risk and reward incentives that

limit the risk and reward of an electrical corporation.

(3) Upfront achievable standards and criteria by which the

acceptability and eligibility for rate recovery of a proposed

procurement transaction will be known by the electrical corporation

prior to the execution of the bilateral contract for the transaction.

The commission shall provide for expedited review and either approve

or reject the individual contracts submitted by the electrical

corporation to ensure compliance with its procurement plan. To the

extent the commission rejects a proposed contract pursuant to this

criteria, the commission shall designate alternative procurement

choices obtained in the procurement plan that will be recoverable for

ratemaking purposes.

(d) A procurement plan approved by the commission shall accomplish

each of the following objectives:

(1) Enable the electrical corporation to fulfill its obligation to

serve its customers at just and reasonable rates.

(2) Eliminate the need for after-the-fact reasonableness reviews

of an electrical corporation's actions in compliance with an approved

procurement plan, including resulting electricity procurement

contracts, practices, and related expenses. However, the commission

may establish a regulatory process to verify and assure that each

contract was administered in accordance with the terms of the

contract, and contract disputes which may arise are reasonably

resolved.

(3) Ensure timely recovery of prospective procurement costs

incurred pursuant to an approved procurement plan. The commission

shall establish rates based on forecasts of procurement costs adopted

by the commission, actual procurement costs incurred, or combination

thereof, as determined by the commission. The commission shall

establish power procurement balancing accounts to track the

differences between recorded revenues and costs incurred pursuant to

an approved procurement plan. The commission shall review the power

procurement balancing accounts, not less than semiannually, and shall

adjust rates or order refunds, as necessary, to promptly amortize a

balancing account, according to a schedule determined by the

commission. Until January 1, 2006, the commission shall ensure that

any overcollection or undercollection in the power procurement

balancing account does not exceed 5 percent of the electrical

corporation's actual recorded generation revenues for the prior

calendar year excluding revenues collected for the Department of

Water Resources. The commission shall determine the schedule for

amortizing the overcollection or undercollection in the balancing

account to ensure that the 5 percent threshold is not exceeded. After

January 1, 2006, this adjustment shall occur when deemed appropriate

by the commission consistent with the objectives of this section.

(4) Moderate the price risk associated with serving its retail

customers, including the price risk embedded in its long-term supply

contracts, by authorizing an electrical corporation to enter into

financial and other electricity-related product contracts.

(5) Provide for just and reasonable rates, with an appropriate

balancing of price stability and price level in the electrical

corporation's procurement plan.

(e) The commission shall provide for the periodic review and

prospective modification of an electrical corporation's procurement

plan.

(f) The commission may engage an independent consultant or

advisory service to evaluate risk management and strategy. The

reasonable costs of any consultant or advisory service is a

reimbursable expense and eligible for funding pursuant to Section

631.

(g) The commission shall adopt appropriate procedures to ensure

the confidentiality of any market sensitive information submitted in

an electrical corporation's proposed procurement plan or resulting

from or related to its approved procurement plan, including, but not

limited to, proposed or executed power purchase agreements, data

request responses, or consultant reports, or any combination,

provided that the Office of Ratepayer Advocates and other consumer

groups that are nonmarket participants shall be provided access to

this information under confidentiality procedures authorized by the

commission.

(h) Nothing in this section alters, modifies, or amends the

commission's oversight of affiliate transactions under its rules and

decisions or the commission's existing authority to investigate and

penalize an electrical corporation's alleged fraudulent activities,

or to disallow costs incurred as a result of gross incompetence,

fraud, abuse, or similar grounds. Nothing in this section expands,

modifies, or limits the State Energy Resources Conservation and

Development Commission's existing authority and responsibilities as

set forth in Sections 25216, 25216.5, and 25323 of the Public

Resources Code.

(i) An electrical corporation that serves less than 500,000

electric retail customers within the state may file with the

commission a request for exemption from this section, which the

commission shall grant upon a showing of good cause.

(j) (1) Prior to its approval pursuant to Section 851 of any

divestiture of generation assets owned by an electrical corporation

on or after ~~the date of enactment of the act adding this~~

~~section~~ September 24, 2002 , the commission

shall determine the impact of the proposed divestiture on the

electrical corporation's procurement rates and shall approve a

divestiture only to the extent it finds, taking into account the

effect of the divestiture on procurement rates, that the divestiture

is in the public interest and will result in net ratepayer benefits.

(2) Any electrical corporation's procurement necessitated as a

result of the divestiture of generation assets on or after

~~the effective date of the act adding this subdivision~~

September 24, 2002, shall be subject to the mechanisms and

procedures set forth in this section only if its actual cost is less

than the recent historical cost of the divested generation assets.

(3) Notwithstanding paragraph (2), the commission may deem

proposed procurement eligible to use the procedures in this section

upon its approval of asset divestiture pursuant to Section 851.

SEC. 6. Chapter 4.5 (commencing with Section 950) is added to Part

1 of Division 1 of the Public Utilities Code, to read:

CHAPTER 4.5. CALIFORNIA RENEWABLES PORTFOLIO STANDARD PROGRAM

Article 1. General Provisions and Definitions

950. The Legislature finds and declares all of the following:

(a) In order to attain a target of generating 35 percent of total

retail sales of electricity in California from eligible renewable

energy resources by December 31, 2020, and the goal of generating 50

percent by December 31, 2035, and for the purposes of the Legislative

goals of the renewables portfolios standard, the commission, the

Energy Commission, and each local publicly owned electric utility

shall implement the California Renewables Portfolio Standard Program

described in this chapter.

(b) A renewables portfolio standard that requires each retail

supplier of electricity in California to meet at least 35 percent of

its retail sales of electricity in California from eligible renewable

resources is necessary to:

(1) Reduce emissions of greenhouse gases and California's

contribution to global warming.

(2) Reduce the in-state consumption of nonrenewable fuels in order

to improve the public health and air quality throughout the state.

(3) Stimulate sustainable economic development, encourage

innovation in energy technologies, and create new employment

opportunities.

(4) Increase fuel diversity and promote greater stability and

predictability in electricity prices for consumers.

infrastructure may be necessary to ensure reliability, relieve

transmission congestion, and meet future growth in load and energy

resources, including renewable energy resources.

(d) It is the policy of this state and the intent of the

Legislature that adequate investments are made in a timely manner to

facilitate the attainment of the renewable portfolio standard and to

ensure that the state's electrical transmission system continues to

operate in an efficient and reliable manner.

952. For purposes of this chapter, the following terms have the

following meanings:

(a) "Conduit hydroelectric facility" means a facility for the

generation of electricity that uses only the hydroelectric potential

of an existing pipe, ditch, flume, siphon, tunnel, canal, or other

manmade conduit that is operated to distribute water for a beneficial

use.

(b) "Delivered" and "delivery" have the same meaning as provided

in subdivision (a) of Section 25741 of the Public Resources Code.

generating facility that uses biomass, solar energy, wind,

geothermal, fuel cells using renewable fuels, small hydroelectric

generation of 30 megawatts or less, digester gas, landfill gas, ocean

wave, ocean thermal, or tidal current, and any additions or

enhancements to the facility using that technology, and that meets

the general eligibility requirements of Section 953 and, when

applicable, the requirements for specific renewable energy sources of

Section 954.

(d) "Procure" means that a retail seller receives delivered

electricity generated by an eligible renewable energy resource that

it owns or for which it has entered into an electricity purchase

agreement. Nothing in this chapter is intended to imply that the

purchase of electricity from third parties in a wholesale transaction

is the preferred method of fulfilling a retail seller's obligation

to comply with this chapter.

(e) (1) "Renewable energy credit" means a certificate of proof,

issued through the accounting system established by the Energy

Commission pursuant to Section 970, that one unit of electricity was

generated and delivered by an eligible renewable energy resource.

(2) "Renewable energy credit" includes all renewable and

environmental attributes associated with the production of

electricity from the eligible renewable energy resource, except for

an emissions reduction credit issued pursuant to Section 40709 of the

Health and Safety Code and any credits or payments associated with

the reduction of solid waste and treatment benefits created by the

utilization of biomass or biogas fuels.

(f) "Renewable generator" means the owner or operator of an

eligible renewable energy resource with the authority to contract for

the electricity generated by the facility.

(g) "Renewables portfolio standard" means the specified percentage

of electricity generated by eligible renewable energy resources that

a retail seller or local publicly owned electric utility is required

to procure pursuant to this chapter.

(h) (1) "Retail seller" means an entity engaged in the retail sale

of electricity to end-use customers located within the state,

including any of the following:

(A) An electrical corporation.

(B) A community choice aggregator. The commission shall institute

a rulemaking to determine the manner in which a community choice

aggregator will participate in the renewables portfolio standard

program subject to the same terms and conditions applicable to an

electrical corporation.

commission shall determine the manner in which electric service

providers will participate in the renewables portfolio standard

program. The electric service provider shall be subject to the same

terms and conditions applicable to an electrical corporation pursuant

to this chapter. Nothing in this paragraph shall impair a contract

entered into between an electric service provider and a retail

customer prior to the suspension of direct access by the commission

pursuant to Section 80110 of the Water Code.

(2) "Retail seller" does not include any of the following:

(A) A corporation or person employing cogeneration technology or

producing electricity consistent with subdivision (b) of Section 218.

(B) The Department of Water Resources acting in its capacity

pursuant to Division 27 (commencing with Section 80000) of the Water

Code.

(i) "WECC" means the Western Electricity Coordinating Council.

953. To be eligible for meeting the renewables portfolio

standard, an eligible renewable energy resource shall satisfy one of

the following requirements:

(a) The facility is located in the state or near the border of the

state with the first point of connection to the transmission network

within this state and electricity produced by the facility is

delivered to an in-state location.

(b) The facility has its first point of interconnection to the

transmission network outside the state and satisfies all of the

following requirements:

(1) It is connected to the transmission network within the WECC

service territory.

(2) Electricity produced by the facility is delivered to an

in-state location.

(3) It will not cause or contribute to any violation of a

California environmental quality standard or requirement.

(4) If the facility is outside of the United States, it is

developed and operated in a manner that is as protective of the

environment as a similar facility located in the state.

(5) It participates in the accounting system to verify compliance

with the renewables portfolio standard by retail sellers, once

established by the Energy Commission pursuant to subdivision (a) of

Section 975.

(6) It commences initial commercial operation after January 1,

2005.

(3), (4), and (5) in subdivision (b), but does not meet the

requirements of paragraph (6) because it commences initial operation

prior to January 1, 2005, if the facility satisfies either of the

following requirements:

(1) The electricity is from incremental generation resulting from

expansion or repowering of the facility.

(2) The facility has been part of the existing baseline of

eligible renewable energy resources of the retail seller or local

publicly owned electric utility.

954. (a) (1) Except as provided in paragraph (2), a hydroelectric

generation facility that is larger than 30 megawatts is not an

eligible renewable energy resource.

(2) The incremental increase in the amount of electricity

generated from a hydroelectric generation facility as a result of

efficiency improvements at the facility, is electricity from an

eligible renewable energy resource, without regard to the electrical

output of the facility, if all of the following conditions are met:

(A) The incremental increase is the result of efficiency

improvements from a retrofit that do not result in an adverse impact

on instream beneficial uses or cause a change in the volume or timing

of streamflow.

(B) The hydroelectric generation facility has, within the

immediately preceding 15 years, received certification from the State

Water Resources Control Board pursuant to Section 401 of the Clean

Water Act (33 U.S.C. Sec. 1341), or has received certification from a

regional board to which the state board has delegated authority to

issue certification, unless the facility is exempt from certification

because there is no potential for discharge into waters of the

United States.

January 1, 2007, the efficiency improvements are initiated on or

after January 1, 2008, the efficiency improvements are not the result

of routine maintenance activities, as determined by the Energy

Commission, and the efficiency improvements were not included in any

resource plan sponsored by the facility owner prior to January 1,

2008.

(D) All of the incremental increase in electricity resulting from

the efficiency improvements are demonstrated to result from a

long-term financial commitment by the retail seller or local publicly

owned electric utility.

For purposes of this paragraph, "long-term financial commitment"

means either new ownership investment in the facility by the retail

seller or local publicly owned electric utility, or a new or renewed

contract with a term of 10 or more years, which includes procurement

of the incremental generation.

(b) (1) Except for a conduit hydroelectric generation facility

operating pursuant to subdivision (c), a hydroelectric generation

facility of 30 megawatts or less that was in operation prior to

January 1, 2006, shall be eligible only if a retail seller or local

publicly owned electric utility procured the electricity from the

facility as of December 31, 2005.

(2) A hydroelectric generation facility of 30 megawatts or less

that becomes operational on or after January 1, 2006, is not eligible

if it will cause an adverse impact on instream beneficial uses or

cause a change in the volume or timing of streamflow.

(3) A small hydroelectric generation facility that satisfies the

criteria for an eligible renewable energy resource pursuant to this

subdivision shall not lose its eligibility if efficiency improvements

undertaken after January 1, 2008, cause the generating capacity of

the facility to exceed 30 megawatts, and the efficiency improvements

do not result in an adverse impact on instream beneficial uses or

cause a change in the volume or timing of streamflow. The entire

generating capacity of the facility shall be eligible.

that commenced operation before January 1, 2006, is an eligible

renewable energy resource.

(2) A conduit hydroelectric generation facility of 30 megawatts or

less that becomes operational on or after January 1, 2006, is an

eligible renewable energy resource unless it will cause an adverse

impact on instream beneficial uses or cause a change in the volume or

timing of streamflow.

(d) A facility engaged in the combustion of municipal solid waste

using a noncombustion thermal process to convert solid waste to a

clean-burning fuel for the purpose of generating electricity is an

eligible renewable energy resource only if it meets the following

conditions:

(1) It is located in Stanislaus County and was operational prior

to September 26, 1996.

(2) The technology does not use air or oxygen in the conversion

process, except ambient air to maintain temperature control.

(3) The technology produces no discharges of air contaminants or

emissions, including greenhouse gases as defined in Section 42801.1

of the Health and Safety Code.

(4) The technology produces no discharges to surface or

groundwaters of the state.

(5) The technology produces no hazardous wastes.

(6) The technology removes all recyclable materials and marketable

green waste compostable materials from the solid waste stream prior

to the conversion process, to the maximum extent feasible, and the

owner or operator of the facility certifies that those materials will

be recycled or composted.

(7) The facility is in compliance with all applicable laws,

regulations, and ordinances.

(8) The technology meets any other conditions established by the

commission.

(9) The facility certifies that any local agency sending solid

waste to the facility diverted at least 30 percent of all solid waste

it collects through solid waste reduction, recycling, and

composting. For purposes of this paragraph, "local agency" means any

city, county, or special district, or subdivision thereof, which is

authorized to provide solid waste handling services.

955. This chapter shall become operative on January 1, 2011.

Article 2. Implementation of the Renewables Portfolio Standard

for Retail Sellers of Electricity Regulated by, or Registered with,

the Commission

960. In order to fulfill unmet long-term resource needs, the

commission shall establish a renewables portfolio standard requiring

each retail seller to increase its procurement of eligible renewable

energy resources to accomplish all of the following:

(1) Procure at least 20 percent of the electricity delivered to

its retail customers from eligible renewable energy resources.

(2) Procure at least 25 percent of the electricity delivered to

its retail customers from eligible renewable energy resources by

December 31, 2015.

(3) Procure at least 35 percent of the electricity delivered to

its retail customers from eligible renewable energy resources by

December 31, 2020.

(4) Establish a goal of procuring at least 50 percent of the

electricity delivered to its retail customers from eligible renewable

energy resources by December 31, 2035.

962. (a) The commission shall direct each electrical corporation

to prepare a renewable energy procurement plan to satisfy its

procurement requirements under the renewables portfolio standard. The

renewable energy procurement plan shall, to the extent feasible, be

proposed, reviewed, and adopted by the commission as part of, and

pursuant to, a general procurement plan process pursuant to Section

454.5. The commission shall require each electrical corporation to

review and update its renewable energy procurement plan as it

determines to be necessary.

(b) (1) The renewable energy procurement plan shall include a

process that provides criteria for the rank ordering and selection of

eligible renewable energy resources to comply with the renewables

portfolio standard procurement requirement so that each electrical

corporation's total renewables portfolio benefits ratepayers. This

process shall consider estimates of indirect costs associated with

needed transmission investments and ongoing utility expenses

resulting from integrating and operating eligible renewable energy

resources.

(2) The renewable energy procurement plan submitted by an

electrical corporation shall include all of the following:

(A) An assessment of annual or multiyear portfolio supplies and

demand to determine the optimal mix of eligible renewable energy

resources with deliverability characteristics that may include

peaking, dispatchable, baseload, firm, and as-available capacity.

(B) Provisions for employing available compliance flexibility

mechanisms established by the commission.

renewable energy resources of each deliverability characteristic,

required online dates, and locational preferences, if any.

electrical corporation shall offer standard terms and conditions to

be used in contracting with renewable generators for eligible

renewable energy resources, including performance requirements for

renewable generators. A contract for the purchase of electricity

generated by an eligible renewable energy resource shall, at a

minimum, include the renewable energy credits associated with all

electricity generation specified under the contract. The standard

terms and conditions of the contract shall include the requirement

that, no later than six months after the commission's approval of an

electricity purchase agreement entered into pursuant to this chapter,

the following information about the agreement shall be disclosed by

the commission: the names of the contracting parties, the renewable

energy resource type, the project location, and the generating

capacity of the project.

(d) (1) In soliciting and procuring eligible renewable energy

resources, each electrical corporation shall offer contracts of no

less than 10 years' duration, unless the commission approves of a

contract of shorter duration.

(2) The commission may authorize a retail seller to enter into a

contract of less than 10 years' duration with a renewable generator

for the electricity generated by an eligible renewable energy

resource, if the commission has established, for each retail seller,

minimum quantities of eligible renewable energy resources to be

procured either through contracts of at least 10 years' duration or

from new facilities commencing commercial operations on or after

January 1, 2005.

(e) The commission shall review and accept, modify, or reject each

electrical corporation's renewable energy procurement plan prior to

the commencement of renewable procurement pursuant to this chapter by

an electrical corporation.

(f) The commission shall review the results of a solicitation for

eligible renewable energy resources submitted for approval by an

electrical corporation and accept or reject proposed contracts with

the renewable generator based on consistency with the approved

renewable energy procurement plan. If the commission determines that

the bid prices are elevated due to a lack of effective competition

among the bidders, the commission shall direct the electrical

corporation to renegotiate the contracts or conduct a new

solicitation.

(g) (1) The commission shall provide preference to contracts for

renewable energy resources that are from a California supplier.

(2) For purposes of this paragraph, "California supplier" means

any sole proprietorship, partnership, joint venture, corporation, or

other business entity that manufactures eligible renewable energy

resources in California that are supplied to the renewable generator

and that meets either of the following criteria:

(A) The owners or policymaking officers are domiciled in

California and the permanent principal office, or place of business

from which the supplier's trade is directed or managed, is located in

California.

(B) A business or corporation, including those owned by, or under

common control of, a corporation, that meets all of the following

criteria continuously during the five years prior to providing

eligible renewable energy resources to a renewable generator:

(i) Owns and operates a manufacturing facility located in

California that builds or manufactures eligible renewable energy

resources.

(ii) Is licensed by the state to conduct business within the

state.

(iii) Employs California residents for work within the state.

(3) For purposes of qualifying as a California supplier, a

distribution or sales management office or facility does not qualify

as a manufacturing facility.

(h) Procurement and administrative costs associated with long-term

contracts entered into by an electrical corporation for eligible

renewable energy resources pursuant to this chapter and approved by

the commission shall be deemed reasonable per se by the commission,

and shall be recoverable in rates.

(i) If an electrical corporation fails to comply with a commission

order adopting a renewable energy procurement plan, the commission

shall exercise its authority pursuant to Section 2113 to require

compliance. The commission shall enforce comparable penalties on any

retail seller that is not an electrical corporation that fails to

meet renewables procurement requirements pursuant to Section 960.

963. (a) (1) The commission shall, by January 1, 2011, and

annually thereafter, establish and adopt a benchmark price for

electricity generated by an eligible renewable energy resource, for

terms corresponding to the length of contracts with renewable

generators, in consideration of the following:

(A) The long-term market price of electricity for all fixed-price

contracts determined pursuant to an electrical corporation's general

procurement activities as authorized by the commission.

(B) The value of different deliverability characteristics for

electricity, including baseload, peaking, dispatchable, firm, and

as-available electricity.

energy resources and the value of any other emissions reductions

that are not already accounted for pursuant to Section 40709 of the

Health and Safety Code.

(2) The benchmark price shall not include any indirect expenses,

including imbalance energy charges, sale of excess energy, decreased

generation from existing resources, or transmission upgrades.

(b) The commission shall, by January 1, 2011, for each electrical

corporation, establish a limitation on the total costs expended above

the benchmark prices determined in subdivision (a) for the

procurement of eligible renewable energy resources to achieve the

annual procurement targets established pursuant to this article. The

cost limitation shall not exceed ____ percent of the electrical

corporation's revenue requirement.

electrical corporation pursuant to subdivision (b) is insufficient to

support the total costs expended above the benchmark prices

determined pursuant to subdivision (a) for the procurement of

eligible renewable energy resources, the commission shall allow the

electrical corporation and other retail sellers to limit their

procurement to the quantity of eligible renewable energy resources

that can be procured at or below the benchmark prices.

(d) An electrical corporation may voluntarily propose to procure

eligible renewable energy resources at above the benchmark price that

are not counted toward the cost limitation. Any voluntary

procurement above the benchmark price shall be subject to commission

approval prior to the expense being recovered in rates.

964. (a) The commission may authorize a procurement entity to

enter into contracts on behalf of customers of a retail seller for

electricity generated by eligible renewable energy resources to meet

the retail seller's renewables portfolio standard procurement

requirements. The commission may not require any person or

corporation to act as a procurement entity or require any party to

purchase electricity generated by eligible renewable energy resources

from a procurement entity.

(b) The procurement entity shall, subject to review and approval

by the commission, recover reasonable administrative and procurement

costs through the retail rates of end-use customers that are served

by the procurement entity and are directly benefiting from the

procurement of electricity generated by eligible renewable energy

resources.

965. Construction, alteration, demolition, installation, and

repair work on an eligible renewable energy resource that receives

production incentives pursuant to Section 25742 of the Public

Resources Code, including work performed to qualify, receive, or

maintain production incentives is "public works" for the purposes of

Chapter 1 (commencing with Section 1720) of Part 7 of Division 2 of

the Labor Code.

Article 3. Implementation of the Renewables Portfolio Standard

for Local Publicly Owned Electric Utilities

970. (a) In order to fulfill unmet long-term resource needs, each

governing body of a local publicly owned electric utility shall be

responsible for implementing and enforcing a renewables portfolio

standard that accomplishes all of the following:

(1) Procures at least 20 percent of the electricity delivered to

its retail customers from eligible renewable energy resources.

(2) Procures at least 25 percent of the electricity delivered to

its retail customers from eligible renewable energy resources by

December 31, 2015.

(3) Procures at least 35 percent of the electricity delivered to

its retail customers from eligible renewable energy resources by

December 31, 2020.

(4) Establishes a goal of procuring at least 50 percent of the

electricity delivered to its retail customers from eligible renewable

energy resources by December 31, 2035.

(b) Each local publicly owned electric utility shall report, on an

annual basis, to its customers and to the Energy Commission, the

following:

(1) Expenditures of public goods funds collected pursuant to

Section 385 for eligible renewable energy resource development.

Reports shall contain a description of programs, expenditures, and

expected or actual results.

(2) The resource mix used to serve its customers by energy source.

(3) The utility's status in implementing a renewables portfolio

standard pursuant to subdivision (a) and the utility's progress

toward attaining the standard following implementation.

Article 4. Duties of the Energy Commission in Implementing the

Renewables Portfolio Standard

975. (a) The Energy Commission shall do all of the following:

(1) Design and implement an accounting system to verify compliance

with the renewables portfolio standard by retail sellers, to ensure

that electricity generated by an eligible renewable energy resource

is counted only once for the purpose of compliance with regulatory or

legal requirements of this state or any other state, for verifying

retail product claims in this state or any other state or to certify

renewable energy credits produced by eligible renewable energy

resources. In establishing the guidelines governing this accounting

system, the Energy Commission shall collect data from electricity

market participants that it deems necessary to verify compliance of

retail sellers, in accordance with the requirements of this article

and the California Public Records Act (Chapter 3.5 (commencing with

Section 6250) of Division 7 of Title 1 of the Government Code). In

seeking data from electrical corporations, the Energy Commission

shall request data from the commission. The commission shall collect

data from electrical corporations and remit the data to the Energy

Commission within 90 days of the request.

(2) Certify eligible renewable energy resources that it determines

meet the criteria described in subdivision (c) of Section 952, the

requirements of Section 953, and when applicable, the requirements of

Section 954.

(3) Establish a system for tracking and verifying renewable energy

credits that, through the use of independently audited data,

verifies the generation and delivery of electricity associated with

each renewable energy credit and protects against multiple counting

of the same renewable energy credit. The Energy Commission shall

consult with other western states and with the WECC in the

development of this system. No electricity generated by an eligible

renewable energy resource attributable to the use of nonrenewable

fuels, beyond a de minimus quantity, as determined by the Energy

Commission, shall result in the creation of a renewable energy

credit.

(b) The Energy Commission may, as part of the integrated energy

policy report adopted pursuant to Chapter 4 (commencing with Section

25300) of Division 15 of the Public Resources Code, recommend

additional technologies and resources to be included in the

definition of an eligible renewable energy resource for purposes of

this chapter.

Article 5. Renewable Energy Credits

980. (a) Subject to the conditions of this article, a retail

seller or local publicly owned electric utility may use renewable

energy credits from eligible renewable energy resources, that are

certified by the Energy Commission pursuant to Article 4, to comply

with the renewables portfolio standard procurement requirements.

(b) (1) Subject to the conditions of this article and the limits

of paragraphs (2), (3), and (4), a retail seller or local publicly

owned electric utility may use renewable energy credits from

renewable energy resources that meet all the criteria for eligibility

except the deliverability requirement of paragraph (2) of

subdivision (b) of Section 953, that are certified by the Energy

Commission pursuant to Article 4, to comply with the renewables

portfolio standard procurement requirements.

(2) From January 1, 2011, until the commission establishes a

reduced amount pursuant to paragraph (4), a retail seller or local

publicly owned electric utility may meet up to 50 percent of its

renewables portfolio standard procurement requirements with renewable

energy credits that do not meet the deliverability requirement of

paragraph (2) of subdivision (b) of Section 953.

(3) On and after January 1, 2018, a retail seller or local

publicly owned electric utility may meet up to 10 percent of its

renewables portfolio standard procurement requirements with renewable

energy credits that do not meet the deliverability requirement of

paragraph (2) of subdivision (b) of Section 953.

(4) The commission shall identify interim targets to gradually

decrease the use of renewable energy credits from the levels

authorized in paragraph (2) to those authorized in paragraph (3).

shall use renewable energy credits to comply with the renewables

portfolio standard procurement requirements pursuant to subdivision

(a) or (b) until the commission and the Energy Commission find that

the tracking system established pursuant to paragraph (3) of

subdivision (b) of Section 970, is operational, is capable of

independently verifying the electricity generated by an eligible

renewable energy resource and delivered to the retail seller or local

publicly owned electric utility, and can ensure that renewable

energy credits shall not be double counted for the purposes of

compliance with regulatory or legal requirements of this state or any

other state, or for verifying retail product claims in this state or

any other state.

(d) A renewable energy credit shall be counted only once for the

purposes of compliance with regulatory or legal requirements of this

state or any other state, or for verifying retail product claims in

this state or any other state, except that a renewable energy credit

may be used by a retail seller or local publicly owned electric

utility for both compliance with any federal renewable energy

portfolio requirement and for compliance with the renewables

portfolio standard pursuant to this chapter.

(e) A renewable energy credit shall either be used for purposes of

compliance with regulatory or legal requirements of this state or

any other state, or shall expire within 18 months of the date of

purchase by the retail seller or local publicly owned utility.

(f) No renewable energy credits shall be created for electricity

generated pursuant to any electricity purchase contract with a retail

seller or a local publicly owned electric utility executed before

January 1, 2005, unless the contract contains explicit terms and

conditions specifying the ownership or disposition of those credits.

Deliveries under those contracts shall be tracked through the

accounting system described in paragraph (3) of subdivision (b) of

Section 970 and included in the baseline quantity of eligible

renewable energy resources of a purchasing retail seller pursuant to

subdivision (b) of Section 960.

(g) No renewable energy credits shall be created for electricity

generated under any electricity purchase contract with a qualifying

facility executed after January 1, 2005, pursuant to the federal

Public Utility Regulatory Policies Act of 1978 (Public Law 95-617).

Deliveries under the electricity purchase contracts shall be tracked

through the accounting system described in paragraph (3) of

subdivision (b) of Section 970 and count toward the renewables

portfolio standard procurement requirements of the purchasing retail

seller or local publicly owned electric utility.

(h) The commission shall allow an electrical corporation to

recover in rates the reasonable costs of purchasing renewable energy

credits to meet its renewables portfolio standard procurement

requirements.

(i) All revenues received by an electrical corporation for the

sale of a renewable energy credit shall be credited to the benefit of

ratepayers.

Article 6. Small-Scale Renewable Distributed Generation

Facilities

985. The Legislature finds and declares all of the following:

(a) The state should encourage the reduction of electricity demand

at customer sites and increase generating capacity in order to meet

the demand for electricity.

(b) Some tariff structures and regulatory structures are

presenting a barrier to meeting the requirements and goals of this

chapter.

eligible renewable energy resources may face difficulties in

participating in competitive solicitations under the California

Renewables Portfolio Standard Program (Chapter 8.6 (commencing with

Section 25740) of Division 15 of the Public Resources Code).

(d) A tariff that allows customers of electrical corporations and

local publicly owned electric utilities to sell electricity generated

by renewable technologies would address these barriers and could

assist in the achievement of the renewables portfolio standard and

the state's goals for reducing emissions of greenhouse gases pursuant

to the California Global Warming Solutions Act of 2006 (Division

25.5 (commencing with Section 38500) of the Health and Safety Code).

(e) A tariff for electricity generated by renewable technologies

should recognize the environmental attributes of the renewable

technology, the characteristics that contribute to peak electricity

demand reduction, reduced transmission congestion, avoided

transmission and distribution improvements, and in a manner that

accelerates the deployment of renewable energy resources.

(f) It is the policy of this state and the intent of the

Legislature to encourage the distributed generation of electricity

from small-scale eligible renewable energy resources at the sites

where the electricity will be utilized.

986. As used in this article, "small-scale renewable distributed

generation facility" means an electric generation facility, owned,

leased, or rented by a retail customer of a retail seller or local

publicly owned electric utility, that meets all of the following

criteria:

(a) Has an effective capacity of not more than five megawatts and

is located on property owned or under the control of the customer.

Premises that are leased by the customer are under the control of the

customer for purposes of this requirement. It is not required that

the customer own the electric generation facility.

(b) Is interconnected and operates in parallel with the electric

transmission and distribution grid.

transmission system in a manner that optimizes the deliverability of

electricity generated at the facility to load centers.

(d) Is an eligible renewable energy resource.

987. (a) Every electrical corporation shall file with the

commission a standard tariff for electricity purchased from an

electric generation facility.

(b) The tariff shall provide for a base payment rate for every

kilowatthour of electricity purchased from a small-scale renewable

distributed generation facility at the benchmark price as determined

by the commission pursuant to Section 963 for a period of 10, 15, or

20 years, as authorized by the commission. The commission may adjust

the payment rate to reflect the value of every kilowatthour of

electricity generated

on a time-of-delivery basis and any other attributes of renewable

generation. The commission shall ensure that ratepayers that do not

receive service pursuant to the tariff are indifferent, with respect

to rates and charges, to whether a ratepayer with a small-scale

renewable distributed generation facility receives service pursuant

to the tariff.

to customers that own, lease, or rent a small-scale renewable

distributed generation facility within the service territory of the

electrical corporation, upon request, on a first-come-first-served

basis, until the combined statewide cumulative rated generating

capacity of those facilities reaches 500 megawatts. An electrical

corporation may make the terms of the tariff available to customers

in the form of a standard contract subject to commission approval.

Each electrical corporation shall only be required to offer service

or contracts under this section until that electrical corporation

meets its proportionate share of the 500 megawatts based on the ratio

of its peak demand to the total statewide peak demand.

(d) Every kilowatthour of electricity purchased from the electric

generation facility shall count toward the electrical corporation's

renewables portfolio standard annual procurement targets for purposes

of this chapter.

(e) The electricity generated by a small-scale renewable

distributed generation facility, consistent with Section 380, shall

count toward the electrical corporation's resource adequacy

requirement.

(f) (1) The commission, in consultation with the Independent

System Operator, shall monitor and examine the impact on the

transmission and distribution grid and any effects upon ratepayers

resulting from small-scale renewable distributed generation

facilities operating pursuant to a tariff or contract approved by the

commission pursuant to this section.

(2) The commission shall establish performance standards for any

small-scale renewable distributed generation facility that has a

capacity greater than one megawatt to ensure that those facilities

are constructed, operated, and maintained to generate the expected

annual net production of electricity and do not impact system

reliability.

(g) (1) The commission may modify or adjust the requirements of

this section for any electrical corporation with less than 100,000

service connections, as individual circumstances merit.

(2) The commission may reduce the five megawatt capacity

limitation of subdivision (a) of Section 986, if the commission finds

that a reduced capacity limitation is necessary to maintain system

reliability within that electrical corporation's service territory.

(h) (1) A customer electing to receive service under a tariff or

contract approved by the commission shall continue to receive service

under the tariff or contract until either of the following occurs:

(A) The customer no longer meets the eligibility requirements for

receiving service pursuant to the tariff or contract.

(B) The period of service established by the commission pursuant

to subdivision (b) is completed.

(2) Upon completion of the period of service established by the

commission pursuant to subdivision (b), the customer may elect to

renew receiving service pursuant to the tariff or contract approved

by the commission for the period of time then established by the

commission, or may elect to receive service under another then

applicable tariff.

988. (a) A local publicly owned electric utility that sells

electricity at retail to 75,000 or more customers shall adopt a

standard tariff for electricity purchased from a small-scale

renewable distributed generation facility.

(b) The governing board of the local publicly owned electric

utility shall ensure that the tariff adopted pursuant to subdivision

(b) reflects the value of every kilowatthour of electricity generated

on a time-of-delivery basis. The governing board may adjust this

value based on the other attributes of renewable generation. The

governing board shall ensure that ratepayers that do not receive

service pursuant to the tariff are indifferent, with respect to rates

and charges, to whether a ratepayer with a small-scale renewable

distributed generation facility receives service pursuant to the

tariff.

at retail to 75,000 or more customers shall make the tariff

available to customers that own, lease, or rent a small-scale

renewable distributed generation facility within the service

territory of the utility, upon request, on a first-come-first-served

basis, until the combined statewide cumulative rated generating

capacity of those facilities reaches 250 megawatts. A local publicly

owned electric utility may make the terms of the tariff available to

customers in the form of a standard contract. A local publicly owned

electric utility is only required to offer service or contracts under

this section until the utility meets its proportionate share of the

250 megawatts based on the ratio of its peak demand to the total

statewide peak demand.

(d) Every kilowatthour of electricity purchased from the a

small-scale renewable distributed generation facility shall count

toward the local publicly owned electric utility's renewables

portfolio standard procurement requirements for purposes of this

chapter.

(e) A local publicly owned electric utility may establish

performance standards for any small-scale renewable distributed

generation facility that has a capacity greater than one megawatt to

ensure that those facilities are constructed, operated, and

maintained to generate the expected annual net production of

electricity and do not impact system reliability.

(f) A local publicly owned electric utility may reduce the five

megawatt capacity limitation of subdivision (a) of Section 986, if

the utility finds that a reduced capacity limitation is necessary.

Article 7. Renewables Infrastructure Authority

990. (a) The Legislature finds and declares that in order to

furnish the citizens of California with a reliable and affordable

supply of electricity that integrates electricity generated from

eligible renewable energy resources consistent with the renewables

portfolio standard, and to protect the public health, welfare, and

safety, the state needs to finance, purchase, lease, own, operate,

acquire, or otherwise provide financial assistance for public and

private facilities for the generation and transmission of electricity

generated from eligible renewable energy resources.

(b) As used in this article, the following terms have the

following meanings:

(1) "Authority" means the Renewables Infrastructure Authority

established pursuant to Section 991 and any board, commission,

department, or officer succeeding to the functions thereof, or to

whom the powers conferred upon the authority by this article shall be

given by law.

(2) "Board" means the Board of Directors of the Renewables

Infrastructure Authority.

(3) "Bond purchase agreement" means a contractual agreement

executed between the authority and an underwriter or underwriters

and, where appropriate, a participating party, whereby the authority

agrees to sell bonds issued pursuant to this article.

(4) "Bonds" means bonds, including structured, senior, and

subordinated bonds or other securities; loans; notes, including bond

revenue or grant anticipation notes; certificates of indebtedness;

commercial paper; floating rate and variable maturity securities; and

any other evidences of indebtedness or ownership, including

certificates of participation or beneficial interest, asset backed

certificates, or lease-purchase or installment purchase agreements,

whether taxable or excludable from gross income for state and federal

income taxation purposes.

(5) "Cost," as applied to a program, project, or portion thereof

financed under this article, means all or any part of the cost of

construction, improvement, repair, reconstruction, renovation, and

acquisition of all lands, structures, improved or unimproved real or

personal property, rights, rights-of-way, franchises, licenses,

easements, and interests acquired or used for a project; the cost of

demolishing or removing or relocating any buildings or structures on

land so acquired, including the cost of acquiring any lands to which

the buildings or structures may be moved; the cost of all machinery

and equipment; financing charges; the costs of any environmental

mitigation; the costs of issuance of bonds or other indebtedness;

interest prior to, during, and for a period after, completion of the

project, as determined by the authority; provisions for working

capital; reserves for principal and interest; reserves for reduction

of costs for loans or other financial assistance; reserves for

maintenance, extension, enlargements, additions, replacements,

renovations, and improvements; and the cost of architectural,

engineering, financial, appraisal, and legal services, plans,

specifications, estimates, administrative expenses, and other

expenses necessary or incidental to determining the feasibility of

any project, enterprise, or program or incidental to the completion

or financing of any project or program.

(6) "Electric transmission line" means any electrical powerline

carrying electricity from a powerplant or renewable energy

designation zone located within the state to a point of junction with

any interconnected transmission system. Electric transmission line

may include any high-voltage electric transmission line pursuant to

Section 25330 of the Public Resources Code, and any replacement on

the site of existing electrical powerlines with electrical powerlines

equivalent to those existing electrical powerlines or the placement

of new or additional conductors, insulators, or accessories related

to those electrical powerlines on supporting structures in existence

on January 1, 2010, or certified pursuant to this article. Electric

transmission line may also include a remote resource interconnection

line to accommodate proposed location-constrained generation in a

designated renewable energy designation zone.

(7) "Enterprise" means a revenue-producing improvement, building,

system, plant, works, facilities, or undertaking used for or useful

for the generation or production of electricity for lighting,

heating, and power for public or private uses. Enterprise includes,

but is not limited to, all parts of the enterprise, all appurtenances

to it, lands, easements, rights in land, water rights, contract

rights, franchises, buildings, structures, improvements, equipment,

and facilities appurtenant or relating to the enterprise.

(8) "Feasible" means capable of being accomplished in a successful

manner within a reasonable period of time, taking into account

economic, environmental, social, and technological factors.

(9) "Financial assistance" in connection with a project,

enterprise or program, includes, but is not limited to, any

combination of grants, loans, the proceeds of bonds issued by the

authority, insurance, guarantees or other credit enhancements or

liquidity facilities, and contributions of money, property, labor, or

other things of value, as may be approved by resolution of the

board; the purchase or retention of authority bonds, the bonds of a

participating party for their retention or for sale by the authority,

or the issuance of authority bonds or the bonds of a special purpose

trust used to fund the cost of a project or program for which a

participating party is directly or indirectly liable, including, but

not limited to, bonds, the security for which is provided in whole or

in part pursuant to the powers granted by this division; bonds for

which the authority has provided a guarantee or enhancement; or any

other type of assistance determined to be appropriate by the

authority.

(10) "Fund" means the Renewables Infrastructure Authority Fund

created pursuant to Section 995.

(11) "Loan agreement" means a contractual agreement executed

between the authority and a participating party that provides that

the authority will loan funds to the participating party and that the

participating party will repay the principal and pay the interest

and redemption premium, if any, on the loan.

(12) "Participating party" means either of the following:

(A) Any person, company, corporation, partnership, firm, federally

recognized California Indian tribe, or other entity or group of

entities, whether organized for profit or not for profit, engaged in

business or operations within the state and that applies for

financial assistance from the authority for the purpose of

implementing a project or program in a manner prescribed by the

authority.

(B) Any subdivision of the state or local government, including,

but not limited to, departments, agencies, commissions, cities,

counties, nonprofit corporations, special districts, assessment

districts, and joint powers authorities within the state or any

combination of these subdivisions, that has, or proposes to acquire,

an interest in a project, or that operates or proposes to operate a

program and that makes application to the authority for financial

assistance in a manner prescribed by the authority.

(13) "Program" means a loan program that provides financial

assistance to a participating party to use for the purchase or lease

of eligible renewable energy resources.

(14) "Project" means plants, facilities, equipment, appliances,

structures, expansions, and improvements within the state that serve

the purposes of this article as approved by the authority, and all

activities and expenses necessary to initiate and complete those

projects.

(15) "Renewable energy designation zone" means the geographic area

necessary to accommodate the construction and operation of one or

more powerplants or other form of generation that operate using an

"eligible renewable energy resource" as defined in Section 952 and

where the backup fuel, such as oil and natural gas, does not, in the

aggregate, exceed 10 percent of the total energy output of the

facility during any calendar year period. A renewable energy

designation zone shall accommodate existing land uses and land uses

identified in local, general, or specific plans, and avoid

environmental constraints or mitigate potential environmental

impacts.

(16) "Revenues" means all receipts, purchase payments, loan

repayments, lease payments, rents, fees and charges, and all other

income or receipts derived by the authority from an enterprise, or by

the authority or a participating party from any other financing

arrangement undertaken by the authority or a participating party,

including, but not limited to, all receipts from a bond purchase

agreement, and any income or revenue derived from the investment of

any money in any fund or account of the authority or a participating

party.

(17) "State" means the State of California.

(18) "Transmission corridor zone" means the geographic area

necessary to accommodate the construction and operation of one or

more high-voltage electric transmission lines. A transmission

corridor zone shall not be more than 1,500 feet in width unless

required to accommodate existing land uses and land uses identified

in local, general, or specific plans, or to avoid environmental

constraints or mitigate potential environmental impacts.

Administrative Procedure Act, as defined in Section 11370 of the

Government Code.

991. (a) There is hereby created in the state government the

Renewables Infrastructure Authority, which shall be responsible for

administering this article. The authority shall implement the

purposes of this chapter and to that end, finance projects and

programs in pursuant to this article, all to the mutual benefit of

the people of the state and to protect their health, welfare, and

safety.

(b) The authority shall be governed by a nine-member board of

directors that shall consist of the following persons:

(1) The Secretary for Resources.

(2) Secretary for Environmental Protection.

(3) Chair of the Energy Commission.

(4) President of the commission.

(5) A member of the public appointed by the Governor and subject

to confirmation by the Senate. This member shall have considerable

experience in power generation, natural gas transportation or

storage, energy conservation, financing, or ratepayer advocacy.

(6) The State Treasurer.

(7) The president of the Independent System Operator governing

board.

(8) A designee of the Senate Pro Tem, who shall be a nonvoting

member.

(9) A designee of the Speaker of the Assembly, who shall be a

nonvoting member.

Five of the members shall constitute a quorum, and the affirmative

vote of four board members shall be necessary for any action to be

taken by the board.

(d) (1) The chairperson of the board shall be appointed by the

Governor.

(2) Except as provided in this subdivision, the members of the

board shall serve without compensation, but shall be reimbursed for

actual and necessary expenses incurred in the performance of their

duties to the extent that reimbursement for these expenses is not

otherwise provided or payable by another public agency, and shall

receive one hundred dollars ($100) for each full day of attending

meetings of the authority.

991.1. (a) The authority is authorized and empowered to do any of

the following:

(1) Adopt an official seal.

(2) Sue and be sued in its own name.

(3) Employ or contract with officers and employees to administer

the authority. The authority may contract for the services of a chief

executive officer, who shall serve at the pleasure of the board. If

the chief executive officer contracts for the services of any other

officer or employee, the contract shall be subject to the approval of

the board.

(4) Exercise the power of eminent domain.

(5) Adopt rules and regulations for the regulation of its affairs

and the conduct of its business.

(6) Do all things generally necessary or convenient to carry out

its powers and purposes under this article.

(b) The chief executive officer shall manage and conduct the

business and affairs of the authority and the fund subject to the

direction of the board. Except as otherwise provided in this section,

the board may assign to the executive director, by resolution, those

duties generally necessary or convenient to carry out its powers and

purposes under this article. The chief executive office may

designate a liaison to the federal government to facilitate, when

necessary, the implementation of its powers and duties. Any action

involving final approval of any bonds, notes, loans, or other

financial assistance shall require the approval of a majority of the

members of the board.

991.2. (a) The authority's operating budget shall be subject to

review and appropriation in the annual Budget Act. For purposes of

this section, the authority's operating budget shall include the

costs of personnel, administration, and overhead.

(b) The authority shall, on or before January 1 of each year,

prepare and submit to the Governor, the Chairperson of the Joint

Legislative Budget Committee, and the chairperson of the committee in

each house that considers appropriations, a report regarding its

activities and expenditures pursuant to this article.

effectiveness of the authority's efforts in achieving its purposes as

described in Section 991.3. The evaluation shall include

recommendations as to whether there is a continued need for the

authority beyond January 1, 2016. The evaluation shall be submitted

to the Governor and the Legislature on or before January 1, 2014.

991.3. The authority may only exercise its powers pursuant to

this article for the following purposes:

(a) Establish, finance, purchase, lease, own, operate, acquire, or

construct generating facilities that are eligible renewable energy

resources and other projects and enterprises to facilitate the state'

s renewable energy goals, on its own or through agreements with

public and private third parties or joint ventures with public or

private entities, or provide financial assistance for projects or

programs by participating parties, to supplement private and public

sector supplies of electricity, taking into account generation

facilities in operation or under development as of the effective date

of this section, and to ensure a sufficient and reliable supply of

electricity for California's consumers at just and reasonable rates.

(b) Finance programs, administered by the Energy Commission, the

commission, and other approved participating parties for consumers

and businesses to invest in cost-effective energy efficient

appliances, eligible renewable energy resources, and other programs

that will reduce the demand for energy in California or meet that

demand through generation from eligible renewable energy resources.

(d) Provide financing for owners of aged, inefficient, eligible

renewable energy resources to perform necessary retrofits to improve

the efficiency and environmental performance of those resources.

991.4. The authority may enter into any agreement or contract,

execute any instrument, and perform any act or thing necessary or

convenient to, directly or indirectly, secure the authority's bonds

or a participating party's obligations to the authority, including,

but not limited to, bonds of a participating party purchased by the

authority for retention or sale, with funds or moneys that are

legally available and that are due or payable to the participating

party by reason of any grant, allocation, apportionment, or

appropriation of the state or agencies thereof, to the extent that

the Controller shall be the custodian at any time of these funds or

moneys, or with funds or moneys that are or will be legally available

to the participating party, the authority, or the state or any

agencies thereof by reason of any grant, allocation, apportionment,

or appropriation of the federal government or agencies thereof; and

in the event of written notice that the participating party has not

paid or is in default on its obligations to the authority, direct the

Controller to withhold payment of those funds or moneys from the

participating party over which it is or will be custodian and to pay

the same to the authority or its assignee, or direct the state or any

agencies thereof to which any grant, allocation, apportionment, or

appropriation of the federal government or agencies thereof is or

will be legally available to pay the same upon receipt to the

authority or its assignee, until the default has been cured and the

amounts then due and unpaid have been paid to the authority or its

assignee, or until arrangements satisfactory to the authority have

been made to cure the default.

991.5. (a) The fiscal powers granted to the authority by this

article may be exercised without regard or reference to any other

department, division, or agency of the state, except the Legislature

or as otherwise stated in this article. This article shall be deemed

to provide an alternative method of doing the things authorized by

this article, and shall be regarded as supplemental and additional to

powers conferred by other laws.

(b) No member of the board or any person executing bonds of the

authority pursuant to this article shall be personally liable on the

bonds or subject to any personal liability or accountability by

reason of the issuance thereof.

project in carrying out this article shall be payable solely from

funds provided under the authority of this article and no liability

or obligation shall be imposed upon the State of California and, none

shall be incurred by the authority beyond the extent to which moneys

shall have been provided under this article. Under no circumstances

shall the authority create any debt, liability, or obligation on the

part of the State of California in connection with any enterprise or

project payable from any source whatsoever other than the moneys

provided under this article.

991.6. In connection with an enterprise, the authority may do any

or all of the following:

(a) Acquire any enterprise by gift, purchase, or eminent domain as

necessary to achieve the purposes of the authority pursuant to

Sections 991.3 and 992.1.

(b) Construct or improve any enterprise. By gift, lease, purchase,

eminent domain, or otherwise, it may acquire any real or personal

property, for an enterprise, except that no property of a state

public body may be acquired without its consent. The authority may

sell, lease, exchange, transfer, assign, or otherwise dispose of any

real or personal property or any interest in such property. It may

lay out, open, extend, widen, straighten, establish, or change the

grade of any real property or public rights-of-way necessary or

convenient for any enterprise.

enterprise, including the leasing for commercial purposes of surplus

space or other space that is not economic to use for such enterprise.

(d) Adopt reasonable rules or regulations for the conduct of the

enterprise.

(e) Prescribe, revise, and collect charges for the services,

facilities, or energy furnished by the enterprise. The charges shall

be established and adjusted so as to provide funds sufficient with

other revenues and moneys available therefor, if any, to (1) pay the

principal of, and interest on, outstanding bonds of the authority

financing such enterprise as the same shall become due and payable,

(2) create and maintain reserves, including, without limitation,

operating and maintenance reserves and reserves required or provided

for in any resolution authorizing, or trust agreement securing such

bonds, and (3) pay operating and administrative costs of the

authority.

(f) Execute all instruments, perform all acts, and do all things

necessary or convenient in the exercise of the powers granted by this

article.

991.7. In connection with a project, the authority may do any or

all of the following:

(a) Determine the location and character of any project to be

financed under this article.

(b) Acquire, construct, enlarge, remodel, renovate, alter,

improve, furnish, equip, own, maintain, manage, repair, operate,

lease as lessee or lessor, or regulate any project to be financed

under this article.

participating party for the construction of a project by such

participating party.

(d) Enter into leases and agreements, as lessor or lessee, with

any participating party relating to the acquisition, construction,

and installation of any project, including real property, buildings,

equipment, and facilities of any kind or character.

(e) Establish, revise, charge and collect rates, rents, fees, and

charges for a project. The rates, rents, fees, and charges shall be

established and adjusted in respect to the aggregate rates, rents,

fees, and charges from all projects so as to provide funds sufficient

with other revenues and moneys available therefor, if any, to (1)

pay the principal of and interest on outstanding bonds of the

authority financing the project as the same shall become due and

payable, (2) create and maintain reserves, including, without

limitation, operating and maintenance reserves and reserves required

or provided for in any resolution authorizing, or trust agreement

securing the bonds, and (3) pay operating and administrative costs of

the authority.

(f) Enter into contracts of sale with any participating party

covering any project financed by the authority.

(g) As an alternative to leasing or selling a project to a

participating party, finance the acquisition, construction, or

installation of a project by means of a loan to the participating

party.

(h) Execute all instruments, perform all acts, and do all things

necessary or convenient in the exercise of the powers granted by this

article.

991.8. In connection with the purposes of this article, the

authority may charge and equitably apportion among participating

parties or other public or private entities the authority's

administrative costs and expenses, including operating and

financing-related costs incurred in connection with an enterprise or

a project. The authority shall recover those costs that are related

to one of the authority's own enterprises or projects, in which case

costs shall be included in the cost of generating and transmitting

that electricity.

992. (a) All generation-related projects and enterprises financed

pursuant to this article shall provide electricity to the consumers

of this state at the cost of generating that electricity, including

the costs of financing those projects or enterprises. To the extent

that electricity is not needed in the state, or that it is

financially advantageous to California consumers, the electricity may

be sold outside the state at just and reasonable rates.

(b) If a participating party is an electrical corporation, the

commission shall determine the cost of generating electricity and to

which entities the electricity is sold.

utility seeking to provide electricity to consumers in its service

territory, the governing board of that utility shall determine the

cost of generating electricity and to which entities the electricity

is sold.

(d) If neither subdivision (b) nor subdivision (c) applies, the

authority shall determine the cost of generating electricity and to

which entities the electricity is sold, consistent with subdivision

(a).

992.1. In addition to the other powers provided in this article,

the activities of the authority under this article are intended to

supplement private and public sector supplies of electricity

generated from eligible renewable energy resources, taking into

account generation facilities in operation or under development as of

January 1, 2010, consistent with achieving reasonable energy

capacity reserves.

992.2. The authority shall have the authority to receive and act

on applications for financial assistance from renewable generators

who commit to undertake capacity expansion through facility

retrofits, new construction, or both, that will improve the

efficiency and environmental performance of generation facilities

that are eligible renewable energy resources.

992.4. (a) The authority may not invest in any nuclear facilities

or develop additional hydroelectric facilities without first

receiving specific statutory authorization to do so on a

project-by-project basis.

(b) All generation facilities constructed or improved pursuant to

this article shall comply with Chapter 1 (commencing with Section

1720) of Part 7 of Division 2 of the Labor Code.

992.5. (a) If the authority determines that additional electric

generation supply is required to meet the purposes of this chapter,

the authority may undertake the following activities to ensure that

the authority, or any participating party, is able to build, own, and

operate generation facilities as part of a least cost electric

supply policy:

(1) (A) Identify suitable sites or renewable energy designation

zones for the construction of generation facilities, taking into

account fuel supply, interconnection, community, feasibility, and

environmental factors.

(B) The authority may designate a renewable energy designation

zone on its own motion, by a motion by the Energy Commission, or by

an application of a person who plans to construct an eligible

renewable energy resource within the state. The designation of a

renewable energy designation zone shall serve to identify a feasible

region where one or more generation facilities that are eligible

renewable energy resources may be built that are consistent with the

state's needs and objectives as set forth in the Renewables

Investment Plan adopted pursuant to Section 994.

renewable energy designation zones based on the following criteria:

(i) Total capacity of generation projects that are in the

Independent System Operator generation queue for each of the

renewable energy designation zones.

(ii) Fuel diversity.

(iii) Distance to the nearest possible Independent System Operator

transmission bulk facility.

(iv) Potential viable transmission route.

(v) Order of magnitude of transmission cost per megawatt for the

designated renewable energy designation zone to deliver electricity

from renewable generators to the load centers.

(vi) Realistic commercial operating dates for location-constrained

projects and the transmission interconnection facilities.

(vii) Potential impact on the transmission access charge.

(viii) Potential operational, congestion, and reliability benefits

of the facility.

(ix) Stranded cost risk and potential impact.

(x) Alternative means of transmission access from the renewable

energy designation zone to the Independent System Operator grid.

(D) The authority shall arrange for the publication of a summary

of any application made for designation in a newspaper of general

circulation in each county where the proposed renewable energy

designation zone would be located, and shall notify all property

owners within, or adjacent to, the renewable energy designation zone.

The authority shall transmit a copy of the application for

designation to all cities, counties, and state and federal agencies

having an interest in the proposed renewable energy designation zone.

The authority shall publish the application for designation on its

Internet Web site, and notify members of the public that the

application is available on the authority's Internet Web site.

(E) As soon as practicable after the authority designates a

renewable energy designation zone, it shall do both of the following:

(i) Post a copy of its decision on its Internet Web site and cause

a summary of the notice to be published in a newspaper of general

circulation in each county in which the renewable energy designation

zone and related facilities, or any part thereof, designated in the

notice are proposed to be located.

(ii) Send a copy of its decision, including a description of the

renewable energy designation zone to each affected city, county,

state agency, and federal agency, and notify property owners within

or adjacent to the renewable energy designation zone of the

availability of the decision on the authority's Internet Web site.

(F) After receiving notice from the authority regarding the

designation or revision of a renewable energy designation zone within

its jurisdiction, each city or county shall consider the designated

zone when making a determination regarding a land use change within

or adjacent to the zone that could affect its continuing viability to

accommodate generation facilities, related transmission lines,

transmission corridor zones, or other facilities appurtenant to the

designated zone. Upon receiving the authority's notification of a

proposed renewable energy designation zone, a city or county may

request a fee from the authority to cover the actual added costs of

this review and the authority shall pay this amount to the city or

county.

(G) After the authority designates a renewable energy designation

zone, it shall identify that zone in its subsequent Renewables

Investment Plans adopted pursuant to Section 994. The Energy

Commission shall display the renewable energy designation zone in the

strategic plans adopted pursuant to Section 25324 of the Public

Resources Code.

(H) If, upon regular review or at any other time, the authority

finds that a renewable energy designation zone designation is no

longer needed, the authority shall revise or repeal the designation

and, as soon as practicable, notify the affected cities, counties,

state and federal agencies, and property owners within, or adjacent

to, the renewable energy designation zone.

(2) (A) Notwithstanding Chapter 6 (commencing with Section 25500)

of Division 15 of the Public Resources Code, certify all sites and

related facilities for all generation facilities that are eligible

renewable energy resources, and facilities appurtenant thereto, that

are within the state that have a minimum generating capacity of 5

megawatts, including, but not limited to, all generation facilities

in a designated renewable energy designation zone, including new

sites and related facilities and changes or additions to an existing

facility.

(B) The issuance of a certificate by the authority shall be in

lieu of any permit, certificate, or similar document required by any

state, local, or regional agency or federal agency to the extent

permitted by federal law, for use of the site and related facilities,

and shall supersede any applicable statute, ordinance, or regulation

of any state, local, or regional agency, or federal agency to the

extent permitted by federal law.

application to construct a generation facility within a designated

renewable energy designation zone whether the application is

complete.

(D) If the notice or application is determined to be complete, the

authority shall conduct all applicable public and community

involvement processes. After the conclusion of hearings, and no later

than 180 days after the date of determination of whether the

application is complete, the authority shall issue a proposed

decision that contains its findings and conclusions regarding all of

the following matters:

(i) Conformity of the proposed generation facility and related

facilities with the Renewables Investment Plan adopted pursuant to

Section 994.

(ii) Suitability of the proposed generation facility and related

facilities with respect to environmental, public health and safety,

land use, economic, and transmission-system impacts.

(iii) Mitigation measures and alternatives as may be needed to

protect environmental quality, public health and safety, the state's

electrical transmission grid, or any other relevant matter.

(iv) Other factors that the authority considers relevant.

(E) The authority shall issue its final decision on certification

within six months of the date the authority determined that the

application was complete.

(3) Secure rights to the sites or renewable energy designation

zones identified, including, but not limited to, fee simple

acquisition, leaseholds, or options.

(4) Conduct any studies that may be necessary to construct and

operate generation facilities at the site that are eligible renewable

energy resources, including, but not limited to, environmental,

engineering, or feasibility studies. The designation of a renewable

energy designation zone is subject to the California Environmental

Quality Act (Division 13 (commencing with Section 21000) of the

Public Resources Code). The authority shall be the lead agency for

all generation projects proposed in the designated zone. When deemed

feasible, the authority shall prepare a master environmental impact

report for a designated zone.

(5) Conduct, in coordination with the Energy Commission, all

applicable public and community involvement processes.

(6) Apply for permits, licenses, or other local, state, or federal

approvals, including, but not limited to, compliance with the

applicable procedures of the Energy Commission.

(b) The authority may request proposals from qualified

participating parties to purchase, lease, or otherwise acquire sites

for the purpose of developing generation facilities that are eligible

renewable energy resources and that will provide the lowest cost

electricity to consumers over the life of the facilities, consistent

with Section 992. If after 45 days following a request for proposals,

or 45 days after notification pursuant to subparagraph (E) of

paragraph (1) of subdivision (a), if the authority determines it is

necessary and feasible, the authority shall exercise its authority to

build, own, and operate generation facilities as part of a least

cost electrical supply policy.

laws and all environmental regulations.

993. (a) In accordance with the provisions of this article and

notwithstanding any other provision of law, the authority shall,

except as provided in subdivision (e), have the exclusive power to

certify all electric transmission lines, remote resource

interconnection lines, electric transmission facilities and

facilities appurtenant thereto, and related facilities in the state,

including new electric transmission lines or transmission corridor

zones and related facilities or changes or additions to existing

electric transmission lines.

(b) The issuance of a certificate by the authority shall be in

lieu of any permit, certificate, or similar document required by any

state, local or regional agency, or federal agency to the extent

permitted by federal law, for such use of the site and related

facilities, and shall supersede any applicable statute, ordinance, or

regulation of any state, local, or regional agency, or federal

agency to the extent permitted by federal law.

subdivision (a) shall commence without first obtaining certification

for that site and related facility by the authority.

(d) The authority shall certify sufficient sites and related

facilities which are required for the transmission of electricity

sufficient to accommodate the generation projected in the most recent

designation of a renewable energy designation zone, adopted pursuant

to Section 992.5.

(e) (1) This section does not apply to any electric transmission

lines or facilities appurtenant thereto for which the commission has

issued a certificate of public convenience and necessity, or which

any local publicly owned electric utility has approved, before

January 1, 2011.

(2) This section does not apply to electric transmission lines

that connect generation facilities to the high-voltage transmission

grid that are under the siting authority of the Energy Commission,

pursuant to Section 25500 of the Public Resources Code.

993.4. (a) The authority may not invest in any electric

transmission lines without first receiving specific statutory

authorization to do so on a project-by-project basis.

(b) All electric transmission lines constructed or improved

pursuant to this division shall comply with Chapter 1 (commencing

with Section 1720) of Part 7 of Division 2 of the Labor Code.

993.5. (a) If the authority determines that an additional

electric transmission line is required to meet the purposes of this

chapter, the authority may undertake the following activities to

ensure that the authority, or any participating party, is able to

build, own, and operate transmission lines as part of a least cost

electric supply policy:

(1) Identify suitable sites for the construction of electric

transmission lines, taking into account the designation of a

renewable energy designation zone, interconnection, community,

feasibility, and environmental factors.

(2) Identify the site for an electric transmission line or a

transmission corridor zone on its own motion, by a motion by the

Energy Commission, or by application of a person who plans to

construct an electric transmission line within the state. The

designation of a site for an electric transmission line or a

transmission corridor zone shall serve to identify a feasible

corridor where one or more future electric transmission lines can be

built that are consistent with the state's needs and objectives as

set forth in the Renewables Investment Plan adopted pursuant to

Section 994.

(3) Require an application to site the electric transmission line

be submitted to the authority. The application shall be in the form

prescribed by the authority, shall be supported by any information

that the authority may require, and shall require a showing that the

site being applied for is consistent with the Renewables Investment

Plan adopted pursuant to Section 994.

(4) Secure rights to the sites identified, including, but not

limited to, fee simple acquisition, leaseholds, or options.

(5) Conduct any studies that may be necessary to construct and

operate electric transmission lines and transmission corridor zones,

including, but not limited to, environmental, engineering, or

feasibility studies. The designation of the site for an electric

transmission line and facilities appurtenant thereto or transmission

corridor zones is subject to the California Environmental Quality Act

(Division 13 (commencing with Section 21000) of the Public Resources

Code). The authority shall be the lead agency for all electric

transmission lines and facilities appurtenant thereto and

transmission corridor zones pursuant to this chapter. The authority

shall conduct a programmatic environmental impact report, for each

designated electric transmission line.

(6) Conduct, in coordination with the Energy Commission, all

applicable public and community involvement processes.

(7) Apply for permits, licenses, or other local, state, or federal

approvals, including, but not limited to, compliance with the

applicable procedures of the Energy Commission.

(8) (A) Utilize the bond authority provided in this division,

under terms and conditions approved by the authority, to acquire,

construct, enlarge, remodel, renovate, alter, improve, furnish,

equip, own, maintain, manage, repair, operate, lease as lessee or

lessor, or regulate electric transmission lines.

(B) The rates, rents, fees, and charges associated with the

investment in electric transmission lines shall be established and

adjusted to ensure compliance with subdivision (e) of Section 991.7.

(8) Request proposals from qualified participating parties to

purchase, lease, or otherwise acquire sites for the purpose of

developing electric transmission facilities that will provide the

lowest cost power to consumers over the life of the facilities,

consistent with Section 992.

(b) When considering whether to designate a site for an electric

transmission line and facilities appurtenant thereto or transmission

corridor zones pursuant to this section, the authority shall confer

with cities and counties, federal agencies, and California Native

American tribes to identify appropriate areas within their

jurisdictions that may be suitable for designation. The authority

shall, to the extent feasible, coordinate efforts to identify

long-term transmission needs of the state with the land use plans of

cities, counties, federal agencies, and California Native American

tribes. The authority shall not propose any facility within the

jurisdiction of a California Native American tribe without the

approval of the California Native American tribe.

994. (a) By January 1, 2011, and annually thereafter, the

authority shall, in consultation with the Energy Commission and the

Independent System Operator, develop a Renewables Investment Plan and

submit that plan to the Governor and the Joint Legislative Budget

Committee and the chairs of the policy committees with jurisdiction

over energy policy in the State of California.

(b) The Renewables Investment Plan shall take into account

California's anticipated needs, over the next decade, for electricity

generated by eligible renewable energy resources and the need for

transmission to deliver the electricity generated to retail

customers. The plan shall address issues regarding adequacy of

supply, storage, reliability of service, grid congestion, and

environmental quality. In developing the investment plan, the

authority shall compare the costs of various energy resources,

including a comparison of the costs and benefits of demand reduction

strategies with the costs and benefits of additional generation

supply. The plan shall acknowledge the potential volatility of fossil

fuel prices and the value of resources that avoid that price risk.

investments, using the financing powers provided to the authority by

this article. The plan may recommend changes to the specific

expenditure authority granted in this article in order to carry out

the investment strategy contained in the plan.

(d) The plan shall be developed with input from interested parties

at scheduled public hearings of the authority. The authority shall

adopt the plan by majority vote of the board at a public meeting. The

authority shall update the plan on a regular basis as determined by

the authority.

(e) All investments made by the authority under this article shall

be consistent with the strategy outlined in the Renewables

Investment Plan. Nothing in this section shall preclude the authority

from exercising its powers prior to the adoption of the initial

Renewables Investment Plan.

(f) The authority shall be the agency responsible for ensuring

that the investment strategy outlined in the Renewables Investment

Plan is implemented. To that end, the authority may, on its own or

through a partnership with a participating party, make those

investments necessary to ensure that the plan is implemented.

994.5. Nothing in this article shall be construed to obviate the

need to review the roles, functions, and duties of other state energy

oversight agencies and, where appropriate, change or consolidate

those roles, functions, and duties. To achieve that efficiency, the

Governor may propose to the Legislature a Governmental Reorganization

Plan, pursuant to Section 8523 of the Government Code and Section 6

of Article V of the Constitution.

995. (a) There is hereby created in the State Treasury the

Renewables Infrastructure Authority Fund for expenditure by the

authority for the purpose of implementing the objectives and

provisions of this article. For the purposes of subdivision (e), or

as necessary or convenient to the accomplishment of any other purpose

of the authority, the authority may establish within the fund

additional and separate accounts and subaccounts.

(b) Except as provided in subdivision (a) of Section 991.2, all

moneys in the fund that are not General Fund moneys are continuously

appropriated to the authority and may be used for any reasonable

costs that may be incurred by the authority in the exercise of its

powers under this article.

moneys from the authority, or from any federal, state, or local

agency or private entity, to create reserves in the fund as provided

in this article and as authorized by the board.

(d) The authority may pledge any or all of the moneys in the fund

(including in any account or subaccount) as security for payment of

the principal of, and interest on, any particular issuance of bonds

issued pursuant to this article.

(e) The authority, may, from time to time, direct the Treasurer to

invest moneys in the fund that are not required for the authority's

current needs, including proceeds from the sale of any bonds, in any

securities permitted by law as the authority shall designate. The

authority also may direct the Treasurer to deposit moneys in

interest-bearing accounts in state or national banks or other

financial institutions having principal offices in this state. The

authority may alternatively require the transfer of moneys in the

fund to the Surplus Money Investment Fund for investment pursuant to

Article 4 (commencing with Section 16470) of Chapter 3 of Part 2 of

Division 4 of the Government Code. All interest or other increment

resulting from an investment or deposit shall be deposited in the

fund, notwithstanding Section 16305.7 of the Government Code. Moneys

in the fund shall not be subject to transfer to any other fund

pursuant to any provision of Part 2 (commencing with Section 16300)

of Division 4 of the Government Code, excepting the Surplus Money

Investment Fund.

996. For the purposes provided in this division, the authority is

authorized to incur indebtedness and to issue securities of any kind

or class, at public or private sale by the Treasurer, and to renew

the same, provided that all such indebtedness, howsoever evidenced,

shall be payable solely from revenues. The authority may issue bonds

for the purposes of this division in an amount not to exceed six

billion, four hundred million dollars ($6,400,000,000), exclusive of

any refundings.

996.1. In addition to the powers otherwise provided in this

article, the authority may, in connection with the issuance of bonds,

do all of the following:

(a) Issue, from time to time, bonds payable from and secured by a

pledge of all or any part of the revenues in order to finance the

activities authorized by this article, including, without limitation,

an enterprise or multiple enterprises, a single project for a single

participating party, a series of projects for a single participating

party, a single project for several participating parties, or

several projects for several participating parties, and to sell those

bonds at public or private sale by the Treasurer, in the form and on

those terms and conditions as the Treasurer, as agent for sale,

shall approve.

(b) Pledge all or any part of the revenues to secure bonds and any

repayment or reimbursement obligations of the authority to any

provider of insurance or a guarantee of liquidity or credit facility

entered into to provide for the payment or debt service on any bond.

underwriters, and other advisers determined necessary and appointed

by the Treasurer in connection with the issuance and sale of any

bond.

(d) Issue bonds to refund or purchase or otherwise acquire bonds

on terms and conditions as the Treasurer, as agent for sale, shall

approve.

(e) Perform all acts that relate to the function and purpose of

the authority under this article, whether or not specifically

designated.

996.2. Bonds issued under this article shall not be deemed to

constitute a debt or liability of the state or of any political

subdivision thereof, other than the authority, or a pledge of the

faith and credit of the state or of any political subdivision, other

than the authority, but shall be payable solely from the funds herein

provided therefor. All bonds issued under this division shall

contain on the face thereof a statement to the following effect:

"Neither the faith and credit nor the taxing power of the State of

California or any local agency is pledged to the payment of the

principal of or interest on this bond." The issuance of bonds under

this article shall not directly or indirectly or contingently

obligate the state or any political subdivision thereof to levy or to

pledge any form of taxation whatever therefor or to make any

appropriation for their payment. Nothing in this section shall

prevent nor be construed to prevent the authority from pledging its

full faith and credit to the payment of bonds or issue of bonds

authorized pursuant to this article.

996.5. The authority is authorized to obtain loans from the

Pooled Money Investment Account pursuant to Sections 16312 and 16313

of the Government Code. These loans shall be subject to the terms

negotiated with the Pooled Money Investment Board, including, but not

limited to, a pledge of authority bond proceeds or revenues.

997. The authority may not finance or approve any new program,

enterprise, or project on or after December 31, 2020, unless

authority to approve such an activity is granted by statute enacted

on or before January 1, 2021.

SEC. 7. No reimbursement is required by this act pursuant to

Section 6 of Article XIII B of the California Constitution because

certain costs that may be incurred by a local agency or school

district will be incurred because this act creates a new crime or

infraction, eliminates a crime or infraction, or changes the penalty

for a crime or infraction, within the meaning of Section 17556 of the

Government Code, or changes the definition of a crime within the

meaning of Section 6 of Article XIII B of the California

Constitution.

With respect to certain other costs, no reimbursement is required

by this act pursuant to Section 6 of Article XIII B of the California

Constitution because a local agency or school district has the

authority to levy service charges, fees, or assessments sufficient to

pay for the program or level of service mandated by this act, within

the meaning of Section 17556 of the Government Code.

¹ In the Energy Action Plan II (2005), the CPUC and CEC called for the examination of a 33% RPS. The CEC, through the 2008 Integrated Energy Policy Report (IEPR) Update, makes various recommendations pertaining to a 33% RPS. The CEC and CPUC supported a greater reliance on renewable energy so that at least 33% of the State's electricity needs are met by renewable resources by 2020 in their October 2008 decision recommending greenhouse gas regulatory strategies for the electric sector.

² Except for one limited category of transmission interconnecting individual generators to the grid, which would apparently continue to be permitted by the California Energy Commission.

³ The California Legislative Counsel has determined that "[B]ecause the California Constitution confers the function of public utility regulation on the commission, the Governor is precluded from transferring the statutory and constitutional authority of the commission that relates to the regulation of public utilities to any other entity of state government pursuant to the Governor's statutory authority to reorganize state government." (Legislative Counsel letter to Little Hoover Commission, June 20, 2005, p. 3.) Similarly, constitutionally-granted powers of the CPUC cannot be modified, curtailed, or abridged by legislation. (People v. Western Air Lines, Inc. (1954), 42 Cal. 2d 621, 637, citing Western Assn. etc. R.R. v. Railroad Com. (1916), 173 Cal. 802, 804.)

⁴ If the RIA would actually own a new transmission facility, that facility might not be subject to the same extent of FERC jurisdiction as public utility-owned transmission. However, this would complicate "seams" issues reflecting the contrasting jurisdictional and operational models for the CAISO's independently operated grid versus neighboring transmission systems owned by municipal or federal entities. If, more consistent with AB 64's emphasis on centralization of decisions, any RIA-owned transmission were to become part of the CAISO-operated system, then it would be fully subject to FERC jurisdiction regarding planning, cost recovery and other matters

⁵ Transmission projects must ultimately go to FERC for approval of rates and cost recovery, where the CPUC, within its retail ratemaking role, represents the interests of California consumers and other market participants.

STATE OF CALIFORNIA

Public Utilities Commission

February 11, 2009

Office of Governmental Affairs (OGA) - Sacramento