Today's Law As Amended


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AB-94 Public utilities: local publicly owned electric utilities: renewable energy resources.(2007-2008)



As Amends the Law Today


SECTION 1.

 Section 25302.5 of the Public Resources Code is amended to read:

25302.5.
 (a) As part of each integrated energy policy report required pursuant to Section 25302, each entity that serves or plans to serve electricity to retail customers, including, but not limited to, electrical corporations, nonutility electric service providers, community choice aggregators, and local publicly owned electric utilities, shall provide the commission with its forecast of both of the following:
(1) The amount of its forecasted load that may be lost or added by any of the following:
(A) A community choice aggregator.
(B) An existing local publicly owned electric utility.
(C) A newly formed local publicly owned electric utility.
(2) Load that will be served by an electric service provider.
(b) The commission shall perform an assessment in the service territory of each electrical corporation of the loss or addition of load described in this section and submit the results of the assessment to the Public Utilities Commission.
(c) Notwithstanding subdivision (a), the commission may exempt from the forecasting requirements in that subdivision, a local publicly owned electric utility that is not planning to acquire additional load beyond its existing exclusive service territory within the forecast period provided by the commission pursuant to Section 25303.
(d) For purposes of this section, the following terms have the following meanings:
(1) “Community choice aggregator” means any “community choice aggregator” as defined in Section 331.1 of the Public Utilities Code.
(2) “Electrical corporation” means any “electrical corporation” as defined in Section 218 of the Public Utilities Code.
(3) “Electric service provider” means any “electric service provider” as defined in Section 218.3 of the Public Utilities Code.
(4) “Local publicly owned electric utility” means any “local publicly owned electric utility” as defined in Section 224.3 of the Public Utilities Code.

SEC. 2.

 Section 25534 of the Public Resources Code is amended to read:

25534.
 (a) The commission may, after one or more hearings, amend the conditions of, or revoke the certification for, any facility for any of the following reasons:
(1) Any material false statement set forth in the application, presented in proceedings of the commission, or included in supplemental documentation provided by the applicant.
(2) Any significant failure to comply with the terms or conditions of approval of the application, as specified by the commission in its written decision.
(3) A violation of this division or any regulation or order issued by the commission under this division.
(4) The owner of a project does not start construction of the project within 12 months after the date all permits necessary for the project become final and all administrative and judicial appeals have been resolved provided the California Consumer Power and Conservation Financing Authority notifies the commission that it is willing and able to construct the project pursuant to subdivision (g). The project owner may extend the 12-month period by 24 additional months pursuant to subdivision (f). This paragraph applies only to projects with a project permit application deemed complete by the commission after January 1, 2003.
(b) The commission may also administratively impose a civil penalty for a violation of paragraph (1) or (2) of subdivision (a). Any civil penalty shall be imposed in accordance with Section 25534.1 and may not exceed seventy-five thousand dollars ($75,000) per violation, except that the civil penalty may be increased by an amount not to exceed one thousand five hundred dollars ($1,500) per day for each day in which the violation occurs or persists, but the total of the per day  per-day  penalties may not exceed fifty thousand dollars ($50,000).
(c) A project owner shall commence construction of a project subject to the start-of-construction deadline provided by paragraph (4) of subdivision (a) within 12 months after the project has been certified by the commission and after all accompanying project permits are final and administrative and judicial appeals have been completed. The project owner shall submit construction and commercial operation milestones to the commission within 30 days after project certification. Construction milestones shall require the start of construction within the 12-month period established by this subdivision. The commission shall approve milestones within 60 days after project certification. If the 30-day deadline to submit construction milestones to the commission is not met, the commission shall establish milestones for the project.
(d) The failure of the owner of a project subject to the start-of-construction deadline provided by paragraph (4) of subdivision (a) to meet construction or commercial operation milestones, without a finding by the commission of good cause, shall be cause for revocation of certification or the imposition of other penalties by the commission.
(e) A finding by the commission that there is good cause for failure to meet the start-of-construction deadline required by paragraph (4) of subdivision (a) or any subsequent milestones of subdivision (c) shall be made if the commission determines that any of the following criteria are met:
(1) The change in any deadline or milestone does not change the established deadline or milestone for the start of commercial operation.
(2) The deadline or milestone is changed due to circumstances beyond the project owner’s control, including, but not limited to, administrative and legal appeals.
(3) The deadline or milestone will be missed but the project owner demonstrates a good faith effort to meet the project deadline or milestone.
(4) The deadline or milestone will be missed due to unforeseen natural disasters or acts of God that prevent timely completion of the project deadline or milestone.
(5) The deadline or milestone will be missed for any other reason determined reasonable by the commission.
(f) The commission shall extend the start-of-construction deadline required by paragraph (4) of subdivision (a) by an additional 24 months, months  if the owner reimburses the commission’s actual cost of licensing the project, less the amount paid pursuant to subdivision (a) of Section 25806. For the purposes of this section, the commission’s actual cost of licensing the project shall be based on a certified audit report filed by the commission staff within 180 days of the commission’s certification of the project. The certified audit shall be filed and served on all parties to the proceeding, is subject to public review and comment, and is subject to at least one public hearing if requested by the project owner. Any reimbursement received by the commission pursuant to this subdivision shall be deposited in the General Fund.
(g) If the owner of a project subject to the start-of-construction deadline provided by paragraph (4) of subdivision (a) fails to commence construction, without good cause, within 12 months after the project has been certified by the commission and has not received an extension pursuant to subdivision (f), the commission shall provide immediate notice to the California Consumer Power and Conservation Financing Authority. The authority shall evaluate whether to pursue the project independently or in conjunction with any other public or private entity, including the original certificate holder. If the authority demonstrates to the commission that it is willing and able to construct the project either independently or in conjunction with any other public or private entity, including the original certificate holder, the commission may revoke the original certification and issue a new certification for the project to the authority, unless the authority’s statutory authorization to finance or approve new programs, enterprises, or projects has expired. If the authority declines to pursue the project, the permit shall remain with the current project owner until it expires pursuant to the regulations adopted by the commission.
(h) If the commission issues a new certification for a project subject to the start-of-construction deadline provided by paragraph (4) of subdivision (a) to the authority, the commission shall adopt new milestones for the project that allow the authority up to 24 months to start construction of the project or to start to meet the applicable deadlines or milestones. If the authority fails to begin construction in conformity with the deadlines or milestones adopted by the commission, without good cause, the certification may be revoked.
(i) (1) If the commission issues a new certification for a project subject to the start-of-construction deadline provided by paragraph (4) of subdivision (a) to the authority and the authority pursues the project without participation of the original certificate holder, the authority shall offer to reimburse the original certificate holder for the actual costs the original certificate holder incurred in permitting the project and in procuring assets associated with the license, including, but not limited to, major equipment and the emission offsets. In order to receive reimbursement, the original certificate holder shall provide to the commission documentation of the actual costs incurred in permitting the project. The commission shall validate those costs. The certificate holder may refuse to accept the offer of reimbursement for any asset associated with the license and retain the asset. To the extent the certificate holder chooses to accept the offer for an asset, it shall provide the authority with the asset.
(2) If the authority reimburses the original certificate holder for the costs described in paragraph (1), the original certificate holder shall provide the authority with all of the assets for which the original certificate holder received reimbursement.
(j) This section does not prevent a certificate holder from selling its license to construct and operate a project prior to its revocation by the commission. In the event of a sale to an entity that is not an affiliate of the certificate holder, the commission shall adopt new deadlines or milestones for the project that allow the new certificate holder up to 12 months to start construction of the project or to start to meet the applicable deadlines or milestones.
(k) Paragraph (4) of subdivision (a) and subdivisions (c) to (j), inclusive, do not apply to licenses issued for the modernization, repowering, replacement, or refurbishment of existing facilities or to a qualifying small power production facility or a qualifying cogeneration facility within the meaning of Sections 201 and 210 of Title II of the federal Public Utility Regulatory Policies Act of 1978 (16 U.S.C. Secs. 796(17), 796(18), and 824a-3), and the regulations adopted pursuant to those sections by the Federal Energy Regulatory Commission (18 C.F.R. Parts 292.101 to 292.602, inclusive), nor shall those provisions apply to any other generation units installed, operated, and maintained at a customer site exclusively to serve that facility’s load. For the purposes of this subdivision, “replacement” of an existing facility includes, but is not limited to, a comparable project at a location different than the facility being replaced, provided that the commission certifies that the new project will result in the decommissioning of the existing facility.
(l) Paragraph (4) of subdivision (a) and subdivisions (c) to (j), inclusive, do not apply to licenses issued to “local publicly owned electric utilities,” as defined in Section 224.3 of the Public Utilities Code, whose governing bodies certify to the commission that the project is needed to meet the projected native load of the local publicly owned utility.
(m) To implement this section, the commission and the California Consumer Power and Conservation Financing Authority may, in consultation with each other, adopt emergency regulations in accordance with Chapter 3.5 (commencing with Section 11340) of Part 1 of Division 3 of Title 2 of the Government Code. For purposes of that chapter, including, without limitation, Section 11349.6 of the Government Code, the adoption of the regulations shall be considered by the Office of Administrative Law to be necessary for the immediate preservation of the public peace, health and safety, or general welfare.

SEC. 3.

 Section 25741 of the Public Resources Code is amended to read:

25741.
 As used in this chapter, the following terms have the following meaning:
(a) “Delivered” and “delivery” mean the electricity output of an in-state renewable electricity generation facility that is used to serve end-use retail customers located within the state. Subject to verification by the accounting system established by the commission pursuant to subdivision (b) of Section 399.13 of the Public Utilities Code, electricity shall be deemed delivered if it is either generated at a location within the state, or is scheduled for consumption by California end-use retail customers. Subject to criteria adopted by the commission, electricity generated by an eligible renewable energy resource may be considered “delivered” regardless of whether the electricity is generated at a different time from consumption by a California end-use customer.
(a) (b)  “Renewable electrical  “In-state renewable electricity  generation facility” means a facility that meets all of the following criteria:
(1) The facility uses biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current, and any additions or enhancements to the facility using that technology.
(2) The facility satisfies 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 of a balancing authority area primarily located within the state. For purposes of this subparagraph, “balancing authority area” has the same meaning as defined in Section 399.12 of the Public Utilities Code. 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, within the Western Electricity Coordinating Council (WECC) service area,  state  and satisfies all of the following requirements:
(i) It is connected to the transmission network within the Western Electricity Coordinating Council (WECC) service territory.
(i) (ii)  It commences initial commercial operation after January 1, 2005.
(iii) Electricity produced by the facility is delivered to an in-state location.
(ii) (iv)  It will not cause or contribute to any violation of a California environmental quality standard or requirement.
(v) 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.
(iii) (vi)  It participates in the accounting system to verify compliance with the renewables portfolio standard by retail sellers,  once established by the commission  Energy Commission  pursuant to subdivision (b) of Section 399.25 399.13  of the Public Utilities Code.
(C) The facility meets the requirements of clauses (ii) and (iii) (i), (iii), (iv), (v), and (vi)  in subparagraph (B), but does not meet the requirements of clause (i) of subparagraph (B)  (ii)  because it commenced commences  initial operation prior to January 1, 2005, if the facility satisfies either of the following requirements:
(i) The electricity is from incremental generation resulting from expansion or repowering of the facility.
(ii) Electricity generated by the facility was procured by a retail seller or local publicly owned electric utility as of January 1, 2010.
(3) If the facility is outside 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.
(4) (ii)  If eligibility of the facility is based on the use of landfill gas, digester gas, or another renewable fuel delivered to the facility through a common carrier pipeline, the transaction for the procurement of that fuel, including the source of the fuel and delivery method, satisfies the requirements of Section 399.12.6 The facility has been part of the existing baseline of eligible renewable energy resources of a retail seller established pursuant to paragraph (2) of subdivision (b) of Section 399.15  of the Public Utilities Code and is verified pursuant to the accounting system established by the commission pursuant to 399.25  or has been part of the existing baseline of eligible renewable energy resources of a local publicly owned electric utility established pursuant to Section 387  of the Public Utilities Code, or a comparable system, as determined by the commission. Code. 
(b) (3)  “Municipal solid waste conversion,” as used in subdivision (a), For the purposes of this subdivision, “solid waste conversion”  means a technology that uses a noncombustion thermal process to convert solid waste to a clean-burning fuel for the purpose of generating electricity, and that meets all of the following criteria:
(1) (A)  The technology does not use air or oxygen in the conversion process, except ambient air to maintain temperature control.
(2) (B)  The technology produces no discharges of air contaminants or emissions, including greenhouse gases as defined in Section 38505 42801.1  of the Health and Safety Code.
(3) (C)  The technology produces no discharges to surface or groundwaters of the state.
(4) (D)  The technology produces no hazardous wastes.
(5) (E)  To the maximum extent feasible, the technology removes all recyclable materials and marketable green waste compostable materials from the solid waste stream prior to the conversion process and the owner or operator of the facility certifies that those materials will be recycled or composted.
(6) (F)  The facility at which the technology is used is in compliance with all applicable laws, regulations, and ordinances.
(7) (G)  The technology meets any other conditions established by the commission.
(8) (H)  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.
(c) “Procurement entity” means any person or corporation that enters into an agreement with a retail seller to procure eligible renewable energy resources pursuant to subdivision (f) of Section 399.14 of the Public Utilities Code.
(c) (d)  “Renewable energy public goods charge” means that portion of the nonbypassable system benefits charge required authorized  to be collected to fund renewable energy  and to be transferred to the Renewable Resource Trust Fund  pursuant to the Reliable Electric Service Investments Act (Article 15 (commencing with Section 399) of Chapter 2.3 of Part 1 of Division 1 of the Public Utilities Code).
(d) (e)  “Report” means the report entitled “Investing in Renewable Electricity Generation in California” (June 2001, Publication Number P500-00-022) submitted to the Governor and the Legislature by the commission.
(e) (f)  “Retail seller” means a “retail seller” as defined in Section 399.12 of the Public Utilities Code.

SEC. 3.SEC. 4.

 Section 5 of the Public Utilities Code is amended to read:

5.
 Unless the provision or the context otherwise requires, the definitions, rules of construction, and other general provisions contained in Sections 1 to 22, inclusive, and the definitions in the Public Utilities Act (Chapter 1 (commencing with Section 201) of Part 1 of Division 1), shall govern the construction of this code.

SEC. 4.SEC. 5.

 Section 20 of the Public Utilities Code is amended to read:

20.
 (a) “Commission” means the Public Utilities Commission created by Section 1 of Article XII of the California Constitution, and “commissioner” means a member of the commission.
(b) “Energy Commission” means the State Energy Resources Conservation and Development Commission.

SEC. 5.SEC. 6.

 Section 216 of the Public Utilities Code is amended to read:

216.
 (a) (1)  “Public utility” includes every common carrier, toll bridge corporation, pipeline corporation, gas corporation, electrical corporation, telephone corporation, telegraph corporation, water corporation, sewer system corporation, and heat corporation, where the service is performed for, or the commodity is delivered to, the public or any portion thereof.
(2) A provider of last resort, as defined in Section 387, that is providing service pursuant to Article 8.5 (commencing with Section 387) of Chapter 2.3 is a public utility subject to the jurisdiction, control, and regulation of the commission and the provisions of this part regarding providing that service.
(b) Whenever any common carrier, toll bridge corporation, pipeline corporation, gas corporation, electrical corporation, telephone corporation, telegraph corporation, water corporation, sewer system corporation, or heat corporation performs a service for, or delivers a commodity to, the public or any portion thereof for which any compensation or payment whatsoever is received, that common carrier, toll bridge corporation, pipeline corporation, gas corporation, electrical corporation, telephone corporation, telegraph corporation, water corporation, sewer system corporation, or heat corporation, is a public utility subject to the jurisdiction, control, and regulation of the commission and the provisions of this part.
(c) When any person or corporation performs any service for, or delivers any commodity to, any person, private corporation, municipality, or other political subdivision of the state, that in turn either directly or indirectly, mediately or immediately, performs that service for, or delivers that commodity to, the public or any portion thereof, that person or corporation is a public utility subject to the jurisdiction, control, and regulation of the commission and the provisions of this part.
(d) Ownership or operation of a facility that employs cogeneration technology or produces power from other than a conventional power source or the ownership or operation of a facility which employs landfill gas technology does not make a corporation or person a public utility within the meaning of this section solely because of the ownership or operation of that facility.
(e) Any corporation or person engaged directly or indirectly in developing, producing, transmitting, distributing, delivering, or selling any form of heat derived from geothermal or solar resources or from cogeneration technology to any privately owned or publicly owned public utility, or to the public or any portion thereof, is not a public utility within the meaning of this section solely by reason of engaging in any of those activities.
(f) The ownership or operation of a facility that sells compressed natural gas or hydrogen  at retail to the public for use only as a motor vehicle fuel, and the selling of compressed natural gas or hydrogen  at retail from that facility to the public for use only as a motor vehicle fuel, does not make the corporation or person a public utility within the meaning of this section solely because of that ownership, operation, or sale.
(g) Ownership or operation of a facility that is an exempt wholesale generator, as defined in the Public Utility Holding Company Act of 2005 (42 U.S.C. Sec. 16451(6)), does not make a corporation or person a public utility within the meaning of this section, section  solely due to the ownership or operation of that facility.
(h) The ownership, control, operation, or management of an electric plant used for direct transactions or participation directly or indirectly in direct transactions, as permitted by subdivision (b) of Section 365, sales into a market established and operated by the Independent System Operator or any other wholesale electricity market, or the use or sale as permitted under subdivisions (b) to (d), inclusive, of Section 218, shall not make a corporation or person a public utility within the meaning of this section solely because of that ownership, participation, or sale.
(i) The ownership, control, operation, or management of a facility that supplies electricity to the public only for use to charge light duty plug-in electric vehicles does not make the corporation or person a public utility within the meaning of this section solely because of that ownership, control, operation, or management. For purposes of this subdivision, “light duty plug-in electric vehicles” includes light duty battery electric and plug-in hybrid electric vehicles. This subdivision does not affect the commission’s authority under Section 454 or 740.2 or any other applicable statute.

SEC. 7.

 Section 224.3 is added to the Public Utilities Code, to read:

224.3.
 “Local publicly owned electric utility” means a municipality or municipal corporation operating as a “public utility” furnishing electric service as provided in Section 10001, a municipal utility district furnishing electric service formed pursuant to Division 6 (commencing with Section 11501), a public utility district furnishing electric services formed pursuant to the Public Utility District Act set forth in Division 7 (commencing with Section 15501), an irrigation district furnishing electric services formed pursuant to the Irrigation District Law set forth in Division 11 (commencing with Section 20500) of the Water Code, or a joint powers authority that includes one or more of these agencies and that owns generation or transmission facilities, or furnishes electric services over its own or its member’s electric distribution system.

SEC. 7.SEC. 8.

 Section 228.5 of the Public Utilities Code is amended and renumbered to read:

218.5.
 (a) The following terms have the following meanings:
(1) “Exempt wholesale generator” has the same meaning as defined in the Public Utility Holding Company Act of 2005 (42 U.S.C. Sec. 16451(6)).
(2) “Qualifying small power producer,” “small power production facility,” and “qualifying small power production facility” have the same meanings as found in Section 796 of Title 16 of the United States Code and the regulations enacted pursuant thereto.
(b) Notwithstanding any other provision of law, a qualifying small power producer owning or operating a small power production facility is not a public utility subject to the general jurisdiction of the commission solely because of the ownership or operation of the facility.
(c) Notwithstanding any other provision of law, an exempt wholesale generator is not a public utility subject to the general jurisdiction of the commission solely due to the ownership or operation of the facility.

SEC. 8.SEC. 9.

 Section 353.11 of the Public Utilities Code is amended to read:

353.11.
 A local publicly owned electric utility or a local publicly owned utility otherwise providing electrical service, shall review at the earliest practicable date its rates, tariffs, and rules to identify barriers to and determine the appropriate balance of costs and benefits of distributed energy resources in order to facilitate the installation of these resources in the interests of their customer-owners and the state, and shall hold at least one noticed public meeting to solicit public comment on the review and any recommended changes. However, notwithstanding any other provision of this article, such an entity has the sole authority to undertake such a review and to make modifications to its rates, tariffs, and rules as the governing body of that utility determines to be necessary.

SEC. 9.SEC. 10.

 Section 366.2 of the Public Utilities Code is amended to read:

366.2.
 (a) (1) Customers shall be entitled to aggregate their electric loads as members of their local community with community choice aggregators.
(2) Customers may aggregate their loads through a public process with community choice aggregators, aggregators  if each customer is given an opportunity to opt out of the customer’s  their  community’s aggregation program.
(3) If a customer opts out of a community choice aggregator’s program, or has no community choice aggregation  program available, that customer shall have the right to continue to be served by the existing electrical corporation or its successor in interest.
(4) The implementation of a community choice aggregation program shall not result in a shifting of costs between the customers of the community choice aggregator and the bundled service customers of an electrical corporation.
(5) A community choice aggregator shall be solely responsible for all generation procurement activities on behalf of the community choice aggregator’s customers, except where other generation procurement arrangements are expressly authorized by statute.
(b) If a public agency seeks to serve as a community choice aggregator, it shall offer the opportunity to purchase electricity to all residential customers within its jurisdiction.
(c) (1) Notwithstanding Section 366, a community choice aggregator is hereby authorized to aggregate the electrical load of interested electricity consumers within its boundaries to reduce transaction costs to consumers, provide consumer protections, and leverage the negotiation of contracts. However, the community choice aggregator may not aggregate electrical load if that load is served by a local publicly owned electric utility. A community choice aggregator may group retail electricity customers to solicit bids, broker, and contract for electricity and energy services for those customers. The community choice aggregator may enter into agreements for services to facilitate the sale and purchase of electricity and other related services. Those service agreements may be entered into by an entity authorized to be a community choice aggregator, as defined in Section 331.1. a single city or county, a city and county, or by a group of cities, cities and counties, or counties. 
(2) Under community choice aggregation, customer participation may not require a positive written declaration, but each customer all customers  shall be informed of the customer’s  their  right to opt out of the community choice aggregation program. If no negative declaration is made by a customer, that customer shall be served through the community choice aggregation program. If an existing customer moves the location of the customer’s electric service within the jurisdiction of the community choice aggregator, the customer shall retain the same subscriber status as prior to the move, unless the customer affirmatively changes the customer’s subscriber status. If the customer is moving from outside to inside the jurisdiction of the community choice aggregator, customer participation shall not require a positive written declaration, but the customer shall be informed of the customer’s right to elect not to receive service through the community choice aggregator. 
(3) A community choice aggregator establishing electrical load aggregation pursuant to this section shall develop an implementation plan detailing the process and consequences of aggregation. The implementation plan, and any subsequent changes to it, shall be considered and adopted at a duly noticed public hearing. The implementation plan shall contain all of the following:
(A) An organizational structure of the program, its operations, and its funding.
(B) Ratesetting and other costs to participants.
(C) Provisions for disclosure and due process in setting rates and allocating costs among participants.
(D) The methods for entering and terminating agreements with other entities.
(E) The rights and responsibilities of program participants, including, but not limited to, consumer protection procedures, credit issues, and shutoff procedures.
(F) Termination of the program.
(G) A description of the third parties that will be supplying electricity under the program, including, but not limited to, information about financial, technical, and operational capabilities.
(H) The methods for ensuring procurement from small, local, and diverse business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.
(4) A community choice aggregator establishing electrical load aggregation shall prepare a statement of intent with the implementation plan. Any community choice load aggregation established pursuant to this section shall provide for the following:
(A) Universal access.
(B) Reliability.
(C) Equitable treatment of all classes of customers.
(D) Any requirements established by state law or by the commission concerning aggregated service, including those rules adopted by the commission pursuant to paragraph (3) of subdivision (b) of Section 8341 for the application of the greenhouse gases emission performance standard to community choice aggregators. service. 
(5) In order to determine the cost-recovery mechanism to be imposed on the community choice aggregator pursuant to subdivisions (d), (e), and (f) that shall be paid by the customers of the community choice aggregator to prevent shifting of costs, the community choice aggregator shall file the implementation plan with the commission, and any other information requested by the commission that the commission determines is necessary to develop the cost-recovery mechanism in subdivisions (d), (e), and (f).
(6) The commission shall notify any electrical corporation serving the customers proposed for aggregation that an implementation plan initiating community choice aggregation has been filed, within 10 days of the filing.
(7) Within 90 days after the community choice aggregator establishing load aggregation files its implementation plan, the commission shall certify that it has received the implementation plan, including any additional information necessary to determine a cost-recovery mechanism. After certification of receipt of the implementation plan and any additional information requested, the commission shall then provide the community choice aggregator with its findings regarding any cost recovery that must be paid by customers of the community choice aggregator to prevent a shifting of costs as provided for in subdivisions (d), (e), and (f).
(8) No entity proposing community choice aggregation shall act to furnish electricity to electricity consumers within its boundaries until the commission determines the cost recovery  cost-recovery  that must be paid by the customers of that proposed community choice aggregation program, as provided for in subdivisions (d), (e), and (f). The commission shall designate the earliest possible effective date for implementation of a community choice aggregation program, taking into consideration the impact on any annual procurement plan of the electrical corporation that has been approved by the commission.
(9) All electrical corporations shall cooperate fully with any community choice aggregators that investigate, pursue, or implement community choice aggregation programs. Cooperation shall include providing the entities with appropriate billing and electrical load data, including, but not limited to, electrical consumption data as defined in Section 8380 and other data  data  detailing electricity needs and patterns of usage, as determined by the commission, and in accordance with procedures established by the commission. The commission shall exercise its authority pursuant to Chapter 11 (commencing with Section 2100) to enforce the requirements of this paragraph when it finds that the requirements of this paragraph have been violated.  Electrical corporations shall continue to provide all metering, billing, collection, and customer service to retail customers that participate in community choice aggregation programs. Bills sent by the electrical corporation to retail customers shall identify the community choice aggregator as providing the electrical energy component of the bill. The commission shall determine the terms and conditions under which the electrical corporation provides services to community choice aggregators and retail customers.
(10) If the commission finds that an electrical corporation has violated this section, the commission shall consider the impact of the violation upon community choice aggregators.
(11) The commission shall proactively expedite the complaint process for disputes regarding an electrical corporation’s violation of its obligations pursuant to this section in order to provide for timely resolution of complaints made by community choice aggregation programs, so that all complaints are resolved in no more than 180 days following the filing of a complaint by a community choice aggregation program concerning the actions of the incumbent electrical corporation. This deadline may only be extended under either of the following circumstances:
(A) Upon agreement of all of the parties to the complaint.
(B) The commission makes a written determination that the deadline cannot be met, including findings for the reason for this determination, and issues an order extending the deadline. A single order pursuant to this subparagraph shall not extend the deadline for more than 60 days.
(12) (10)  (A) An entity authorized to be a community choice aggregator, as defined in Section 331.1,  A city, county, or city and county  that elects to implement a community choice aggregation program within its jurisdiction pursuant to this chapter, chapter  shall do so by ordinance. A city, county, or city and county may request, by affirmative resolution of its governing council or board, that another entity authorized to be a community choice aggregator act as the community choice aggregator on its behalf. If a city, county, or city and county, by resolution, requests another authorized entity be the community choice aggregator for the city, county, or city and county, that authorized entity shall be responsible for adopting the ordinance to implement the community choice aggregation program on behalf of the city, county, or city and county. 
(B) Two or more entities authorized to be a community choice aggregator, as defined in Section 331.1,  cities, counties, or cities and counties  may participate as a group in a community choice aggregation program  pursuant to this chapter, through a joint powers agency established pursuant to Chapter 5 (commencing with Section 6500) of Division 7 of Title 1 of the Government Code, if each entity adopts an ordinance pursuant to subparagraph (A). Pursuant to Section 6508.1 of the Government Code, members of a joint powers agency that is a community choice aggregator may specify in the joint powers agreement that, unless otherwise agreed by the members of the agency, the debts, liabilities, and obligations of the agency shall not be the debts, liabilities, and obligations, either jointly or severally, of the members of the agency. The commission shall not, as a condition of registration or otherwise, require an agency’s members to voluntarily assume the debts, liabilities, and obligations of the agency to the electrical corporation unless the commission finds that the agreement by the agency’s members is the only reasonable means by which the agency may establish its creditworthiness under the electrical corporation’s tariff to pay charges to the electrical corporation under the tariff. 
(13) (11)  Following adoption of aggregation through the ordinance described in paragraph (12), (10),  the program shall allow any retail customer to opt out and to continue to be served as a bundled service customer by the existing electrical corporation, or its successor in interest. Delivery services shall be provided at the same rates, terms, and conditions, as approved by the commission, for community choice aggregation customers and customers that have entered into a direct transaction where applicable, as determined by the commission. Once enrolled in the aggregated entity, any ratepayer that chooses to opt out within 60 days or two billing cycles of the date of enrollment may do so without penalty and shall be entitled to receive default service pursuant to paragraph (3) of subdivision (a). Customers that return to the electrical corporation for procurement services shall be subject to the same terms and conditions as are applicable to other returning direct access customers from the same class, as determined by the commission, as authorized by the commission pursuant to this code or any other provision of law, except that those customers shall be subject to no more than a 12-month stay requirement with the electrical corporation.  law.  Any reentry fees to be imposed after the opt-out period specified in this paragraph, paragraph  shall be approved by the commission and shall reflect the cost of reentry. The commission shall exclude any amounts previously determined and paid pursuant to subdivisions (d), (e), and (f) from the cost of reentry.
(14) (12)  Nothing in this section shall be construed as authorizing any city or any community choice retail load aggregator to restrict the ability of retail electricity customers to obtain or receive service from any authorized electric service provider in a manner consistent with law.
(15) (13)  (A) The community choice aggregator shall fully inform participating customers at least twice within two calendar months, or 60 days, in advance of the date of commencing automatic enrollment. Notifications may occur concurrently with billing cycles. Following enrollment, the aggregated entity shall fully inform participating customers for not less than two consecutive billing cycles. Notification may include, but is not limited to, direct mailings to customers, or inserts in water, sewer, or other utility bills. Any notification shall inform customers of both of the following:
(i) That the customer is  they are  to be automatically enrolled and that the customer has the right to opt out of the community choice aggregator without penalty.
(ii) The terms and conditions of the services offered.
(B) The community choice aggregator may request the commission to approve and order the electrical corporation to provide the notification required in subparagraph (A). If the commission orders the electrical corporation to send one or more of the notifications required pursuant to subparagraph (A) in the electrical corporation’s normally scheduled monthly billing process, the electrical corporation shall be entitled to recover from the community choice aggregator all reasonable incremental costs it incurs related to the notification or notifications. The electrical corporation shall fully cooperate with the community choice aggregator in determining the feasibility and costs associated with using the electrical corporation’s normally scheduled monthly billing process to provide one or more of the notifications required pursuant to subparagraph (A).
(C) Each notification shall also include a mechanism by which a ratepayer may opt out of community choice aggregated service. The opt out may take the form of a self-addressed return postcard indicating the customer’s election to remain with, or return to, electrical energy service provided by the electrical corporation, or another straightforward means by which the customer may elect to derive electrical energy service through the electrical corporation providing service in the area.
(16) A community choice aggregator shall have an operating service agreement with the electrical corporation prior to furnishing electric service to consumers within its jurisdiction. The service agreement shall include performance standards that govern the business and operational relationship between the community choice aggregator and the electrical corporation. The commission shall ensure that any service agreement between the community choice aggregator and the electrical corporation includes equitable responsibilities and remedies for all parties. The parties may negotiate specific terms of the service agreement, provided that the service agreement is consistent with this chapter.
(17) (14)  The community choice aggregator shall register with the commission, which may require additional information to ensure compliance with basic consumer protection rules and other procedural matters.
(18) (15)  Once the community choice aggregator’s contract is signed, the community choice aggregator shall notify the applicable electrical corporation that community choice service will commence within 30 days.
(19) (16)  Once notified of a community choice aggregator program, the electrical corporation shall transfer all applicable accounts to the new supplier within a 30-day period from the date of the close of the electrical corporation’s  their  normally scheduled monthly metering and billing process.
(20) (17)  An electrical corporation shall recover from the community choice aggregator any costs reasonably attributable to the community choice aggregator, as determined by the commission, of implementing this section, including, but not limited to, all business and information system changes, except for transaction-based costs as described in this paragraph. Any costs not reasonably attributable to a community choice aggregator shall be recovered from ratepayers, as determined by the commission. All reasonable transaction-based costs of notices, billing, metering, collections, and customer communications or other services provided to an aggregator or its customers shall be recovered from the aggregator or its customers on terms and at rates to be approved by the commission.
(21) (18)  At the request and expense of any community choice aggregator, electrical corporations shall install, maintain, maintain  and calibrate metering devices at mutually agreeable locations within or adjacent to the community choice  aggregator’s political boundaries. The electrical corporation shall read the metering devices and provide the data collected to the community choice  aggregator at the aggregator’s expense. To the extent that the community choice  aggregator requests a metering location that would require alteration or modification of a circuit, the electrical corporation shall only be required to alter or modify a circuit if such alteration or modification does not compromise the safety, reliability, reliability  or operational flexibility of the electrical corporation’s facilities. All costs incurred to modify circuits pursuant to this paragraph paragraph,  shall be borne by the community choice  aggregator.
(d) (1) It is the intent of the Legislature that each retail end-use customer that has purchased power from an electrical corporation on or after February 1, 2001, should bear a fair share of the Department of Water Resources’ electricity purchase costs, as well as electricity purchase contract obligations incurred as of the effective date of the act adding this section, that are recoverable from electrical corporation customers in commission-approved rates. It is further the intent of the Legislature to prevent any shifting of recoverable costs between customers.
(2) The Legislature finds and declares that this subdivision is consistent with the requirements of Division 27 (commencing with Section 80000) of the Water Code and Section 360.5 of this code,  360.5,  and is therefore declaratory of existing law.
(e) A retail end-use customer that purchases electricity from a community choice aggregator pursuant to this section shall pay both of the following:
(1) A charge equivalent to the charges that would otherwise be imposed on the customer by the commission to recover bond-related costs pursuant to any agreement between the commission and the Department of Water Resources pursuant to Section 80110 of the Water Code, which charge shall be payable until any obligations of the Department of Water Resources pursuant to Division 27 (commencing with Section 80000) of the Water Code are fully paid or otherwise discharged.
(2) Any additional costs of the Department of Water Resources, equal to the customer’s proportionate share of the Department of Water Resources’ estimated net unavoidable electricity purchase contract costs as determined by the commission, for the period commencing with the customer’s purchases of electricity from the community choice aggregator, through the expiration of all then existing electricity purchase contracts entered into by the Department of Water Resources.
(f) A retail end-use customer purchasing electricity from a community choice aggregator pursuant to this section shall reimburse the electrical corporation that previously served the customer for all of the following:
(1) The electrical corporation’s unrecovered past undercollections for electricity purchases, including any financing costs, attributable to that customer, that the commission lawfully determines may be recovered in rates.
(2) Any additional costs of the electrical corporation recoverable in commission-approved rates, equal to the share of the electrical corporation’s estimated net unavoidable electricity purchase contract costs attributable to the customer, as determined by the commission, for the period commencing with the customer’s purchases of electricity from the community choice aggregator, through the expiration of all then existing electricity purchase contracts entered into by the electrical corporation.
(g) Estimated net unavoidable electricity costs paid by the customers of a community choice aggregator shall be reduced by the value of any benefits that remain with bundled service customers, unless the customers of the community choice aggregator are allocated a fair and equitable share of those benefits.
(h) (g)  (1) Any charges imposed pursuant to subdivision (e) shall be the property of the Department of Water Resources. Any charges imposed pursuant to subdivision (f) shall be the property of the electrical corporation. The commission shall establish mechanisms, including agreements with, or orders with respect to, electrical corporations necessary to ensure that charges payable pursuant to this section shall be promptly remitted to the party entitled to payment.
(2) Charges imposed pursuant to subdivisions (d), (e), and (f) shall be nonbypassable.
(i) (h)  The  Notwithstanding Section 80110 of the Water Code, the  commission shall authorize community choice aggregation only if the commission imposes a cost-recovery mechanism pursuant to subdivisions (d), (e), (f), and (h). (g).  Except as provided by this subdivision, this section shall not alter the suspension by the commission of direct purchases of electricity from alternate providers other than by community choice aggregators, pursuant to Section 365.1. 80110 of the Water Code. 
(j) (i)  (1) The commission shall not authorize community choice aggregation until it implements a cost-recovery mechanism, consistent with subdivisions (d), (e), and (f), that is applicable to customers that elected to purchase electricity from an alternate provider between February 1, 2001, and January 1, 2003.
(2) The commission shall not authorize community choice aggregation until it has adopted rules for implementing community choice aggregation. submits a report certifying compliance with paragraph (1) to the Senate Energy, Utilities and Communications Committee, or its successor, and the Assembly Committee on Utilities and Commerce, or its successor. 
(k) (3)  (1) The  Except for nonbypassable charges imposed by the commission pursuant to subdivisions (d), (e), (f), and (h), and programs authorized by the commission to provide broader statewide or regional benefits to all customers, electric service customers of a community choice aggregator shall not be required to pay nonbypassable charges for goods, services, or programs that do not benefit either, or where applicable, both, the customer and the community choice aggregator serving the customer.  commission shall not authorize community choice aggregation until it has adopted rules for implementing community choice aggregation. 
(2) The commission, Energy Commission, electrical corporation, or third-party administrator shall administer any program funded through a nonbypassable charge on a nondiscriminatory basis so that the electric service customers of a community choice aggregator may participate in the program on an equal basis with the customers of an electrical corporation.
(3) Nothing in this subdivision is intended to modify, or prohibit the use of, charges funding programs for the benefit of low-income customers.
(l) (1) An electrical corporation shall not terminate the services of a community choice aggregator unless authorized by a vote of the full commission. The commission shall ensure that prior to authorizing a termination of service, that the community choice aggregator has been provided adequate notice and a reasonable opportunity to be heard regarding any electrical corporation contentions in support of termination. If the contentions made by the electrical corporation in favor of termination include factual claims, the community choice aggregator shall be afforded an opportunity to address those claims in an evidentiary hearing.
(2) Notwithstanding paragraph (1), if the Independent System Operator has transferred the community choice aggregator’s scheduling coordination responsibilities to the incumbent electrical corporation, an administrative law judge or assigned commissioner, after providing the aggregator with notice and an opportunity to respond, may suspend the aggregator’s service to customers pending a full vote of the commission.
(m) (1) The commission shall require each community choice aggregator with gross annual revenues exceeding fifteen million dollars ($15,000,000) to annually submit a detailed and verifiable plan to the commission for increasing procurement from small, local, and diverse business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.
(2) (A) The commission shall require each community choice aggregator with gross annual revenues exceeding fifteen million dollars ($15,000,000) to annually submit a report to the commission regarding its procurement from women, minority, disabled veteran, and LGBT business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.
(B) The report shall be in a form that the commission may require and shall be submitted by an annual date that the commission shall designate.
(C) The report shall include women, minority, disabled veteran, and LGBT business enterprises with whom a prime contractor or grantee of a community choice aggregator has engaged in contracts or subcontracts for all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.
(3) The Legislature declares that each community choice aggregator that is not required to submit a plan pursuant to this subdivision is encouraged to voluntarily adopt a plan for increasing procurement from small, local, and diverse business enterprises in all categories.
(n) (j)  Any meeting of an entity authorized to be a community choice aggregator, as defined in Section 331.1, for the purpose of developing, implementing, or administering a program of  The commission shall prepare and submit to the Legislature, on or before January 1, 2006, a report regarding the number of community choices aggregations, the number of customers served by community choice aggregations, third-party suppliers to community choice aggregations, compliance with this section, and the overall effectiveness of  community choice aggregation shall be conducted in the manner prescribed by the Ralph M. Brown Act (Chapter 9 (commencing with Section 54950) of Part 1 of Division 2 of Title 5 of the Government Code). programs. 
(o) For the purposes of this section, “disabled veteran business enterprise,” “LGBT business enterprise,” “minority business enterprise,” “renewable energy project,” and “women business enterprise,” are defined as in Section 8282.

SEC. 10.SEC. 11.

 Section 380 of the Public Utilities Code is amended to read:

380.
 (a) The commission, in consultation with the Independent System Operator, shall establish resource adequacy requirements for all load-serving entities.
(b) In establishing resource adequacy requirements, the commission shall ensure the reliability of electrical service in California while advancing, to the extent possible, the state’s goals for clean energy, reducing air pollution, and reducing emissions of greenhouse gases. The resource adequacy program shall  achieve all of the following objectives:
(1) Facilitate development of new generating, nongenerating, and hybrid  generating  capacity and retention of existing generating, nongenerating, and hybrid  generating  capacity that is economical and needed for reliability and to achieve the state policy specified in Section 454.53. economic and needed. 
(2) Establish new, or maintain existing, demand response products and tariffs that facilitate the economical dispatch and use of demand response that can either meet or reduce an electrical corporation’s resource adequacy requirements, as determined by the commission.
(3) (2)  Equitably allocate the cost of generating capacity and demand response in a manner that prevents the  prevent  shifting of costs between customer classes.
(4) (3)  Minimize enforcement requirements and costs.
(5) Maximize the ability of community choice aggregators to determine the generation resources used to serve their customers.
(c) Each load-serving entity shall maintain physical generating capacity and electrical demand response  adequate to meet its load requirements, including, but not limited to, peak demand and planning and operating reserves. The generating capacity or electrical demand response  shall be deliverable to locations and at times as may be necessary to maintain electrical service system reliability, local area reliability, and flexibility. provide reliable electric service. 
(d) Each load-serving entity shall, at a minimum, meet the most recent minimum planning reserve and reliability criteria approved by the board Board  of directors Trustees  of the Western Systems Coordinating Council or the Western Electricity Coordinating Council.
(e) The commission shall implement and enforce the resource adequacy requirements established in accordance with this section in a nondiscriminatory manner. Each load-serving entity shall be subject to the same requirements for resource adequacy,  adequacy and  the renewables portfolio standard program, and the integrated resource planning process pursuant to Section 454.52 that apply  program that are applicable  to electrical corporations pursuant to this section, or are  otherwise required by law law,  or by order or decision of the commission. The commission shall exercise its enforcement powers to ensure compliance by all load-serving entities.
(f) (1)  The commission shall require sufficient information, including, but not limited to, anticipated load, actual load, and measures undertaken by a load-serving entity to ensure resource adequacy, to be reported to enable the commission to determine compliance with the resource adequacy requirements established by the commission.
(2) The commission shall calculate and publish annually on its internet website, in a new report or as part of another report, the percentage of each load-serving entity’s local and system resource adequacy requirements from the previous calendar year that was met with capacity from eligible renewable energy resources pursuant to the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11)), other zero-carbon resources, including large hydroelectric and nuclear resources, or energy storage resources. In determining the percentage of each load-serving entity’s resource adequacy requirements, the commission shall include all directly owned or contracted resources and each load-serving entity’s allocation of any centrally procured resources or allocation of resources pursuant to any other mechanism that involves an assignment or allocation of resources purchased or owned by a single buyer, and shall exclude any share of a load-serving entity’s resources that were allocated to another load-serving entity.
(g) An electrical corporation’s costs of meeting or reducing  resource adequacy requirements, including, but not limited to, the costs associated with system reliability,  reliability and  local area reliability, or flexible resource adequacy,  that are determined to be reasonable by the commission, or are otherwise recoverable under a procurement plan approved by the commission pursuant to Section 454.5, shall be fully recoverable from those customers on whose behalf the costs are incurred, as determined by the commission, at the time the commitment to incur the cost is made,  made or thereafter,  on a fully nonbypassable basis, as determined by the commission. The commission shall exclude any amounts authorized to be recovered pursuant to Section 366.2 when authorizing the amount of costs to be recovered from customers of a community choice aggregator or from customers that purchase electricity through a direct transaction pursuant to this subdivision.
(h) The commission shall determine and authorize the most efficient and equitable means for achieving all of the following:
(1) Meeting the objectives of this section.
(2) Ensuring that investment is made in new generating capacity.
(3) Ensuring that existing generating capacity that is economical economic  is retained.
(4) Ensuring that the cost of generating capacity and demand response  is allocated equitably.
(5) Ensuring that community choice aggregators can determine the generation resources used to serve their customers.
(6) Ensuring that investments are made in new and existing demand response resources that are cost effective and help to achieve electrical grid reliability and the state’s goals for reducing emissions of greenhouse gases.
(7) Minimizing the need for backstop procurement by the Independent System Operator.
(i) In making the determination pursuant to subdivision (h), the commission may consider a centralized resource adequacy mechanism among other options.
(j) The commission shall ensure appropriate valuation of both supply and load modifying demand response resources. The commission, in an existing or new proceeding, shall establish a mechanism to value load modifying demand response resources, including, but not limited to, the ability of demand response resources to help meet distribution needs and transmission system needs and to help reduce a load-serving entity’s resource adequacy obligation pursuant to this section. In determining this value, the commission shall consider how these resources further the state’s electrical grid reliability and the state’s goals for reducing emissions of greenhouse gases. The commission, Energy Commission, and Independent System Operator shall jointly ensure that changes in demand caused by load modifying demand response are expeditiously and comprehensively reflected in the Energy Commission’s Integrated Energy Policy Report forecast and in planning proceedings and associated analyses, and shall encourage reflection of these changes in demand in the operation of the grid.
(k) (j)  For purposes of this section, “load-serving entity” means an electrical corporation, electric service provider, or community choice aggregator. “Load-serving entity” does not include any of the following:
(1) A local publicly owned electric utility.
(2) The State Water Resources Development System commonly known as the State Water Project.
(3)   Customer generation located on the customer’s site or providing electric service through arrangements authorized by Section 218, if the customer generation, or the load it serves, meets one of the following criteria:
(A) It takes standby service from the electrical corporation on a commission-approved rate schedule that provides for adequate backup planning and operating reserves for the standby customer class.
(B) It is not physically interconnected to the electrical electric  transmission or distribution grid, so that, if the customer generation fails, backup electricity is not supplied from the electrical electricity  grid.
(C) There is physical assurance that the load served by the customer generation will be curtailed concurrently and commensurately with an outage of the customer generation.

SEC. 11.SEC. 12.

 Section 387 of the Public Utilities Code is amended to read:

387.
 (a) For purposes of this article, the following terms have the following meanings:
(1) “Carbon-free electrical resource” means a source of electrical generation that emits no greenhouse gases when generating electricity that is deliverable to retail end-use customers in California.
(2) “Load-serving entity” has the same meaning as defined in Section 380.
(3) (a)  “Provider of last resort” means a load-serving entity that the commission determines meets the minimum requirements of this article and designates to provide electrical service to any retail customer whose service is transferred to the designated load-serving entity because the customer’s load-serving entity failed to provide, or denied, service to the customer or otherwise failed to meet its obligations. 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. 
(b) The provider of last resort shall be the electrical corporation in its service territory unless provided otherwise in a service territory boundary agreement entered into pursuant to Article 1 (commencing with Section 8101) of Chapter 6 of Division 4, or unless another load-serving entity is designated by the commission pursuant to subdivision (c) or (d).
(c) The commission may designate a load-serving entity other than the electrical corporation to serve as a provider of last resort in the electrical corporation’s service territory by approving a joint application by the electrical corporation and the load-serving entity that proposes to become the new provider of last resort in the electrical corporation’s service territory. The application may request a transfer of the responsibilities of the provider of last resort for the entire service territory of the electrical corporation or for a portion of that service territory. The application shall include all of the following:
(1) A demonstrated ability by the load-serving entity seeking to become the new provider of last resort to post a bond sufficient to meet the minimum threshold established pursuant to subdivision (e).
(2) A demonstrated history of contracting for electricity and access to carbon-free electrical resources by the load-serving entity seeking to become provider of last resort.
(3) A viable plan for meeting the resource adequacy requirements established pursuant to Section 380, the requirements of the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11)), and all other load-serving entity procurement requirements.
(4) A history of the load-serving entity seeking to become the provider of last resort participating in, and complying with the requirements of, the integrated resource planning process pursuant to Sections 454.51, 454.52, and 454.54, and all other load-serving entity procurement requirements.
(5) The full disclosure by the load-serving entity seeking to become the provider of last resort of any fines or penalties imposed by, or violations of law found by, any regulatory body of any state or territory, or the federal government.
(6) A detailed history of the safety record of the load-serving entity seeking to become the provider of last resort.
(7) An implementation plan to provide for universal access, equitable treatment of all classes of customers, and other customer protections including electric service disconnection procedures consistent with Sections 718 and 779.3.
(d) The commission shall develop a process to facilitate a joint application from load-serving entities that are not electrical corporations to request to transfer the responsibilities of the provider of last resort. This process shall apply when one load-serving entity that is not an electrical corporation has already been designated as a provider of last resort, as described in subdivision (c). The commission may approve a joint application by the designated provider of last resort and the load-serving entity that proposes to become the new provider of last resort in the service territory. The application may request a transfer of responsibilities of the provider of last resort for the entire service territory or for a portion of that service territory. The application shall include all of the elements described in subdivision (c). All of the requirements of this article are applicable to the load-serving entity that proposes to become the new provider of last resort in the applicable service territory.
(e) While a load-serving entity is serving as the new provider of last resort pursuant to subdivision (c) or (d), the commission shall not enforce the provider of last resort requirements on the former provider or providers of last resort.
(f) The commission shall develop additional threshold attributes for a load-serving entity other than an electrical corporation to serve as a provider of last resort to retail end-use customers in California that include all of the following:
(1) Minimum insurance requirements.
(2) Minimum financial requirements necessary to provide electricity to retail end-use customers in each service territory.
(3) Compliance with resource adequacy requirements pursuant to Section 380, requirements of the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11)), integrated resource planning requirements pursuant to Sections 454.51, 454.52, and 454.54, and all other state-mandated procurement requirements.
(4) Electric service disconnection rules pursuant to Sections 718 and 779.3.
(5) Any additional minimum requirements that the commission determines are needed to ensure that the provider of last resort will perform its obligation to serve.
(g) The commission shall ensure that the provider of last resort for each service territory receives reasonable cost recovery for being designated and serving as a provider of last resort.
(h) (b)  To ensure continued achievement of California’s greenhouse gas emission reduction and air quality goals, and continued accounting of emissions of greenhouse gases for California pursuant to Part 2 (commencing with Section 38530) of Division 25.5 of the Health and Safety Code and other emissions reporting programs, in preparation for an unplanned customer migration to a provider of last resort, the commission, in consultation with the Energy Commission, may do both of  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,  the following:
(1) Establish rules for all load-serving entities in preparation of any potentially large and unplanned customer migration. 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) Recommend to agencies modifications to relevant regulations.
(i) (2)  Notwithstanding any other law, electrical corporations shall continue to provide all metering, billing, and collection to retail customers served by the provider of last resort. Bills sent by an electrical corporation to retail customers shall identify the designated provider of last resort. The commission shall determine the terms and conditions under which the electrical corporation provides these services to the provider of last resort. 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. 
(j) The commission shall supervise and regulate each provider of last resort, as necessary, as a public utility for the services provided by the provider of last resort pursuant to this article to ensure the provision of electrical service to customers without disruption if a load-serving entity fails to provide, or denies, service to any retail end-use customer in California for any reason. The commission may do all things that are necessary and convenient in the exercise of this power.
(k) (3)  This section does not limit the authority of the commission to regulate the terms of service or establish requirements for provider of last resort service by an electrical corporation or any new provider of last resort. 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. 

SEC. 12.SEC. 13.

 Section 387.5 of the Public Utilities Code is amended to read:

387.5.
 (a) In order to further the state goal of encouraging the installation of 3,000 megawatts of photovoltaic solar energy in California within 10 years, the governing body of a local publicly owned electric utility that sells electricity at retail, shall adopt, implement, and finance a solar initiative program, funded in accordance with subdivision (b), for the purpose of investing in, and encouraging the increased installation of, residential and commercial solar energy systems.
(b) On or before January 1, 2008, a local publicly owned electric utility shall offer monetary incentives for the installation of solar energy systems of at least two dollars and eighty cents ($2.80) per installed watt, or for the electricity produced by the solar energy system, measured in kilowatthours, as determined by the governing board of a local publicly owned electric utility, for photovoltaic solar energy systems. The incentive level shall decline each year thereafter at a rate of no less than an average of 7 percent per year.
(c) A local publicly owned electric utility shall initiate a public proceeding to fund a solar energy program to adequately support the goal of installing 3,000 megawatts of photovoltaic solar energy in California. The proceeding shall determine what additional funding, if any, is necessary to provide the incentives pursuant to subdivision (b). The public proceeding shall be completed and the comprehensive solar energy program established by January 1, 2008.
(d) The solar energy program of a local publicly owned electric utility shall be consistent with all of the following:
(1) That a solar energy system receiving monetary incentives comply with the eligibility criteria, design, installation, and electrical output standards or incentives established by the State Energy Resources Conservation and Development Commission pursuant to Section 25782 of the Public Resources Code.
(2) That solar energy systems receiving monetary incentives are intended primarily to offset part or all of the consumer’s own electricity demand.
(3) That all components in the solar energy system are new and unused, and have not previously been placed in service in any other location or for any other application.
(4) That the solar energy system has a warranty of not less than 10 years to protect against defects and undue degradation of electrical generation output.
(5) That the solar energy system be located on the same premises of the end-use consumer where the consumer’s own electricity demand is located.
(6) That the solar energy system be connected to the electric utility’s electrical distribution system within the state.
(7) That the solar energy system has meters or other devices in place to monitor and measure the system’s performance and the quantity of electricity generated by the system.
(8) That the solar energy system be installed in conformance with the manufacturer’s specifications and in compliance with all applicable electrical and building code standards.
(e) A local publicly owned electric utility shall, on an annual basis beginning June 1, 2008, make available to its customers, to the Legislature, and to the State Energy Resources Conservation and Development Commission, information relating to the utility’s solar initiative program established pursuant to this section, including, but not limited to, the number of photovoltaic solar watts installed, the total number of photovoltaic systems installed, the total number of applicants, the amount of incentives awarded, and the contribution toward the program goals.
(f) In establishing the program required by this section, no moneys shall be diverted from any existing programs for low-income ratepayers, or from cost-effective energy efficiency or demand response programs.
(g) The statewide expenditures for solar programs adopted, implemented, and financed by local publicly owned electric utilities shall be seven hundred eighty-four million dollars ($784,000,000). The expenditure level for each local publicly owned electric utility shall be based on that utility’s percentage of the total statewide load served by all local publicly owned electric utilities. Expenditures by a local publicly owned electric utility may be less than the utility’s cap amount, provided that funding is adequate to provide the incentives required by subdivisions (a) and (b).

SEC. 13.SEC. 14.

 Section 394.5 of the Public Utilities Code is amended to read:

394.5.
 (a) Except for an electrical corporation as defined in Section 218, or a local publicly owned electric utility offering electrical service to residential and small commercial customers within its service territory, each electric service provider offering electrical service to residential and small commercial customers shall, prior to the commencement of service, provide the potential customer with a written notice of the service describing the price, terms, and conditions of the service. A notice The notices  shall include all of the following:
(1) A clear description of the price, terms, and conditions of service, including:
(A) The price of electricity expressed in a format that which  makes it possible for residential and small commercial customers to compare and select among similar products and services on a standard basis. The commission shall adopt rules to implement this subdivision. The commission shall require disclosure of the total price of electricity on a cents-per-kilowatthour basis, including the costs of all electric services and charges regulated by the commission. The commission shall also require estimates of the total monthly bill for the electric service at varying consumption levels, including the costs of all electric services and charges regulated by the commission. In determining these rules, the commission may consider alternatives to the cents-per-kilowatthour disclosure if other information would provide the customer with sufficient information to compare among alternatives on a standard basis.
(B) Separate disclosure of all recurring and nonrecurring charges associated with the sale of electricity.
(C) If services other than electricity are offered, an itemization of the services and the charge or charges associated with each.
(2) An explanation of the applicability and amount of the competition transition charge, as determined pursuant to Sections 367 to 376, inclusive.
(3) A description of the potential customer’s right to rescind the contract without fee or penalty as described in Section 395.
(4) An explanation of the customer’s financial obligations, as well as the procedures regarding past due payments, discontinuance of service, billing disputes, and service complaints.
(5) The electric service provider’s registration number, if applicable.
(6) The right to change service providers upon written notice, including disclosure of any fees or penalties assessed by the supplier for early termination of a contract.
(7) A description of the availability of low-income assistance programs for qualified customers and how customers can apply for these programs.
(b) The commission may assist electric service providers in developing the notice. The commission may suggest inclusion of additional information it deems necessary for the consumer protection purposes of this section. On at least a semiannual basis, electric service providers shall provide the commission with a copy of the form of notice included in standard service plans made available to residential and small commercial customers. customers as described in subdivision (a) of Section 392.1. 
(c) An Any  electric service provider offering electric services who declines to provide those services to a consumer shall, upon request of the consumer, disclose to that consumer the reason for the denial in writing within 30 days. At the time service is denied, the electric service provider shall disclose to the consumer the  his or her  right to make this request. A consumer  Consumers  shall have at least 30 days from the date service is denied to make the request.

SEC. 14.SEC. 15.

 Section 395.5 of the Public Utilities Code is amended to read:

395.5.
 (a) For purposes of this section, the following terms have the following meanings:
(1) “Nonprofit charitable organization” means any charitable organization described in Section 501(c)(3) of the federal Internal Revenue Code that has as its primary purpose serving the needs of the poor or elderly.
(2) “Electric commodity” means electricity used by the customer or a supply of electricity available for use by the customer, and does not include services associated with the transmission and distribution of electricity.
(b) Notwithstanding Section 80110 of the Water Code, a nonprofit charitable organization may acquire electric commodity service through a direct transaction with an electric service provider if electric commodity service is donated free of charge without compensation.
(c) A nonprofit charitable organization that acquires donated electric commodity service through a direct transaction pursuant to this section shall be responsible for paying all of the following:
(1) Those charges and surcharges that would be imposed upon a retail end-use customer of a community aggregator pursuant to subdivisions (d), (e), (f), and (g) of Section 366.2.
(2) The transmission and distribution charges of an electrical corporation or a local publicly owned electric utility.
(3) A nonbypassable charge imposed pursuant to Article 7 (commencing with Section 381), Article 8 (commencing with Section 385), or Article 15 (commencing with Section 399).
(4) Costs imposed upon a load-serving entity pursuant to Section 380.
(d) Existing direct access rules and all service obligations otherwise applicable to electric service providers shall govern transactions under this section.
(e) This section shall remain in effect only until January 1, 2010, and as of that date is repealed, unless a later enacted statute, that is enacted before January 1, 2010, deletes or extends that date.

SEC. 16.

 The heading of Article 15 (commencing with Section 399) of Chapter 2.3 of Part 1 of Division 1 of the Public Utilities Code, as added by Section 4 of Chapter 1051 of the Statutes of 2000, is repealed.

SEC. 16.SEC. 17.

 Section 399.1 of the Public Utilities Code is repealed.

SEC. 17.SEC. 18.

 Section 399.12 of the Public Utilities Code is amended to read:

399.12.
 For purposes of this article, 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) “Balancing authority” means the responsible entity that integrates resource plans ahead of time, maintains load-interchange generation balance within a balancing authority area, and supports interconnection frequency in real time.
(c) “Balancing authority area” means the collection of generation, transmission, and loads within the metered boundaries of the area within which the balancing authority maintains the electrical load-resource balance.
(d) (b)  “California balancing authority” is a balancing authority with control over a balancing authority area primarily located in this state and operating for retail sellers and local publicly owned electric utilities subject to the requirements of this article and includes the Independent System Operator (ISO) and a local publicly owned electric utility operating a transmission grid that is not under the operational control of the ISO. A California balancing authority is responsible for the operation of the transmission grid within its metered boundaries which is not limited by the political boundaries of the State of California. “Delivered” and “delivery” have the same meaning as provided in subdivision (a) of Section 25741 of the Public Resources Code. 
(e) (c)  “Eligible renewable energy resource” means an electrical electric  generating facility that meets the definition of a “renewable electrical “in-state renewable electricity  generation facility” in Section 25741 of the Public Resources Code, subject to the following: following limitations: 
(1) (A) (A) An  An  existing small hydroelectric generation facility of 30 megawatts or less shall be eligible only if a retail seller or local publicly owned electric utility owned or  procured the electricity from the facility as of December 31, 2005. A new hydroelectric facility that commences generation of electricity after December 31, 2005,  is not an eligible renewable energy resource if it will cause an adverse impact on instream beneficial uses or cause a change in the volume or timing of streamflow.
(B) Notwithstanding subparagraph (A), a conduit hydroelectric facility of 30 megawatts or less that commenced operation before January 1, 2006, is an eligible renewable energy resource. A conduit hydroelectric facility of 30 megawatts or less that commences operation after December 31, 2005, is an eligible renewable energy resource so long as it does not cause an adverse impact on instream beneficial uses or cause a change in the volume or timing of streamflow.
(C) A facility approved by the governing board of a local publicly owned electric utility prior to June 1, 2010, for procurement to satisfy renewable energy procurement obligations adopted pursuant to former Section 387, shall be certified as an eligible renewable energy resource by the Energy Commission pursuant to this article, if the facility is a “renewable electrical generation facility” as defined in Section 25741 of the Public Resources Code.
(D) (i) A small hydroelectric generation unit with a nameplate capacity not exceeding 40 megawatts that is operated as part of a water supply or conveyance system is an eligible renewable energy resource only for the retail seller or local publicly owned electric utility that procured the electricity from the unit as of December 31, 2005. No unit shall be eligible pursuant to this subparagraph if an application for certification is submitted to the Energy Commission after January 1, 2013. Only one retail seller or local publicly owned electric utility shall be deemed to have procured electricity from a given unit as of December 31, 2005.
(ii) Notwithstanding clause (i), a local publicly owned electric utility that meets the criteria of subdivision (j) of Section 399.30 may sell to another local publicly owned electric utility electricity from small hydroelectric generation units that qualify as eligible renewable energy resources under clause (i), and that electricity may be used by the local publicly owned electric utility that purchased the electricity to meet its renewables portfolio standard procurement requirements. The total of all those sales from the utility shall be no greater than 100,000 megawatthours of electricity.
(iii) The amendments made to this subdivision by the act adding this subparagraph are intended to clarify existing law and apply from December 10, 2011.
(2) (A)  A facility engaged in the combustion of municipal solid waste shall not be considered an eligible renewable energy resource. resource unless it is located in Stanislaus County and was operational prior to September 26, 1996. 
(B) Subparagraph (A) does not apply to generation before January 1, 2017, from a facility located in Stanislaus County that was operational prior to September 26, 1996.
(f) (d)  “Procure” means to acquire through ownership or contract. that a retail seller or local publicly owned electric utility 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 article 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 article or the obligation of a local publicly owned electric utility to meet its renewables portfolio standard implemented pursuant to Section 387. 
(g) (e)  “Procurement entity” means any person or corporation authorized by the commission to enter into contracts to procure  “Renewables portfolio standard” means the specified percentage of electricity generated by  eligible renewable energy resources on behalf of customers of  that  a retail seller pursuant to subdivision (f) of Section 399.13. is required to procure pursuant to this article or the obligation of a local publicly owned electric utility to meet its renewables portfolio standard implemented pursuant to Section 387. 
(h) (f)  (1) (1) “Renewable  “Renewable  energy credit” means a certificate of proof associated with the generation of electricity from an eligible renewable energy resource,  proof,  issued through the accounting system established by the Energy Commission pursuant to Section 399.25, 399.13,  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.
(3) (A) No  Electricity   electricity  generated by an eligible renewable energy resource attributable to the use of nonrenewable fuels, beyond a de minimis quantity used to generate electricity in the same process through which the facility converts renewable fuel to electricity, shall not  minimus quantity, as determined by the Energy Commission, shall  result in the creation of a renewable energy credit. The Energy Commission shall set the de minimis quantity of nonrenewable fuels for each renewable energy technology at a level of no more than 2 percent of the total quantity of fuel used by the technology to generate electricity. The Energy Commission may adjust the de minimis quantity for an individual facility, up to a maximum of 5 percent, if it finds that all of the following conditions are met: 
(i) The facility demonstrates that the higher quantity of nonrenewable fuel will lead to an increase in generation from the eligible renewable energy facility that is significantly greater than generation from the nonrenewable fuel alone.
(ii) The facility demonstrates that the higher quantity of nonrenewable fuels will reduce the variability of its electrical output in a manner that results in net environmental benefits to the state.
(iii) The higher quantity of nonrenewable fuel is limited to either natural gas or hydrogen derived by reformation of a fossil fuel.
(B) Electricity generated by a small hydroelectric generation facility shall not result in the creation of a renewable energy credit unless the facility meets the requirements of subparagraph (A) or (D) of paragraph (1) of subdivision (e).
(C) Electricity generated by a conduit hydroelectric generation facility shall not result in the creation of a renewable energy credit unless the facility meets the requirements of subparagraph (B) of paragraph (1) of subdivision (e).
(D) Electricity generated by a facility engaged in the combustion of municipal solid waste shall not result in the creation of a renewable energy credit. This subparagraph does not apply to renewable energy credits that were generated before January 1, 2017, by a facility engaged in the combustion of municipal solid waste located in Stanislaus County that was operational prior to September 26, 1996, and sold pursuant to contacts entered into before January 1, 2017.
(i) “Renewables portfolio standard” means the specified percentage of electricity generated by eligible renewable energy resources that a retail seller or a local publicly owned electric utility is required to procure pursuant to this article.
(j) (g)  “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:
(1) An electrical corporation, as defined in Section 218.
(2) A community choice aggregator. A  The commission shall institute a rulemaking to determine the manner in which a  community choice aggregator shall will  participate in the renewables portfolio standard program subject to the same terms and conditions applicable to an electrical corporation.
(3) An electric service provider, as defined in Section 218.3. The electric service  218.3, for all sales of electricity to customers beginning January 1, 2006. The commission shall institute a rulemaking to 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 article. This paragraph does not  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.
(4) “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.
(C) A local publicly owned electric utility.
(k) “WECC” means the Western Electricity Coordinating Council of the North American Electric Reliability Corporation, or a successor to the corporation.

SEC. 19.

 Section 399.12.5 of the Public Utilities Code is amended to read:

399.12.5.
 (a) Notwithstanding subdivision (e) (c)  of Section 399.12, a small hydroelectric generation facility that satisfies the criteria for an eligible renewable energy resource pursuant to Section 399.12 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.
(b) Notwithstanding subdivision (e) (c)  of Section 399.12, 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:
(1) 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.
(2) The hydroelectric generation facility meets one of the following certification mechanisms:
(A) (2)  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 federal  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 not subject to  exempt from  certification because there is no potential for discharge into waters of the United States.
(B) If the hydroelectric facility is not located in California, the certification pursuant to Section 401 of the federal Clean Water Act (33 U.S.C. Sec. 1341) may be received from the applicable state board or agency or from a regional board to which the state board has delegated authority to issue the certification.
(C) If the hydroelectric generation facility is the Rock Creek Powerhouse, Federal Energy Regulatory Commission Project Number 1962, the efficiency improvements have received any necessary incremental certification from the State Water Resources Control Board.
(3) The hydroelectric generation facility is owned by a retail seller or a local publicly owned electric utility,  was operational prior to 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.
(4) 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.
(c) The incremental increase in the amount of electricity generated from a hydroelectric generation facility as a result of efficiency improvements at the facility are not eligible for supplemental energy payments pursuant to the Renewable Energy Resources Program (Chapter 8.6 (commencing with Section 25740) of Division 15 of the Public Resources Code), or a successor program.
(d) Notwithstanding subdivision (e) of Section 399.12 and subdivisions (a) and (b), a hydroelectric generation facility that is an eligible renewable energy resource pursuant to this article as of January 1, 2010, shall not lose its eligibility if the facility causes a change in the volume or timing of streamflow required by license conditions approved pursuant to the Federal Power Act (Chapter 12 (commencing with Section 791a) of Title 16 of the United States Code) on or after January 1, 2010.

SEC. 18.SEC. 20.

 Section 399.25 of the Public Utilities Code is amended and renumbered to read:

399.25. 399.2.5. 
 The (a)   Energy Commission shall do all of the following: Notwithstanding any other provision in Sections 1001 to 1013, inclusive, an application of an electrical corporation for a certificate authorizing the construction of new transmission facilities shall be deemed to be necessary to the provision of electric service for purposes of any determination made under Section 1003 if the commission finds that the new facility is necessary to facilitate achievement of the renewable power goals established in Article 16 (commencing with Section 399.11). 
(a) (b)  Certify eligible renewable energy resources that it determines meet the criteria  With respect to a transmission facility  described in subdivision (e) of Section 399.12. (a), the commission shall take all feasible actions to ensure that the transmission rates established by the Federal Energy Regulatory Commission are fully reflected in any retail rates established by the commission. These actions shall include, but are not limited to: 
(b) (1)  Design and implement an accounting system to verify compliance with the renewables portfolio standard by retail sellers and local publicly owned electric utilities, to ensure that electricity generated by an eligible renewable energy resource is counted only once for the purpose of meeting  Making findings, where supported by an evidentiary record, that those transmission facilities provide benefit to the transmission network and are necessary to facilitate the achievement of  the renewables portfolio standard of this state or any other state, to certify renewable energy credits produced by eligible renewable energy resources, and to verify retail product claims in this state or any other state. 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 and local publicly owned electric utilities, in accordance with the requirements of this article and the California Public Records Act (Division 10  established in Article 16  (commencing with Section 7920.000) 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. 399.11). 
(c) (2)  Establish a system for tracking and verifying renewable energy credits that, through the use of independently audited data, verifies the generation 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. Directing the utility to which the generator will be interconnected, where the direction is not preempted by federal law, to seek the recovery through general transmission rates of the costs associated with the transmission facilities. 
(3) Asserting the positions described in paragraphs (1) and (2) to the Federal Energy Regulatory Commission in appropriate proceedings.
(d) (4)  Certify, for purposes of compliance with the renewables portfolio standard requirements by a retail seller, the eligibility of renewable energy credits associated with eligible renewable energy resources procured by a local publicly owned electric utility, if the Energy Commission determines that all of the conditions of Section 399.31 have been met. Allowing recovery in retail rates of any increase in transmission costs incurred by an electrical corporation resulting from the construction of the transmission facilities that are not approved for recovery in transmission rates by the Federal Energy Regulatory Commission after the commission determines that the costs were prudently incurred in accordance with subdivision (a) of Section 454. 

SEC. 21.

 The heading of Article 5 (commencing with Section 445) of Chapter 2.5 of Part 1 of Division 1 of the Public Utilities Code is repealed.

SEC. 20.SEC. 22.

 Section 701.8 of the Public Utilities Code is amended to read:

701.8.
 (a) To ensure that electrical corporations do not operate their transmission and distribution monopolies in a manner that impedes the ability of the San Francisco Bay Area Rapid Transit District (BART District) to reduce its electricity cost through the purchase and delivery of preference power, electrical corporations shall meet the requirements of this section.
(b) Any electrical corporation that owns and operates transmission and distribution facilities that deliver electricity at one or more locations to the BART District’s system shall, upon request by the BART District, and without discrimination or delay, use the same facilities to do any or all of the following: deliver preference power purchased from a federal power marketing agency or its successor, or electricity purchased from a local publicly owned electric utility. 
(1) Deliver preference power purchased from a federal power marketing agency or its successor.
(2) Deliver electricity purchased from a local publicly owned electric utility.
(3) Deliver electricity generated by an eligible renewable energy resource.
(4) Deliver electricity purchased from an electrical corporation or marketer.
(5) Deliver electricity purchased through a market operated by the Independent System Operator.
(c) Where the BART District purchases electricity at more than one location, at any voltage, from an electric utility under tariffs regulated by the commission, the utility shall bill the BART District for usage as though all the electricity purchased at transmission level voltages were metered by a single meter at one location and all the electricity purchased at subtransmission voltages were metered by a single meter at one location, provided that any billing for demand charges would be based on the coincident demand of transmission and distribution metering.
(d) If, on or after January 1, 1996, the BART District leases or has agreed to lease, as special facilities, utility plants for the purpose of receiving power at transmission level voltages, an electrical corporation may not terminate the lease without concurrence from the BART District.
(e) When the BART District elects to have electricity delivered pursuant to subdivision (b), neither  Sections 365, 365.1,  365  and 366, and any commission regulations, orders, or tariffs, that implement direct transactions, are inapplicable, and  applicable, nor is  the BART District is not  an electricity supplier. Neither the commission, nor any electrical corporation that delivers the electricity described in subdivision (b)  federal power or electricity purchased from a local publicly owned electric utility  to the BART District, shall require that an electricity supplier be designated as a condition of the delivery of that electricity. power. 
(f) The BART District may elect to obtain electricity from the following multiple sources at the same time:
(1) Electricity delivered pursuant to subdivision (b).
(2) Electricity supplied by one or more direct transactions.
(3) Electricity from any electrical corporation that owns and operates transmission and distribution facilities that deliver electricity at one or more locations to the BART District’s system.
(g) The BART District shall annually report to the Energy Commission the information for the previous calendar year required of retail electricity suppliers in Article 14 (commencing with Section 398.1) of Chapter 2.3, including all of the following:
(1) The kilowatthours purchased from specified sources, by generator and fuel type during the previous calendar year, consistent with meter data, including losses, reported to the system operator.
(2) The kilowatthours purchased from unspecified sources in California and from unspecified sources imported into California from other subregions within the Western Electricity Coordinating Council.
(3) The kilowatthours consumed by the BART District.
(h) For purposes of this section, the following terms have the following meanings:
(1) “Electricity from specified sources” or “purchases from specified sources” means electricity transactions that are traceable to a specific generation source by any auditable contract trail or equivalent, such as a tradable commodity system, that provides commercial verification that the electricity source claimed has been sold once, and only once, to an end user. The BART District may rely on annual data to determine whether a transaction meets this definition, rather than hour-by-hour matching of loads and resources.
(2) “Electricity from unspecified sources” or “purchases from unspecified sources” means electricity that is not traceable to a specific generation source by any auditable contract trail or equivalent, including a tradable commodity system, that provides commercial verification that the electricity source claimed has been sold once, and only once, to an end user.
(3) “Eligible renewable energy resources” means an eligible renewable energy resource pursuant to the California Renewables Portfolio Standard Program (Article 16 (commencing with Section 399.11) of Chapter 2.3).
(4) “Marketer” has the same meaning as defined in subdivision (e) of Section 331.
(5) “System operator” has the same meaning as defined in Section 398.2.

SEC. 21.SEC. 23.

 Section 761.3 of the Public Utilities Code is amended to read:

761.3.
 (a) Notwithstanding subdivision (g) of Section 216 and subdivision (c) of Section 218.5, the commission shall implement and enforce standards for the maintenance and operation of facilities for the generation and storage  of electricity owned by an electrical corporation or located in the state to ensure their reliable operation. The commission shall enforce the protocols for the scheduling of powerplant outages of the Independent System Operator.
(b) This section does not authorize Nothing in this section authorizes  the commission to establish rates for wholesale sales in interstate commerce from those facilities, or to approve the sale or transfer of control of facilities if an exempt wholesale generator, as defined in the federal  Public Utility Holding Company Act of 2005 (42 U.S.C. Sec. 16451(6)).
(c) (1) (A) Except as otherwise provided in this subdivision, this section does shall  not apply to nuclear powered generating facilities that are federally regulated and subject to standards developed by the Nuclear Regulatory Commission Commission,  and that participate as members of the Institute of Nuclear Power Operations.
(B) The owner or operator of a nuclear powered generating facility shall file with the Oversight Board and the  commission an annual schedule of maintenance, including repairs and upgrades, updated quarterly, for each generating facility. The owner or operator of a nuclear powered generating facility shall make good faith efforts to conduct its maintenance in compliance with its filed plan and shall report to the Oversight Board and the  Independent System Operator any significant variations from its filed plan.
(C) The owner or operator of a nuclear powered generating facility shall report on a monthly basis to the Oversight Board and the  commission all actual planned and unplanned outages of each facility during the preceding month. The owner or operator of a nuclear powered generating facility shall report on a daily basis to the Oversight Board and the  Independent System Operator the daily operational status and availability of each facility.
(2) (A) Except as otherwise provided in this subdivision, this section does shall  not apply to a qualifying small power production facility or a qualifying cogeneration facility within the meaning of Sections 201 and 210 of Title 11 of the federal Public Utility Regulatory Policies Act of 1978 (16 U.S.C. Secs. 796(17), 796(18), and 824a-3), and the regulations adopted pursuant to those sections by the Federal Energy Regulatory Commission (18 C.F.R. Secs. 292.101 to 292.602, inclusive), nor does shall  this section apply to other generation units installed, operated, and maintained at a customer site site,  exclusively to serve that customer’s load.
(B) An electrical corporation that has a contract with a qualifying small power production facility, or a qualifying cogeneration facility, with a name plate  nameplate  rating of 10 megawatts or greater, shall report to the Oversight Board and the  commission maintenance schedules for each facility, including all actual planned and unplanned outages of the facility and the daily operational status and availability of the facility. Each facility with a name plate rating of 10 megawatts or greater shall be responsible for directly reporting to the Oversight Board and the  Independent System Operator maintenance schedules for each facility, including all actual planned and unplanned outages of the facility and the daily operational status and availability of the facility, if that information is not provided to the electrical corporation pursuant to a contract.
(d) This  Nothing in this  section shall not  result in the modification, delay, or abrogation of any deadline, standard, rule, or regulation adopted by a federal, state, or local agency for the purposes of protecting public health or the environment, including, but not limited to, any requirements imposed by the State Air Resources Board or by an air pollution control district or an air quality management district pursuant to Division 26 (commencing with Section 39000) of the Health and Safety Code. The Independent System Operator shall consult with the State Air Resources Board and the appropriate local air pollution control districts and air quality management districts to coordinate scheduled outages to provide for compliance with those retrofits.
(e) The Independent System Operator shall maintain records of generation and storage  facility outages and shall provide those records to the Oversight Board and the  commission on a daily basis. Each entity that owns or operates an electric generating unit in California with a rated maximum capacity of 10 megawatts or greater greater,  shall provide a monthly report to the Independent System Operator that identifies any periods during the preceding month when the unit was unavailable to produce electricity or was available only at reduced capacity. The report shall identify the reasons for any such unscheduled unavailability or reduced capacity. The Independent System Operator shall immediately transmit the information to the Oversight Board and the  commission.
(f) This section does not apply to any of the following:
(1) A facility  Facilities  owned by a local publicly owned electric utility.
(2) A Any  public agency that may generate electricity incidental to the provision of water or wastewater treatment.
(3) A facility  Facilities  owned by a city and county operating as a public utility, furnishing electric service as provided in Section 10001.
(g) (1) In order to ensure the safety of employees, emergency responders, and surrounding communities, each battery energy storage facility located in the state and subject to subdivision (a) shall have an emergency response and emergency action plan that covers the premises of the battery energy storage facility, consistent with Sections 142.3 and 6401 of the Labor Code and any related regulations, including the regulatory requirements applicable to emergency action plans pursuant to Section 3220 of Title 8 of the California Code of Regulations.
(2) The emergency response and emergency action plan shall do all of the following:
(A) Establish response procedures for an equipment malfunction or failure.
(B) Include procedures that provide for the safety of surrounding residents, neighboring properties, emergency responders, and the environment. These procedures shall be established in consultation with local emergency management agencies.
(C) Establish notification and communication procedures between the battery energy storage facility and local emergency management agencies.
(3) The emergency response and emergency action plan may do all of the following:
(A) Consider responses to potential offsite impacts, including, but not limited to, poor air quality, threats to municipal water supplies, water runoff, and threats to natural waterways.
(B) Include procedures for the local emergency response agency to establish shelter-in-place orders and road closure notifications when appropriate.
(4) In developing the emergency response and emergency action plan, the owner or operator of the battery energy storage facility shall coordinate with local emergency management agencies, unified program agencies, and local first response agencies.
(5) The owner or operator of each battery energy storage facility shall submit the emergency response and emergency action plan to the county and, if applicable, the city where the facility is located.

SEC. 22.SEC. 24.

 Section 848 of the Public Utilities Code is amended to read:

848.
 For the purposes of this article, the following terms shall have the following meanings:
(a) “Consumer” means any individual, governmental body, trust, business entity or nonprofit organization which consumes electricity that has been transmitted or distributed by means of electric transmission or distribution facilities, whether those electric transmission or distribution facilities are owned by the consumer, the recovery corporation, or any other party.
(b) “Financing entity” means the recovery corporation or any subsidiary or affiliate of the recovery corporation that is authorized by the commission to issue recovery bonds or acquire recovery property, or both.
(c) “Financing order” means an order of the commission adopted in accordance with this article, which shall include, without limitation, a procedure to require the expeditious approval by the commission of periodic adjustments to fixed recovery amounts and to any associated fixed recovery tax amounts included in that financing order to ensure recovery of all recovery costs and the costs associated with the proposed recovery, financing, or refinancing thereof, including the costs of servicing and retiring the recovery bonds contemplated by the financing order.
(d) “Fixed recovery amounts” means those nonbypassable rates and other charges, including, but not limited to, distribution, connection, disconnection, and termination rates and charges, that are authorized by the commission in a financing order to recover (1) recovery costs specified in the financing order, and (2) the costs of recovering, financing, or refinancing those recovery costs through a plan approved by the commission in the financing order, including the costs of servicing and retiring recovery bonds.
(e) “Fixed recovery tax amounts” means those nonbypassable rates and other charges, including, but not limited to, distribution, connection, disconnection, and termination rates and charges, that are needed to recover federal and State of California income and franchise taxes associated with fixed recovery amounts authorized by the commission in the financing order and that are not financed from proceeds of recovery bonds.
(f) “Recovery bonds” means bonds, notes, certificates of participation or beneficial interest, or other evidences of indebtedness or ownership, issued pursuant to an executed indenture or other agreement of a financing entity, the proceeds of which are used, directly or indirectly, to recover, finance, or refinance recovery costs, and that are directly or indirectly secured by, or payable from, recovery property.
(g) “Recovery corporation” means Pacific Gas and Electric Company, the electrical corporation described in the commission’s Decision No. 03-12-035.
(h) “Recovery costs” means (1) the unamortized balance of the regulatory asset arising and existing pursuant to the commission’s Decision No. 03-12-035, (2) federal and State of California income and franchise taxes associated with recovery of the unamortized balance of that regulatory asset, (3) costs of issuing recovery bonds, and (4) professional fees, consultant fees, redemption premiums, tender premiums and other costs incurred by the recovery corporation in using proceeds of recovery bonds to acquire outstanding securities of the recovery corporation.
(i) (1) “Recovery property” means the property right created pursuant to this article, including, without limitation, the right, title, and interest of the recovery corporation or its transferee:
(A) In and to the tariff established pursuant to a financing order, as adjusted from time to time in accordance with Section 848.1 and the financing order.
(B) To be paid the amount that is determined in a financing order to be the amount that the recovery corporation or its transferee is lawfully entitled to receive pursuant to the provisions of this article and the proceeds thereof, and in and to all revenues, collections, claims, payments, money, or proceeds of or arising from the tariff or constituting fixed recovery amounts that are the subject of a financing order including those nonbypassable rates and other charges referred to in subdivision (d).
(C) In and to all rights to obtain adjustments to the tariff relating to fixed recovery amounts pursuant to the terms of Section 848.1 and the financing order.
(2) “Recovery property” shall not include the right to be paid fixed recovery tax amounts.
(3) “Recovery property” shall constitute a current property right notwithstanding the fact that the value of the property right will depend on consumers using electricity or, in those instances where consumers are customers of the recovery corporation, the recovery corporation performing certain services.
(j) “Service territory” means the geographical area that the recovery corporation provided with electric distribution service as of December 19, 2003.

SEC. 23.SEC. 25.

 Section 2774.5 of the Public Utilities Code is amended to read:

2774.5.
 An electrical corporation or local publicly owned electric utility shall immediately notify the Commissioner of the California Highway Patrol, the Office of Emergency Services, and the sheriff and any affected chief of police of the specific area within their respective law enforcement jurisdictions that will sustain a planned loss of power as soon as the planned loss becomes known as to when and where that power loss will occur. The notification shall include common geographical boundaries, grid or block numbers of the affected area, and the next anticipated power loss area designated by the electrical corporation or public entity during rotating blackouts.

SEC. 24.SEC. 26.

 Section 2827 of the Public Utilities Code is amended to read:

2827.
 (a) The Legislature finds and declares that a program to provide net energy metering combined with net surplus compensation,  metering,  co-energy metering, and wind energy co-metering for eligible customer-generators is one way to encourage substantial private investment in renewable energy resources, stimulate in-state economic growth, reduce demand for electricity during peak consumption periods, help stabilize California’s energy supply infrastructure, enhance the continued diversification of California’s energy resource mix, and  reduce interconnection and administrative costs for electricity suppliers, and encourage conservation and efficiency. suppliers. 
(b) As used in this section, the following terms have the following meanings:
(1) “Co-energy metering” means a program that is the same in all other respects as a net energy metering program, except that the local publicly owned electric utility has elected to apply a generation-to-generation energy and time-of-use credit formula as provided in subdivision (i).
(2) “Electrical cooperative” means an electrical cooperative as defined in Section 2776.
(3) “Electric utility”  distribution utility or cooperative”  means an electrical corporation, a local publicly owned electric utility, or an electrical cooperative, or any other entity, except an electric service provider, that offers electrical service. This section shall not apply to a local publicly owned electric utility that serves more than 750,000 customers and that also conveys water to its customers.
(4) (A)  “Eligible customer-generator” means a residential customer,  residential,  small commercial customer as defined in subdivision (h) of Section 331, or  commercial, industrial, or agricultural customer of an electric utility,  electricity distribution utility or cooperative,  who uses a renewable electrical generation solar or a wind turbine electrical generating  facility, or a combination of those facilities,  hybrid system of both,  with a total  capacity of not more than one megawatt, megawatt  that is located on the customer’s owned, leased, or rented premises, and  is interconnected and operates in parallel with the electrical electric  grid, and is intended primarily to offset part or all of the customer’s own electrical requirements.
(B) (i) Notwithstanding subparagraph (A), “eligible customer-generator” includes the Department of Corrections and Rehabilitation using a renewable electrical generation technology, or a combination of renewable electrical generation technologies, with a total capacity of not more than eight megawatts, that is located on the department’s owned, leased, or rented premises, and is interconnected and operates in parallel with the electrical grid, and is intended primarily to offset part or all of the facility’s own electrical requirements. The amount of any wind generation exported to the electrical grid shall not exceed 1.35 megawatt at any time.
(ii) Notwithstanding paragraph (2) of subdivision (e), an electrical corporation shall be afforded a prudent but necessary time, as determined by the executive director of the commission, to study the impacts of a request for interconnection of a renewable generator with a capacity of greater than one megawatt under this subparagraph. If the study reveals the need for upgrades to the transmission or distribution system arising solely from the interconnection, the electrical corporation shall be afforded the time necessary to complete those upgrades before the interconnection and those costs shall be borne by the customer-generator. Upgrade projects shall comply with applicable state and federal requirements, including requirements of the Federal Energy Regulatory Commission.
(C) (i) For purposes of this subparagraph, a “United States Armed Forces base or facility” is an establishment under the jurisdiction of the United States Army, Navy, Air Force, Marine Corps, Space Force, or Coast Guard.
(ii) Notwithstanding subparagraph (A), a United States Armed Forces base or facility is an “eligible customer-generator” if the base or facility uses a renewable electrical generation facility, or a combination of those facilities, the renewable electrical generation facility is located on premises owned, leased, or rented by the United States Armed Forces base or facility, the renewable electrical generation facility is interconnected and operates in parallel with the electrical grid, the renewable electrical generation facility is intended primarily to offset part or all of the base or facility’s own electrical requirements, and the renewable electrical generation facility has a generating capacity that does not exceed the lesser of 12 megawatts or one megawatt greater than the minimum load of the base or facility over the prior 36 months. Unless prohibited by federal law, a renewable electrical generation facility shall not be eligible for net energy metering for privatized military housing pursuant to this subparagraph if the renewable electrical generation facility was procured using a sole source process. A renewable electrical generation facility procured using best value criteria, if otherwise eligible, may be used for net energy metering for privatized military housing pursuant to this subparagraph. For these purposes, “best value criteria” means a value determined by objective criteria and may include, but is not limited to, price, features, functions, and life-cycle costs.
(iii) A United States Armed Forces base or facility that is an eligible customer generator pursuant to this subparagraph shall not receive compensation for exported generation.
(iv) Notwithstanding paragraph (2) of subdivision (e), an electrical corporation shall be afforded a prudent but necessary time, as determined by the executive director of the commission but not less than 60 working days, to study the impacts of a request for interconnection of a renewable electrical generation facility with a capacity of greater than one megawatt pursuant to this subparagraph. If the study reveals the need for upgrades to the transmission or distribution system arising solely from the interconnection, the electrical corporation shall be afforded the time necessary to complete those upgrades before the interconnection and the costs of those upgrades shall be borne by the eligible customer-generator. Upgrade projects shall comply with applicable state and federal requirements, including requirements of the Federal Energy Regulatory Commission. For any renewable generation facility that interconnects directly to the transmission grid or that requires transmission upgrades, the United States Armed Forces base or facility shall comply with all Federal Energy Regulatory Commission interconnection procedures and requirements.
(v) An electrical corporation shall make a tariff, as approved by the commission, available pursuant to this subparagraph by November 1, 2015.
(vi) This subparagraph shall not apply to a tariff made available pursuant to Section 2827.1.
(5) “Large electrical corporation” means an electrical corporation with more than 100,000 service connections in California.
(6) (5)  “Net energy metering” means measuring the difference between the electricity supplied through the electrical electric  grid and the electricity generated by an eligible customer-generator and fed back to the electrical electric  grid over a 12-month period as described in subdivisions (c) and (h). subdivision (h). An eligible customer-generator who already owns an existing solar or wind turbine electrical generating facility, or a hybrid system of both, is eligible to receive net energy metering service in accordance with this section. 
(7) “Net surplus customer-generator” means an eligible customer-generator that generates more electricity during a 12-month period than is supplied by the electric utility to the eligible customer-generator during the same 12-month period.
(8) “Net surplus electricity” means all electricity generated by an eligible customer-generator measured in kilowatthours over a 12-month period that exceeds the amount of electricity consumed by that eligible customer-generator.
(9) “Net surplus electricity compensation” means a per kilowatthour rate offered by the electric utility to the net surplus customer-generator for net surplus electricity that is set by the ratemaking authority pursuant to subdivision (h).
(10) (6)  “Ratemaking authority” means, for an electrical corporation, the commission, for an electrical cooperative, its ratesetting body selected by its shareholders or members,  electrical cooperative, or electric service provider, the commission,  and for a local publicly owned electric utility, the local elected body responsible for setting the rates of the local publicly owned utility.
(11) “Renewable electrical generation facility” means a facility that generates electricity from a renewable source listed in paragraph (1) of subdivision (a) of Section 25741 of the Public Resources Code. A small hydroelectric generation facility is not an eligible renewable electrical generation facility if it will cause an adverse impact on instream beneficial uses or cause a change in the volume or timing of streamflow.
(12) (7)  “Wind energy co-metering” means any wind energy project greater than 50 kilowatts, but not exceeding one megawatt, where the difference between the electricity supplied through the electrical electric  grid and the electricity generated by an eligible customer-generator and fed back to the electrical electric  grid over a 12-month period is as described in subdivision (h). Wind energy co-metering shall be accomplished pursuant to Section 2827.8.
(c) (1) Except as provided in paragraph (4) and in Section 2827.1, every electric utility  Every electricity distribution utility or cooperative  shall develop a standard contract or tariff providing for net energy metering, and shall make this standard contract or tariff available to eligible customer-generators, upon request, on a first-come-first-served basis until the time that the total rated generating capacity used by eligible customer-generators exceeds 5 2.5  percent of the electric utility’s  electricity distribution utility or cooperative’s  aggregate customer peak demand. Net energy metering shall be accomplished using a single meter capable of registering the flow of electricity in two directions. An additional meter or meters to monitor the flow of electricity in each direction may be installed with the consent of the eligible  customer-generator, at the expense of the electric utility,  electricity distribution utility or cooperative,  and the additional metering shall be used only to provide the information necessary to accurately bill or credit the eligible  customer-generator pursuant to subdivision (h), or to collect solar or wind electric  generating system performance information for research purposes relative to a renewable electrical generation facility.  purposes.  If the existing electrical meter of an eligible customer-generator is not capable of measuring the flow of electricity in two directions, the eligible  customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is able to measure electricity flow in two directions. If an additional meter or meters are installed, the net energy metering calculation shall yield a result identical to that of a single meter. An eligible customer-generator that is receiving service other than through the standard contract or tariff may elect to receive service through the standard contract or tariff until the electric utility reaches the generation limit set forth in this paragraph. Once the generation limit is reached, only eligible customer-generators that had previously elected to receive service pursuant to the standard contract or tariff have a right to continue to receive service pursuant to the standard contract or tariff. Eligibility for net energy metering does not limit an eligible customer-generator’s eligibility for any other rebate, incentive, or credit provided by the electric utility, or pursuant to any governmental program, including rebates and incentives provided pursuant to the California Solar Initiative. 
(2) An electrical corporation shall include a provision in the net energy metering contract or tariff requiring that any customer with an existing electrical generating facility and meter who enters into a new net energy metering contract shall provide an inspection report to the electrical corporation, unless the electrical generating facility and meter have been installed or inspected within the previous three years. The inspection report shall be prepared by a California licensed contractor who is not the owner or operator of the facility and meter. A California licensed electrician shall perform the inspection of the electrical portion of the facility and meter.
(3) (2)  (A) On an annual basis, every electric utility  beginning in 2003, every electricity distribution utility or cooperative  shall make available to the ratemaking authority information on the total rated generating capacity used by eligible customer-generators that are customers of that provider in the provider’s service area and the net surplus electricity purchased by the electric utility pursuant to this section. area. 
(B) An electric service provider operating pursuant to Section 394 shall make available to the ratemaking authority the information required by this paragraph for each eligible customer-generator that is their customer for each service area of an electrical electric  corporation, local publicly owned electrical electric  utility, or electrical cooperative, in which the eligible customer-generator  customer  has net energy metering.
(C) The ratemaking authority shall develop a process for making the information required by this paragraph available to electric utilities, and  electricity distribution utilities and cooperatives, and  for using that information to determine when, pursuant to paragraphs (1) and (4), (3),  an electric utility  electricity distribution utility or cooperative  is not obligated to provide net energy metering to additional eligible  customer-generators in its service area.
(4) (3)  (A)  An electric utility that is not a large electrical corporation is not  electricity distribution utility or cooperative is not  obligated to provide net energy metering to additional eligible  customer-generators in its service area when the combined total peak demand of all electricity used by eligible  customer-generators served by all the electric utilities  electricity distribution utilities or cooperatives  in that service area furnishing net energy metering to eligible customer-generators exceeds 5 2.5  percent of the aggregate customer peak demand of those electric utilities. electricity distribution utilities or cooperatives. 
(B) The commission shall require every large electrical corporation to make the standard contract or tariff available to eligible customer-generators, continuously and without interruption, until such times as the large electrical corporation reaches its net energy metering program limit or July 1, 2017, whichever is earlier. A large electrical corporation reaches its program limit when the combined total peak demand of all electricity used by eligible customer-generators served by all the electric utilities in the large electrical corporation’s service area furnishing net energy metering to eligible customer-generators exceeds 5 percent of the aggregate customer peak demand of those electric utilities. For purposes of calculating a large electrical corporation’s program limit, “aggregate customer peak demand” means the highest sum of the noncoincident peak demands of all of the large electrical corporation’s customers that occurs in any calendar year. To determine the aggregate customer peak demand, every large electrical corporation shall use a uniform method approved by the commission. The program limit calculated pursuant to this paragraph shall not be less than the following:
(i) For San Diego Gas and Electric Company, when it has made 607 megawatts of nameplate generating capacity available to eligible customer-generators.
(ii) For Southern California Edison Company, when it has made 2,240 megawatts of nameplate generating capacity available to eligible customer-generators.
(iii) For Pacific Gas and Electric Company, when it has made 2,409 megawatts of nameplate generating capacity available to eligible customer-generators.
(C) (4)  Every large electrical corporation shall file a monthly report with the commission detailing the progress toward the net energy metering program limit established in subparagraph (B). The report shall include separate calculations on progress toward the limits based on operating solar energy systems, cumulative numbers of interconnection requests for net energy metering eligible systems, and any other criteria required by the commission. By January 1, 2010, the commission, in consultation with the Energy Commission, shall submit a report to the Governor and the Legislature on the costs and benefits of net energy metering, wind energy co-metering, and co-energy metering to participating customers and nonparticipating customers and with options to replace the economic costs and benefits of net energy metering, wind energy co-metering, and co-energy metering with a mechanism that more equitably balances the interests of participating and nonparticipating customers, and that incorporates the findings of the report on economic and environmental costs and benefits of net metering required by subdivision (n). 
(D) Beginning July 1, 2017, or upon reaching the net metering program limit of subparagraph (B), whichever is earlier, the obligation of a large electrical corporation to provide service pursuant to a standard contract or tariff shall be pursuant to Section 2827.1 and applicable state and federal requirements.
(d) Every electric utility  electricity distribution utility or cooperative  shall make all necessary forms and contracts for net energy metering and net surplus electricity compensation  service available for download from the Internet.
(e) (1) Every electric utility  electricity distribution utility or cooperative  shall ensure that requests for establishment of net energy metering and net surplus electricity compensation  are processed in a time period not exceeding that for similarly situated customers requesting new electric service, but not to exceed 30 working days from the date it receives a completed application form for net energy metering service or net surplus electricity compensation,  service,  including a signed interconnection agreement from an eligible customer-generator and the electric inspection clearance from the governmental authority having jurisdiction.
(2) Every electric utility  electricity distribution utility or cooperative  shall ensure that requests for an interconnection agreement from an eligible customer-generator are processed in a time period not to exceed 30 working days from the date it receives a completed application form from the eligible customer-generator for an interconnection agreement.
(3) If an electric utility  electricity distribution utility or cooperative  is unable to process a request within the allowable timeframe pursuant to paragraph (1) or (2), it shall notify the eligible customer-generator and the ratemaking authority of the reason for its inability to process the request and the expected completion date.
(f) (1) If a customer participates in direct transactions pursuant to paragraph (1) of subdivision (b) of Section 365, or Section 365.1,  365  with an electric service provider that does not provide distribution service for the direct transactions, the electric utility  electricity distribution utility or cooperative  that provides distribution service for the an  eligible customer-generator is not obligated to provide net energy metering or net surplus electricity compensation  to the customer.
(2) If a customer participates in direct transactions pursuant to paragraph (1) of subdivision (b) of Section 365 or 365.1  with an electric service provider, and the customer is an eligible customer-generator, the electric utility  electricity distribution utility or cooperative  that provides distribution service for the direct transactions may recover from the customer’s electric service provider the incremental costs of metering and billing service related to net energy metering and net surplus electricity compensation  in an amount set by the ratemaking authority.
(g) Except for the time-variant kilowatthour pricing portion of any tariff adopted by the commission pursuant to paragraph (4) of subdivision (a) of Section 2851, each net energy metering contract or tariff shall be identical, with respect to rate structure, all retail rate components, and any monthly charges, to the contract or tariff to which the same customer would be assigned if the customer did not use a renewable electrical generation an eligible solar or wind electrical generating  facility, except that eligible customer-generators shall not be assessed standby charges on the electrical generating capacity or the kilowatthour production of a renewable electrical generation an eligible solar or wind electrical generating  facility. The charges for all retail rate components for eligible customer-generators shall be based exclusively on the customer-generator’s net kilowatthour consumption over a 12-month period, without regard to the eligible  customer-generator’s choice as to from  whom it purchases electricity that is not self-generated. Any new or additional demand charge, standby charge, customer charge, minimum monthly charge, interconnection charge, or any other charge that would increase an eligible customer-generator’s costs beyond those of other customers who are not eligible customer-generators in the rate class to which the eligible customer-generator would otherwise be assigned if the customer did not own, lease, rent, or otherwise operate a renewable electrical generation facility is an eligible solar or wind electrical generating facility are  contrary to the intent of this section, and shall not form a part of net energy metering contracts or tariffs.
(h) For eligible residential and small commercial  customer-generators, the net energy metering calculation shall be made by measuring the difference between the electricity supplied to the eligible customer-generator and the electricity generated by the eligible customer-generator and fed back to the electrical electric  grid over a 12-month period. The following rules shall apply to the annualized net metering calculation:
(1) The eligible residential or small commercial customer-generator,  customer-generator shall,  at the end of each 12-month period following the date of final interconnection of the eligible customer-generator’s system with an electric utility,  electricity distribution utility or cooperative,  and at each anniversary date thereafter, shall  be billed for electricity used during that 12-month period. The electric utility  electricity distribution utility or cooperative  shall determine if the eligible residential or small commercial customer-generator was a net consumer or a net surplus customer-generator  producer of electricity  during that period.
(2) At the end of each 12-month period, where the electricity supplied during the period by the electric utility  electricity distribution utility or cooperative  exceeds the electricity generated by the eligible residential or small commercial customer-generator during that same period, the eligible residential or small commercial customer-generator is a net electricity consumer and the electric utility  electricity distribution utility or cooperative  shall be owed compensation for the eligible customer-generator’s net kilowatthour consumption over that 12-month period. The compensation owed for the eligible residential or small commercial customer-generator’s consumption shall be calculated as follows:
(A) For all eligible customer-generators taking service under contracts or tariffs employing “baseline” and “over baseline” rates,  rates or charges,  any net monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned to, or be eligible for, if the customer was not an eligible customer-generator. If those same customer-generators are net generators over a billing period, the net kilowatthours generated shall be valued at the same price per kilowatthour as the electric utility  electricity distribution utility or cooperative  would charge for the baseline quantity of electricity during that billing period, and if the number of kilowatthours generated exceeds the baseline quantity, the excess shall be valued at the same price per kilowatthour as the electric utility  electricity distribution utility or cooperative  would charge for electricity over the baseline quantity during that billing period.
(B) For all eligible customer-generators taking service under contracts or tariffs employing time-of-use rates,  “time-of-use” rates or charges,  any net monthly consumption of electricity shall be calculated according to the terms of the contract or tariff to which the same customer would be assigned,  assigned to,  or be eligible for, if the customer was not an eligible customer-generator. When those same customer-generators are net generators during any discrete time-of-use  time of use  period, the net kilowatthours produced shall be valued at the same price per kilowatthour as the electric utility  electricity distribution utility or cooperative  would charge for retail kilowatthour sales during that same time-of-use period. If the eligible customer-generator’s time-of-use electrical meter is unable to measure the flow of electricity in two directions, subparagraph (A) of  paragraph (1) of subdivision (c) shall apply.
(C) For all eligible residential and small commercial customer-generators and for each billing period, the net balance of moneys owed to the electric utility  electricity distribution utility or cooperative  for net consumption of electricity or credits owed to the eligible customer-generator for net generation of electricity shall be carried forward as a monetary value until the end of each 12-month period. For all eligible commercial, industrial, and agricultural customer-generators, the net balance of moneys owed shall be paid in accordance with the electric utility’s  electricity distribution utility or cooperative’s  normal billing cycle, except that if the eligible commercial, industrial, or agricultural customer-generator is a net electricity producer over a normal billing cycle, any excess kilowatthours generated during the billing cycle shall be carried over to the following billing period as a monetary value, calculated according to the procedures set forth in this section, and appear as a credit on the eligible commercial, industrial, or agricultural  customer-generator’s account, until the end of the annual period when paragraph (3) shall apply.
(3) At the end of each 12-month period, where the electricity generated by the eligible customer-generator during the 12-month period exceeds the electricity supplied by the electric utility  electricity distribution utility or cooperative  during that same period, the eligible customer-generator is a net surplus customer-generator and the electric utility, upon an affirmative election by the net surplus customer-generator, shall either (A) provide net surplus electricity compensation for any net surplus electricity generated during the prior 12-month period, or (B) allow the net surplus customer-generator to apply the net surplus electricity as a credit for kilowatthours subsequently supplied by the electric utility to the net surplus customer-generator. For an eligible customer-generator that does not affirmatively elect to receive service pursuant to net surplus electricity compensation, the electric utility  electricity producer and the electricity distribution utility or cooperative  shall retain any excess kilowatthours generated during the prior 12-month period. The eligible customer-generator not affirmatively electing to receive service pursuant to net surplus electricity compensation  shall not be owed any compensation for the net surplus electricity  those excess kilowatthours  unless the electric utility  electricity distribution utility or cooperative  enters into a purchase agreement with the eligible customer-generator for those excess kilowatthours. Every electric utility shall provide notice to eligible customer-generators that they are eligible to receive net surplus electricity compensation for net surplus electricity, that they must elect to receive net surplus electricity compensation, and that the 12-month period commences when the electric utility receives the eligible customer-generator’s election. For an electric utility that is an electrical corporation or electrical cooperative, the commission may adopt requirements for providing notice and the manner by which eligible customer-generators may elect to receive net surplus electricity compensation. 
(4) (A) An eligible customer-generator with multiple meters may elect to aggregate the electrical load of the meters located on the property where the renewable electrical generation facility is located and on all property adjacent or contiguous to the property on which the renewable electrical generation facility is located, if those properties are solely owned, leased, or rented by the eligible customer-generator. If the eligible customer-generator elects to aggregate the electric load pursuant to this paragraph, the electric utility shall use the aggregated load for the purpose of determining whether an eligible customer-generator is a net consumer or a net surplus customer-generator during a 12-month period.
(B) If an eligible customer-generator chooses to aggregate pursuant to subparagraph (A), the eligible customer-generator shall be permanently ineligible to receive net surplus electricity compensation, and the electric utility shall retain any kilowatthours in excess of the eligible customer-generator’s aggregated electrical load generated during the 12-month period.
(C) If an eligible customer-generator with multiple meters elects to aggregate the electrical load of those meters pursuant to subparagraph (A), and different rate schedules are applicable to service at any of those meters, the electricity generated by the renewable electrical generation facility shall be allocated to each of the meters in proportion to the electrical load served by those meters. For example, if the eligible customer-generator receives electric service through three meters, two meters being at an agricultural rate that each provide service to 25 percent of the customer’s total load, and a third meter, at a commercial rate, that provides service to 50 percent of the customer’s total load, then 50 percent of the electrical generation of the eligible renewable generation facility shall be allocated to the third meter that provides service at the commercial rate and 25 percent of the generation shall be allocated to each of the two meters providing service at the agricultural rate. This proportionate allocation shall be computed each billing period.
(D) This paragraph shall not become operative for an electrical corporation unless the commission determines that allowing eligible customer-generators to aggregate their load from multiple meters will not result in an increase in the expected revenue obligations of customers who are not eligible customer-generators. The commission shall make this determination by September 30, 2013. In making this determination, the commission shall determine if there are any public purpose or other noncommodity charges that the eligible customer-generators would pay pursuant to the net energy metering program as it exists prior to aggregation, that the eligible customer-generator would not pay if permitted to aggregate the electrical load of multiple meters pursuant to this paragraph.
(E) A local publicly owned electric utility or electrical cooperative shall only allow eligible customer-generators to aggregate their load if the utility’s ratemaking authority determines that allowing eligible customer-generators to aggregate their load from multiple meters will not result in an increase in the expected revenue obligations of customers that are not eligible customer-generators. The ratemaking authority of a local publicly owned electric utility or electrical cooperative shall make this determination within 180 days of the first request made by an eligible customer-generator to aggregate their load. In making the determination, the ratemaking authority shall determine if there are any public purpose or other noncommodity charges that the eligible customer-generator would pay pursuant to the net energy metering or co-energy metering program of the utility as it exists prior to aggregation, that the eligible customer-generator would not pay if permitted to aggregate the electrical load of multiple meters pursuant to this paragraph. If the ratemaking authority determines that load aggregation will not cause an incremental rate impact on the utility’s customers that are not eligible customer-generators, the local publicly owned electric utility or electrical cooperative shall permit an eligible customer-generator to elect to aggregate the electrical load of multiple meters pursuant to this paragraph. The ratemaking authority may reconsider any determination made pursuant to this subparagraph in a subsequent public proceeding.
(F) For purposes of this paragraph, parcels that are divided by a street, highway, or public thoroughfare are considered contiguous, provided they are otherwise contiguous and under the same ownership.
(G) An eligible customer-generator may only elect to aggregate the electrical load of multiple meters if the renewable electrical generation facility, or a combination of those facilities, has a total generating capacity of not more than one megawatt.
(H) Notwithstanding subdivision (g), an eligible customer-generator electing to aggregate the electrical load of multiple meters pursuant to this subdivision shall remit service charges for the cost of providing billing services to the electric utility that provides service to the meters.
(5) (A) The ratemaking authority shall establish a net surplus electricity compensation valuation to compensate the net surplus customer-generator for the value of net surplus electricity generated by the net surplus customer-generator. The commission shall establish the valuation in a ratemaking proceeding. The ratemaking authority for a local publicly owned electric utility shall establish the valuation in a public proceeding. The net surplus electricity compensation valuation shall be established so as to provide the net surplus customer-generator just and reasonable compensation for the value of net surplus electricity, while leaving other ratepayers unaffected. The ratemaking authority shall determine whether the compensation will include, where appropriate justification exists, either or both of the following components:
(i) The value of the electricity itself.
(ii) The value of the renewable attributes of the electricity.
(B) In establishing the rate pursuant to subparagraph (A), the ratemaking authority shall ensure that the rate does not result in a shifting of costs between eligible customer-generators and other bundled service customers.
(6) (A) Upon adoption of the net surplus electricity compensation rate by the ratemaking authority, any renewable energy credit, as defined in Section 399.12, for net surplus electricity purchased by the electric utility shall belong to the electric utility. Any renewable energy credit associated with electricity generated by the eligible customer-generator that is utilized by the eligible customer-generator shall remain the property of the eligible customer-generator.
(B) Upon adoption of the net surplus electricity compensation rate by the ratemaking authority, the net surplus electricity purchased by the electric utility shall count toward the electric utility’s renewables portfolio standard annual procurement targets for the purposes of paragraph (1) of subdivision (b) of Section 399.15, or for a local publicly owned electric utility, the renewables portfolio standard annual procurement targets established pursuant to Section 399.30.
(7) (4)  The electric utility  electricity distribution utility or cooperative  shall provide every eligible residential or small commercial customer-generator with net electricity consumption and net surplus electricity generation  information with each regular bill. That information shall include the current monetary balance owed the electric utility  electricity distribution utility or cooperative  for net electricity consumed, or the net surplus electricity generated, current amount of excess electricity produced,  since the last 12-month period ended. Notwithstanding this subdivision, an electric utility  electricity distribution utility or cooperative  shall permit that customer to pay monthly for net energy consumed.
(8) (5)  If an eligible residential or small commercial customer-generator terminates the customer relationship with the electric utility, the electric utility  electricity distribution utility or cooperative, the electricity distribution utility or cooperative  shall reconcile the eligible customer-generator’s consumption and production of electricity during any part of a 12-month period following the last reconciliation, according to the requirements set forth in this subdivision, except that those requirements shall apply only to the months since the most recent 12-month bill.
(9) (6)  If an electric service provider or electric utility  electricity distribution utility or cooperative  providing net energy metering to a residential or small commercial customer-generator ceases providing that electric service to that customer during any 12-month period, and the customer-generator enters into a new net energy metering contract or tariff with a new electric service provider or electric utility,  electricity distribution utility or cooperative,  the 12-month period, with respect to that new electric service provider or electric utility,  electricity distribution utility or cooperative,  shall commence on the date on which the new electric service provider or electric utility  electricity distribution utility or cooperative  first supplies electric service to the customer-generator.
(i) Notwithstanding any other provisions of this section, paragraphs (1), (2), and (3)  the following provisions  shall apply to an eligible customer-generator with a capacity of more than 10 kilowatts, but not exceeding one megawatt, that receives electric service from a local publicly owned electric utility that has elected to utilize a co-energy metering program unless the local publicly owned electric utility chooses to provide service for eligible customer-generators with a capacity of more than 10 kilowatts in accordance with subdivisions (g) and (h):
(1) The eligible customer-generator shall be required to utilize a meter, or multiple meters, capable of separately measuring electricity flow in both directions. All meters shall provide time-of-use “time-of-use”  measurements of electricity flow, and the customer shall take service on a time-of-use rate schedule. If the existing meter of the eligible customer-generator is not a time-of-use meter or is not capable of measuring total flow of electricity energy  in both directions, the eligible customer-generator shall be responsible for all expenses involved in purchasing and installing a meter that is both time-of-use and able to measure total electricity flow in both directions. This subdivision shall not restrict the ability of an eligible customer-generator to utilize any economic incentives provided by a governmental government  agency or an electric utility  electricity distribution utility or cooperative  to reduce its costs for purchasing and installing a time-of-use meter.
(2) The consumption of electricity from the local publicly owned electric utility shall result in a cost to the eligible customer-generator to be priced in accordance with the standard rate charged to the eligible customer-generator in accordance with the rate structure to which the customer would be assigned if the customer did not use a renewable electrical generation an eligible solar or wind electrical generating  facility. The generation of electricity provided to the local publicly owned electric utility shall result in a credit to the eligible customer-generator and shall be priced in accordance with the generation component, established under the applicable structure to which the customer would be assigned if the customer did not use a renewable electrical generation an eligible solar or wind electrical generating  facility.
(3) All costs and credits shall be shown on the eligible customer-generator’s bill for each billing period. In any months in which the eligible customer-generator has been a net consumer of electricity calculated on the basis of value determined pursuant to paragraph (2), the customer-generator shall owe to the local publicly owned electric utility the balance of electricity costs and credits during that billing period. In any billing period in which the eligible customer-generator has been a net producer of electricity calculated on the basis of value determined pursuant to paragraph (2), the local publicly owned electric utility shall owe to the eligible customer-generator the balance of electricity costs and credits during that billing period. Any net credit to the eligible customer-generator of electricity costs may be carried forward to subsequent billing periods, provided that a local publicly owned electric utility may choose to carry the credit over as a kilowatthour credit consistent with the provisions of any applicable contract or tariff, including any differences attributable to the time of generation of the electricity. At the end of each 12-month period, the local publicly owned electric utility may reduce any net credit due to the eligible customer-generator to zero.
(j) A renewable electrical generation facility  solar or wind turbine electrical generating system, or a hybrid system of both,  used by an eligible customer-generator shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories, including Underwriters Laboratories Incorporated  and, where applicable, rules of the commission regarding safety and reliability. A customer-generator whose renewable electrical generation facility  solar or wind turbine electrical generating system, or a hybrid system of both,  meets those standards and rules shall not be required to install additional controls, perform or pay for additional tests, or purchase additional liability insurance.
(k) If the commission determines that there are cost or revenue obligations for an electrical corporation  electric corporation, as defined in Section 218,  that may not be recovered from customer-generators acting pursuant to this section, those obligations shall remain within the customer class from which any shortfall occurred and shall may  not be shifted to any other customer class. Net energy metering and co-energy metering customers shall not be exempt from the public goods charges imposed pursuant to Article 7 (commencing with Section 381), Article 8 (commencing with Section 385), or Article 15 (commencing with Section 399) of Chapter 2.3 of Part 1. In its report to the Legislature, the commission shall examine different methods to ensure that the public goods charges remain nonbypassable. 
(l) A net energy metering, co-energy metering, or wind energy co-metering customer shall reimburse the Department of Water Resources for all charges that would otherwise be imposed on the customer by the commission to recover bond-related costs pursuant to an agreement between the commission and the Department of Water Resources pursuant to Section 80110 of the Water Code, as well as the costs of the department equal to the share of the department’s estimated net unavoidable power purchase contract costs attributable to the customer. The commission shall incorporate the determination into an existing proceeding before the commission, and shall ensure that the charges are nonbypassable. Until the commission has made a determination regarding the nonbypassable charges, net energy metering, co-energy metering, and wind energy co-metering shall continue under the same rules, procedures, terms, and conditions as were applicable on December 31, 2002.
(m) In implementing the requirements of subdivisions (k) and (l), an eligible  a  customer-generator shall not be required to replace its existing meter except as set forth in subparagraph (A) of  paragraph (1) of subdivision (c), nor shall the electric utility  electricity distribution utility or cooperative  require additional measurement of usage beyond that which is necessary for customers in the same rate class as the eligible customer-generator.
(n) It is the intent of the Legislature that the Treasurer incorporate net energy metering, including net surplus electricity compensation,  co-energy metering, and wind energy co-metering projects undertaken pursuant to this section as sustainable building methods or distributive energy technologies for purposes of evaluating low-income housing projects.

SEC. 25.SEC. 27.

 Section 2852 of the Public Utilities Code is amended to read:

2852.
 (a) As used in this section, the following terms have the following meanings:
(1) “Affordable housing cost,” “affordable rent,” and “lower income households” have the same meanings as in those set forth in Chapter 2 (commencing with Section 50050) of Part 1 of Division 31 of the Health and Safety Code.
(2) (1)  “California Solar Initiative” means the program providing ratepayer-funded  ratepayer funded  incentives for eligible solar energy systems adopted by the Public Utilities Commission in Decision 05-12-044 and Decision 06-01-024.
(3) (2)  “Low-income residential housing” means any either  of the following:
(A) A multifamily residential complex financed with low-income housing tax credits, tax-exempt mortgage revenue bonds, general obligation bonds, or local, state, or federal loans or grants, and for which either of the following applies:
(i) (A)  The  Residential housing financed with low-income housing tax credits, tax-exempt mortgage revenue bonds, general obligation bonds, or local, state, or federal loans or grants, and for which the  rents of the occupants who are lower income households  households, as defined in Section 50079.5 of the Health and Safety Code,  do not exceed those prescribed by deed restrictions or regulatory agreements pursuant to the terms of the financing or financial assistance.
(ii) The affordable units have been or will be initially sold at an affordable housing cost to a lower income household and those units are subject to a resale restriction or equity sharing agreement pursuant to the terms of the financing or financial assistance.
(B) A multifamily residential complex in which at least 20 percent of the total housing units are sold or rented to lower income households and either of the following applies:
(i) (B)  The rental  A residential complex in which at least 20 percent of the total units are sold or rented to lower income households, as defined in Section 50079.5 of the Health and Safety Code, and the  housing units targeted for lower income households are subject to a deed restriction or affordability covenant with a public entity or nonprofit housing provider organized under Section 501(c)(3) of the Internal Revenue Code that has as its stated purpose in its articles of incorporation on file with the office of the Secretary of State to provide affordable housing to lower income households that ensures that the units will be available at an affordable rent  that ensures that the units will be available at an affordable housing cost, as defined in Section 50052.5 of the Health and Safety Code, or at an affordable rent, as defined in Section 50053 of the Health and Safety Code  for a period of at least 30 years.
(ii) The housing units have been or will be initially sold at an affordable cost to a lower income household and those units are subject to a resale restriction or equity sharing agreement, for which the homeowner does not receive a greater share of equity than described in paragraph (2) of subdivision (c) of Section 65915 of the Government Code, with a public entity or nonprofit housing provider organized under Section 501(c)(3) of the Internal Revenue Code that has as its stated purpose in its articles of incorporation on file with the office of the Secretary of State to provide affordable housing to lower income households.
(C) An individual residence sold at an affordable housing cost to a lower income household that is subject to a resale restriction or equity sharing agreement, for which the homeowner does not receive a greater share of equity than described in paragraph (2) of subdivision (c) of Section 65915 of the Government Code, with a public entity or nonprofit housing provider organized under Section 501(c)(3) of the Internal Revenue Code that has as its stated purpose in its articles of incorporation on file with the office of the Secretary of State to provide affordable housing to lower income households.
(4) (3)  “Solar energy system” means a solar energy device that has the primary purpose of providing for the collection and distribution of solar energy for the generation of electricity, that produces at least one kilowatt, and produces not more than five megawatts, alternating current rated peak electricity, and that meets or exceeds the eligibility criteria established by the commission or the Energy  State Energy Resources Conservation and Development  Commission.
(b) In establishing the California Solar Initiative, no moneys shall be diverted from any existing programs for low-income ratepayers, or from cost-effective energy efficiency or demand response programs.
(c) (1) The commission shall ensure that not less than 10 percent of the funds for the California Solar Initiative, as specified in subdivision (e) of, or moneys collected pursuant to subdivision (f) of, Section 2851,  Initiative  are utilized for the installation of solar energy systems on low-income residential housing. Notwithstanding any other law, the commission may modify the monetary incentives made available pursuant to the California Solar Initiative to accommodate the limited financial resources of low-income residential housing.
(2) The commission may incorporate a revolving loan or loan guarantee program into the California Solar Initiative for low-income residential housing. All loans outstanding as of January 1, 2022, 2016,  shall continue to be repaid consistent with the terms and conditions of the program adopted and implemented by the commission pursuant to this subdivision, until repaid in full.
(3) All moneys set aside for the purpose of funding the installation of solar energy systems on low-income residential housing that are unexpended and unencumbered on January 1, 2022, 2016,  and all moneys thereafter repaid pursuant to paragraph (2), except to the extent those moneys are encumbered pursuant to this section, shall be utilized to augment existing cost-effective energy efficiency measures in low-income residential housing that benefit ratepayers.
(d) In supervising a program implementing the California Solar Initiative pursuant to this section, the commission shall ensure that the program does all of the following:
(1) Is designed to maximize the overall benefit to ratepayers.
(2) Requires participants who receive monetary incentives to enroll in the Energy Savings Assistance Program established pursuant to Section 382, if eligible.
(3) Provides job training and employment opportunities in the solar energy and energy efficiency sectors of the economy.

SEC. 26.SEC. 28.

 Section 3302 of the Public Utilities Code is amended to read:

3302.
 As used in this division, unless the context otherwise requires, the following terms have the following meanings:
(a) “Act” means the California Consumer Power and Conservation Financing Authority Act.
(b) “Authority” means the California Consumer Power and Conservation Financing Authority established pursuant to Section 3320 and any board, commission, department, or officer succeeding to the functions thereof, or to whom the powers conferred upon the authority by this division shall be given by law.
(c) “Board” means the Board of Directors of the California Consumer Power and Conservation Financing Authority.
(d) “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 division.
(e) “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  asset-backed  certificates, or lease-purchase or installment purchase agreements, whether taxable or excludable from gross income for state and federal income taxation purposes.
(f) “Cost,” as applied to a program, project, or portion thereof financed under this division, 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.
(g) “Enterprise” means a revenue-producing improvement, building, system, plant, works, facilities, or undertaking used for or useful for the generation or production of electric energy 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.
(h) “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.
(i) “Fund” means the California Consumer Power and Conservation Financing Authority Fund.
(j) “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.
(k) “Participating party” means either of the following:
(1) 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.
(2) 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 under Section 3365, and that makes application to the authority for financial assistance in a manner prescribed by the authority.
( (l) 
l
)  “Program” means a program that provides financial assistance, as provided in Article 6 (commencing with Section 3365).
(m) “Project” means plants, facilities, equipment, appliances, structures, expansions, and improvements within the state that serve the purposes of this division as approved by the authority, and all activities and expenses necessary to initiate and complete those projects described in Article 5 (commencing with Section 3350) and Article 7 (commencing with Section 3368), of Chapter 3.
(n) “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.
(o) “State” means the State of California.

SEC. 27.SEC. 29.

 Section 7000 of the Public Utilities Code is amended to read:

7000.
 (a) For purposes of this chapter, a utility shall mean all of the following:
(1) An electric corporation.
(2) A water corporation.
(3) A telephone corporation.
(4) A telecommunications carrier, as defined in Section 153 of Title 47 of the United States Code.
(5) A gas corporation.
(6) A local publicly owned electric utility and a publicly owned gas utility.
(7) A special district that owns or operates utilities.
(b) This chapter shall also apply to the following entities:
(1) A cable television corporation.
(2) A cable operator, as defined in Section 522 of Title 47 of the United States Code.

SEC. 28.SEC. 30.

 Section 8340 of the Public Utilities Code is amended to read:

8340.
 For purposes of this chapter, the following terms have the following meanings:
(a) “Baseload generation” means electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60 percent.
(b) “Combined-cycle natural gas” with respect to a powerplant means the powerplant employs a combination of one or more gas turbines and steam turbines in which electricity is produced in the steam turbine from otherwise lost waste heat exiting from one or more of the gas turbines.
(c) “Electric service provider” means an “electric service provider” as defined in Section 218.3, but does not include corporations or persons employing cogeneration technology or producing electricity from other than a conventional power source consistent with subdivision (b) of Section 218.
(d) “Greenhouse gases” means those gases listed in Section 38505 subdivision (h) of Section 42801.1  of the Health and Safety Code.
(e) “Load-serving entity” means every electrical corporation, electric service provider, or community choice aggregator serving end-use customers in the state.
(f) “Long-term financial commitment” means either a new ownership investment in baseload generation or a new or renewed contract with a term of five or more years, which includes procurement of baseload generation.
(g) “Output-based methodology” means a greenhouse gases emission performance standard that is expressed in pounds of greenhouse gases emitted per megawatthour and factoring in the useful thermal energy employed for purposes other than the generation of electricity.
(h) “Plant capacity factor” means the ratio of the electricity produced during a given time period, measured in kilowatthours, to the electricity the unit could have produced if it had been operated at its rated capacity during that period, expressed in kilowatthours.
(i) “Powerplant” means a facility for the generation of electricity, and includes one or more generating units at the same location.
(j) “Zero- or low-carbon generating resource” means an electrical generating resource that will generate electricity while producing emissions of greenhouse gases at a rate substantially below the greenhouse gases emission performance standard, as determined by the commission.

SEC. 29.SEC. 31.

 Section 9604 of the Public Utilities Code is amended to read:

9604.
 For purposes of this division, the following definitions apply:
(a) “Direct transaction” means a contract between one or more electric generators, marketers, or brokers, public or private, of electric power and one or more retail customers providing for the purchase and sale of electric power and ancillary services.
(b) “Service area” means an area in which, as of December 20, 1995, an investor-owned electric utility or a local publicly owned electric utility was obligated to provide service.
(c) “Severance fee” or “transition charge” for a local publicly owned electric utility shall mean that charge or periodic charge assessed to customers to recover the reasonable uneconomic portion of costs associated with generation-related assets and obligations, nuclear decommissioning, and capitalized energy efficiency investment programs approved prior to August 15, 1996.