Article 6. Requirements For The Public Utilities Commission of California Public Utilities Code >> Division 1. >> Part 1. >> Chapter 2.3. >> Article 6.

The commission shall ensure that existing, and if necessary, additional filings at the Federal Energy Regulatory Commission request confirmation of the relevant provisions of this chapter and seek the authority needed to give the Independent System Operator the ability to secure generating and transmission resources necessary to guarantee achievement of planning and operating reserve criteria no less stringent than those established by the Western Electricity Coordinating Council and the North American Electric Reliability Council.

The commission shall determine that portion of each existing electrical corporation's retail rate effective on January 5, 2001, that is equal to the difference between the generation related component of the retail rate and the sum of the costs of the utility' s own generation, qualifying facility contracts, existing bilateral contracts, and ancillary services. That portion of the retail rate shall be known as the California Procurement Adjustment. The commission shall further determine the amount of the California Procurement Adjustment that is allocable to the power sold by the department. That amount shall be payable, by each electrical corporation, upon receipt by the electrical corporation of the revenues from its retail end use customers, to the department for deposit in the Department of Water Resources Electric Power Fund, established by Section 80200 of the Water Code. The amount determined pursuant to this subdivision shall be known as the Fixed Department of Water Resources Set-Aside.

The commission shall ensure that any funds secured by the restructuring trusts established for the purposes of developing the Independent System Operator and the Power Exchange shall be placed at the disposal of the Independent System Operator and the Power Exchange respectively.

(a) In proceedings pursuant to Section 455.5, 851, or 854, the commission shall ensure that facilities needed to maintain the reliability of the electric supply remain available and operational, consistent with maintaining open competition and avoiding an overconcentration of market power. In order to determine whether the facility needs to remain available and operational, the commission shall utilize standards that are no less stringent than the Western Electricity Coordinating Council and North American Electric Reliability Council standards for planning reserve criteria.
  (b) The commission shall require that generation facilities located in the state that have been disposed of in proceedings pursuant to Section 851 are operated by the persons or corporations who own or control them in a manner that ensures their availability to maintain the reliability of the electric supply system.

(a) In order to ensure the continued safe and reliable operation of public utility electric generating facilities, the commission shall require in any proceeding under Section 851 involving the sale, but not spinoff, of a public utility electric generating facility, for transactions initiated prior to December 31, 2001, and approved by the commission by December 31, 2002, that the selling utility contract with the purchaser of the facility for the selling utility, an affiliate, or a successor corporation to operate and maintain the facility for at least two years. The commission may require these conditions to be met for transactions initiated on or after January 1, 2002. The commission shall require the contracts to be reasonable for both the seller and the buyer.
  (b) Subdivision (a) shall apply only if the facility is actually operated during the two-year period following the sale. Subdivision (a) shall not require the purchaser to operate a facility, nor shall it preclude a purchaser from temporarily closing the facility to make capital improvements.
  (c) For those bayside fossil fueled electric generation and associated transmission facilities that an electrical corporation has proposed to divest in a public auction and for which the Legislature has appropriated state funds in the Budget Act of 1998 to assist local governmental entities in acquiring the facilities or to mitigate environmental and community issues, and where the local governmental entity proposes that the closure of the power plant would serve the public interest by mitigating air, water and other environmental, health and safety, and community impacts associated with the facilities, and where the local governmental entity and electrical corporation have engaged in significant negotiations with the purpose of shutting down the power plant, and where there is an agreement between the electrical corporation and the local governmental entity for closure of the facilities or for the local governmental entity to acquire the facilities, the commission shall approve the closure of these facilities or the transfer of these electric generation and associated transmission facilities to the local governmental entity and shall consider the utility transactions with the community to be just and reasonable for its ratepayers. For purposes of calculating the Competition Transition Charge, the commission shall not use any inferred market value for the facilities predicated on the continued use of the plant, the construction of successor facilities or alternative use of the site and shall net the costs of the depreciated book value of the power plant and the unrecovered costs of decommissioning, environmental remediation and site restoration against the net proceeds received from the local governmental entity for the acquisition or closure of the facilities. Thereafter, any net proceeds received from the ultimate disposition, by the electrical corporation, of the site shall be credited to recovery of Competition Transition Charges.

(a) The commission shall adopt inspection, maintenance, repair, and replacement standards, and shall, in a new proceeding, or new phase of an existing proceeding, to commence on or before July 1, 2015, consider adopting rules to address the physical security risks to the distribution systems of electrical corporations. The standards or rules, which shall be prescriptive or performance based, or both, and may be based on risk management, as appropriate, for each substantial type of distribution equipment or facility, shall provide for high-quality, safe, and reliable service.
  (b) In setting its standards or rules, the commission shall consider: cost, local geography and weather, applicable codes, potential physical security risks, national electric industry practices, sound engineering judgment, and experience. The commission shall also adopt standards for operation, reliability, and safety during periods of emergency and disaster.
  (c) The commission shall conduct a review to determine whether the standards or rules prescribed in this section have been met. If the commission finds that the standards or rules have not been met, the commission may order appropriate sanctions, including penalties in the form of rate reductions or monetary fines. The review shall be performed after every major outage. Any money collected pursuant to this subdivision shall be used to offset funding for the California Alternative Rates for Energy Program.
  (d) The commission may, consistent with other provisions of law, withhold from the public information generated or obtained pursuant to this section that it deems would pose a security threat to the public if disclosed.

The actions of the commission pursuant to this chapter shall be consistent with the findings and declarations contained in Section 330. In addition, the commission shall do all of the following:
  (a) Facilitate the efforts of the state's electrical corporations to develop and obtain authorization from the Federal Energy Regulatory Commission for the creation and operation of an Independent System Operator and an independent Power Exchange, for the determination of which transmission and distribution facilities are subject to the exclusive jurisdiction of the commission, and for approval, to the extent necessary, of the cost recovery mechanism established as provided in Sections 367 to 376, inclusive. The commission shall also participate fully in all proceedings before the Federal Energy Regulatory Commission in connection with the Independent System Operator and the independent Power Exchange, and shall encourage the Federal Energy Regulatory Commission to adopt protocols and procedures that strengthen the reliability of the interconnected transmission grid, encourage all publicly owned utilities in California to become full participants, and maximize enforceability of such protocols and procedures by all market participants.
  (b) (1) Authorize direct transactions between electricity suppliers and end use customers, subject to implementation of the nonbypassable charge referred to in Sections 367 to 376, inclusive. Direct transactions shall commence simultaneously with the start of an Independent System Operator and Power Exchange referred to in subdivision (a). The simultaneous commencement shall occur as soon as practicable, but no later than January 1, 1998. The commission shall develop a phase-in schedule at the conclusion of which all customers shall have the right to engage in direct transactions. Any phase-in of customer eligibility for direct transactions ordered by the commission shall be equitable to all customer classes and accomplished as soon as practicable, consistent with operational and other technological considerations, and shall be completed for all customers by January 1, 2002.
  (2) Customers shall be eligible for direct access irrespective of any direct access phase-in implemented pursuant to this section if at least one-half of that customer's electrical load is supplied by energy from a renewable resource provider certified pursuant to Section 383, provided however that nothing in this section shall provide for direct access for electric consumers served by municipal utilities unless so authorized by the governing board of that municipal utility.

(a) Except as expressly authorized by this section, and subject to the limitations in subdivisions (b) and (c), the right of retail end-use customers pursuant to this chapter to acquire service from other providers is suspended until the Legislature, by statute, lifts the suspension or otherwise authorizes direct transactions. For purposes of this section, "other provider" means any person, corporation, or other entity that is authorized to provide electric service within the service territory of an electrical corporation pursuant to this chapter, and includes an aggregator, broker, or marketer, as defined in Section 331, and an electric service provider, as defined in Section 218.3. "Other provider" does not include a community choice aggregator, as defined in Section 331.1, and the limitations in this section do not apply to the sale of electricity by "other providers" to a community choice aggregator for resale to community choice aggregation electricity consumers pursuant to Section 366.2.
  (b) The commission shall allow individual retail nonresidential end-use customers to acquire electric service from other providers in each electrical corporation's distribution service territory, up to a maximum allowable total kilowatthours annual limit. The maximum allowable annual limit shall be established by the commission for each electrical corporation at the maximum total kilowatthours supplied by all other providers to distribution customers of that electrical corporation during any sequential 12-month period between April 1, 1998, and the effective date of this section. Within six months of the effective date of this section, or by July 1, 2010, whichever is sooner, the commission shall adopt and implement a reopening schedule that commences immediately and will phase in the allowable amount of increased kilowatthours over a period of not less than three years, and not more than five years, raising the allowable limit of kilowatthours supplied by other providers in each electrical corporation's distribution service territory from the number of kilowatthours provided by other providers as of the effective date of this section, to the maximum allowable annual limit for that electrical corporation's distribution service territory. The commission shall review and, if appropriate, modify its currently effective rules governing direct transactions, but that review shall not delay the start of the phase-in schedule.
  (c) Once the commission has authorized additional direct transactions pursuant to subdivision (b), it shall do both of the following:
  (1) Ensure that other providers are subject to the same requirements that are applicable to the state's three largest electrical corporations under any programs or rules adopted by the commission to implement the resource adequacy provisions of Section 380, the renewables portfolio standard provisions of Article 16 (commencing with Section 399.11), and the requirements for the electricity sector adopted by the State Air Resources Board pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code). This requirement applies notwithstanding any prior decision of the commission to the contrary.
  (2) (A) Ensure that, in the event that the commission authorizes, in the situation of a contract with a third party, or orders, in the situation of utility-owned generation, an electrical corporation to obtain generation resources that the commission determines are needed to meet system or local area reliability needs for the benefit of all customers in the electrical corporation's distribution service territory, the net capacity costs of those generation resources are allocated on a fully nonbypassable basis consistent with departing load provisions as determined by the commission, to all of the following:
  (i) Bundled service customers of the electrical corporation.
  (ii) Customers that purchase electricity through a direct transaction with other providers.
  (iii) Customers of community choice aggregators.
  (B) If the commission authorizes or orders an electrical corporation to obtain generation resources pursuant to subparagraph (A), the commission shall ensure that those resources meet a system or local reliability need in a manner that benefits all customers of the electrical corporation. The commission shall allocate the costs of those generation resources to ratepayers in a manner that is fair and equitable to all customers, whether they receive electric service from the electrical corporation, a community choice aggregator, or an electric service provider.
  (C) The resource adequacy benefits of generation resources acquired by an electrical corporation pursuant to subparagraph (A) shall be allocated to all customers who pay their net capacity costs. Net capacity costs shall be determined by subtracting the energy and ancillary services value of the resource from the total costs paid by the electrical corporation pursuant to a contract with a third party or the annual revenue requirement for the resource if the electrical corporation directly owns the resource. An energy auction shall not be required as a condition for applying this allocation, but may be allowed as a means to establish the energy and ancillary services value of the resource for purposes of determining the net costs of capacity to be recovered from customers pursuant to this paragraph, and the allocation of the net capacity costs of contracts with third parties shall be allowed for the terms of those contracts.
  (D) It is the intent of the Legislature, in enacting this paragraph, to provide additional guidance to the commission with respect to the implementation of subdivision (g) of Section 380, as well as to ensure that the customers to whom the net costs and benefits of capacity are allocated are not required to pay for the cost of electricity they do not consume.
  (d) (1) If the commission approves a centralized resource adequacy mechanism pursuant to subdivisions (h) and (i) of Section 380, upon the implementation of the centralized resource adequacy mechanism the requirements of paragraph (2) of subdivision (c) shall be suspended. If the commission later orders that electrical corporations cease procuring capacity through a centralized resource adequacy mechanism, the requirements of paragraph (2) of subdivision (c) shall again apply.
  (2) If the use of a centralized resource adequacy mechanism is authorized by the commission and has been implemented as set forth in paragraph (1), the net capacity costs of generation resources that the commission determines are required to meet urgent system or urgent local grid reliability needs, and that the commission authorizes to be procured outside of the Section 380 or Section 454.5 processes, shall be recovered according to the provisions of paragraph (2) of subdivision (c).
  (3) Nothing in this subdivision supplants the resource adequacy requirements of Section 380 or the resource procurement procedures established in Section 454.5.
  (e) The commission may report to the Legislature on the efficacy of authorizing individual retail end-use residential customers to enter into direct transactions, including appropriate consumer protections.

The commission shall ensure that bundled retail customers of an electrical corporation do not experience any cost increases as a result of retail customers of an electrical corporation electing to receive service from other providers. The commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load.

Nothing in this chapter shall prevent the commission from exercising its authority to investigate a process for certification and regulation of the rates, charges, terms, and conditions of default service. If the commission determines that a process for certification and regulation of default service is in the public interest, the commission shall submit its findings and recommendations to the Legislature for approval.

(a) The commission shall take actions as needed to facilitate direct transactions between electricity suppliers and end-use customers. Customers shall be entitled to aggregate their electrical loads on a voluntary basis, provided that each customer does so by a positive written declaration. If no positive declaration is made by a customer, that customer shall continue to be served by the existing electrical corporation or its successor in interest, except aggregation by community choice aggregators, accomplished pursuant to Section 366.2.
  (b) Aggregation of customer electrical load shall be authorized by the commission for all customer classes, including, but not limited, to small commercial or residential customers. Aggregation may be accomplished by private market aggregators, special districts, or on any other basis made available by market opportunities and agreeable by positive written declaration by individual consumers, except aggregation by community choice aggregators, which shall be accomplished pursuant to Section 366.2.

(a) As used in this section, the following terms have the following meanings:
  (1) "Department" means the Department of Water Resources with respect to its power program described in Chapter 2 (commencing with Section 80100) of Division 27 of the Water Code.
  (2) "Existing project participant" means a city with rights and obligations to the Magnolia Power Project under the Magnolia Power Project Planning Agreement, dated May 1, 2001.
  (3) "Magnolia Power Project" means a proposed natural gas-fired electric generating facility to be located at an existing site in Burbank and for which an application for certification has been filed with the State Energy Resources Conservation and Development Act (Docket No. 00-SIT-1) and deemed data adequate pursuant to the expedited six-month licensing process established under Section 25550 of the Public Resources Code.
  (b) Notwithstanding Section 80110 of the Water Code or Commission Decision 01-09-060, if the Magnolia Power Project has been constructed and is otherwise capable of beginning deliveries of electricity to the existing project participants, an existing project participant may serve as a community aggregator on behalf of all retail end-use customers within its jurisdiction.
  (c) Subdivision (b) shall not become operative until both of the following occur:
  (1) The commission implements a cost-recovery mechanism, consistent with subdivision (d), that is applicable to customers that elected to purchase electricity from an alternate provider between February 1, 2001, and the effective date of the act adding this section.
  (2) The commission submits a report certifying its satisfaction of paragraph (1) to the Senate Energy, Utilities and Communications Committee, or its successor, and the Assembly Committee on Utilities and Commerce, or its successor.
  (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's power purchase costs, as well as power purchase contract obligations incurred as of January 1, 2003, that are recoverable from electrical corporation customers in commission-approved rates. It is the further intent of the Legislature to prevent any shifting of recoverable costs between customers.
  (2) The Legislature finds and declares that the provisions in this subdivision are consistent with the requirements of Section 360.5 and Division 27 (commencing with Section 80000) of the Water Code, and are therefore declaratory of existing law.
  (e) A retail end-use customer purchasing power from a community aggregator pursuant to subdivision (b) shall reimburse the department for all of the following:
  (1) A charge equivalent to the charge which 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, that charge shall be payable until all obligations of the Department of Water Resources pursuant to Division 27 of the Water Code are fully paid or otherwise discharged.
  (2) The costs of the department, equal to the share of the department's estimated net unavoidable power purchase contract costs attributable to the customer, as determined by the commission, for the period commencing with the customer's purchases of electricity from a community aggregator, through the expiration of all then existing power purchase contracts entered into by the department.
  (f) A retail end-use customer purchasing power from a community aggregator pursuant to subdivision (b) shall reimburse the electrical corporation that previously served the customer for all of the following:
  (1) The electrical corporation's unrecovered past undercollections, including all financing costs attributable to that customer, that the commission lawfully determines may be recovered in rates.
  (2) The costs of the electrical corporation recoverable in commission-approved rates, equal to the share of the electrical corporation's estimated net unavoidable power 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 aggregator, through the expiration of all then existing power purchase contracts entered into by the electrical corporation.
  (g) (1) A charge or cost imposed pursuant to subdivision (e), and all revenues received to pay the charge or cost, shall be the property of the Department of Water Resources. A charge or cost imposed pursuant to subdivision (f), and all revenues received to pay the charge or cost, shall be the property of the particular electrical corporation. The commission shall establish mechanisms, including agreements with, or orders with respect to, electrical corporations necessary to assure that the revenues received to pay a charge or cost payable pursuant to this section are promptly remitted to the party entitled to those revenues.
  (2) A charge or cost imposed pursuant to this section shall be nonbypassable.

(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, if each customer is given an opportunity to opt out of his or her 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.
  (2) Under community choice aggregation, customer participation may not require a positive written declaration, but each customer shall be informed of his or her 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 his or her 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 his or her 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 his or her 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.
  (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.
  (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 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 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) (A) An entity authorized to be a community choice aggregator, as defined in Section 331.1, that elects to implement a community choice aggregation program within its jurisdiction pursuant to this 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, 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 their 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) Following adoption of aggregation through the ordinance described in paragraph (12), 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. Any reentry fees to be imposed after the opt-out period specified in this 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) 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) (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 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) 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) 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) 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 normally scheduled monthly metering and billing process.
  (20) 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) At the request and expense of any community choice aggregator, electrical corporations shall install, 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, or operational flexibility of the electrical corporation's facilities. All costs incurred to modify circuits pursuant to this 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, 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) (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) The commission shall authorize community choice aggregation only if the commission imposes a cost-recovery mechanism pursuant to subdivisions (d), (e), (f), and (h). 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.
  (j) (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.
  (k) (1) 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.
  (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) 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 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).

Bundled retail customers of an electrical corporation shall not experience any cost increase as a result of the implementation of a community choice aggregator program. The commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load.

(a) No change in the aggregator or supplier of electric power for any small commercial customer may be made until one of the following means of confirming the change has been completed:
  (1) Independent third-party telephone verification.
  (2) Receipt of a written confirmation received in the mail from the consumer after the consumer has received an information package confirming the agreement.
  (3) The customer signs a document fully explaining the nature and effect of the change in service.
  (4) The customer's consent is obtained through electronic means, including, but not limited to, computer transactions.
  (b) No change in the aggregator or provider of electric power for any residential customer may be made over the telephone until the change has been confirmed by an independent third-party verification company, as follows:
  (1) The third-party verification company shall meet each of the following criteria:
  (A) Be independent from the entity that seeks to provide the new service.
  (B) Not be directly or indirectly managed, controlled, or directed, or owned wholly or in part, by an entity that seeks to provide the new service or by any corporation, firm, or person who directly or indirectly manages, controls, or directs, or owns more than 5 percent of the entity.
  (C) Operate from facilities physically separate from those of the entity that seeks to provide the new service.
  (D) Not derive commission or compensation based upon the number of sales confirmed.
  (2) The entity seeking to verify the sale shall do so by connecting the resident by telephone to the third-party verification company or by arranging for the third-party verification company to call the customer to confirm the sale.
  (3) The third-party verification company shall obtain the customer' s oral confirmation regarding the change, and shall record that confirmation by obtaining appropriate verification data. The record shall be available to the customer upon request. Information obtained from the customer through confirmation shall not be used for marketing purposes. Any unauthorized release of this information is grounds for a civil suit by the aggrieved resident against the entity or its employees who are responsible for the violation.
  (4) Notwithstanding paragraphs (1), (2), and (3), an aggregator or provider of electric power shall not be required to comply with these provisions when the customer directly calls an aggregator or provider of electric power to change service providers. However, an aggregator or provider of electric power shall not avoid the verification requirements by asking a customer to contact an aggregator or provider of electric power directly to make any change in the service provider.
  (c) No change in the aggregator or provider of electric power for any residential customer may be made via an Internet transaction, in which the customer accesses the website of the aggregator or provider, unless both of the following occur with respect to confirming the change:
  (1) In addition to any other information gathered in the course of the transaction, the customer shall be asked to read and respond to a separate screen that states, in easily legible text, the following: "I acknowledge that in entering this transaction I am voluntarily choosing to change the entity that supplies me with my electric power."
  (2) The separate screen shall offer the customer the option to complete or terminate the transaction.
  (d) (1) No change in the aggregator or provider of electric power for any residential customer may be made via a written transaction unless the change has been confirmed, as provided in this subdivision. In order to comply with this subdivision, in addition to any other information gathered in the course of the transaction, and in addition to any other signature required, the customer shall be asked to sign and date a document separate from that written transaction, containing the following words printed in 10-point type or larger: "I acknowledge that in signing this contract or agreement, I am voluntarily choosing to change the entity that supplies me with electric power."
  (2) The acknowledgment document described in paragraph (1) may not be included with a check or in connection with a sweepstakes solicitation.
  (e) Any aggregator or provider of electric power offering electricity service to residential and small commercial customers that switches the electric service of a customer without the customer' s consent shall be liable to the aggregator or provider of electric power offering electricity services previously selected by the customer in an amount equal to all charges paid by the customer after the violation and shall refund to the customer any amount in excess of the amount that the customer would have been obligated to pay had the customer not been switched.
  (f) An aggregator or provider of electric power shall keep a record of the confirmation of a change pursuant to subdivision (b), (c), or (d) for two years from the date of that confirmation, and shall make those records available, upon request, to the customer and to the commission in the course of a commission investigation of a customer complaint or an investigation pursuant to subdivision (c) of Section 394.2.
  (g) Public agencies are exempt from this section to the extent they are serving customers within their jurisdiction.
  (h) Notwithstanding subdivisions (c) and (d), the commission may require third-party verification for all residential changes to electric service providers if it finds that the application of subdivisions (c) and (d) results in the unauthorized changing of a customer's electric service provider.
  (i) An electrical corporation is exempt from this section for customers that default to the service of the electrical corporation.
  (j) Electric power sold to customers pursuant to Section 80100 of the Water Code is not subject to this section.

The commission shall identify and determine those costs and categories of costs for generation-related assets and obligations, consisting of generation facilities, generation-related regulatory assets, nuclear settlements, and power purchase contracts, including, but not limited to, restructurings, renegotiations or terminations thereof approved by the commission, that were being collected in commission-approved rates on December 20, 1995, and that may become uneconomic as a result of a competitive generation market, in that these costs may not be recoverable in market prices in a competitive market, and appropriate costs incurred after December 20, 1995, for capital additions to generating facilities existing as of December 20, 1995, that the commission determines are reasonable and should be recovered, provided that these additions are necessary to maintain the facilities through December 31, 2001. These uneconomic costs shall include transition costs as defined in subdivision (f) of Section 840, and shall be recovered from all customers or in the case of fixed transition amounts, from the customers specified in subdivision (a) of Section 841, on a nonbypassable basis and shall:
  (a) Be amortized over a reasonable time period, including collection on an accelerated basis, consistent with not increasing rates for any rate schedule, contract, or tariff option above the levels in effect on June 10, 1996; provided that, the recovery shall not extend beyond December 31, 2001, except as follows:
  (1) Costs associated with employee-related transition costs as set forth in subdivision (b) of Section 375 shall continue until fully collected; provided, however, that the cost collection shall not extend beyond December 31, 2006.
  (2) Power purchase contract obligations shall continue for the duration of the contract. Costs associated with any buy-out, buy-down, or renegotiation of the contracts shall continue to be collected for the duration of any agreement governing the buy-out, buy-down, or renegotiated contract; provided, however, no power purchase contract shall be extended as a result of the buy-out, buy-down, or renegotiation.
  (3) Costs associated with contracts approved by the commission to settle issues associated with the Biennial Resource Plan Update may be collected through March 31, 2002; provided that only 80 percent of the balance of the costs remaining after December 31, 2001, shall be eligible for recovery.
  (4) Nuclear incremental cost incentive plans for the San Onofre nuclear generating station shall continue for the full term as authorized by the commission in Decision 96-01-011 and Decision 96-04-059; provided that the recovery shall not extend beyond December 31, 2003.
  (5) Costs associated with the exemptions provided in subdivision (a) of Section 374 may be collected through March 31, 2002, provided that only fifty million dollars ($50,000,000) of the balance of the costs remaining after December 31, 2001, shall be eligible for recovery.
  (6) Fixed transition amounts, as defined in subdivision (d) of Section 840, may be recovered from the customers specified in subdivision (a) of Section 841 until all rate reduction bonds associated with the fixed transition amounts have been paid in full by the financing entity.
  (b) Be based on a calculation mechanism that nets the negative value of all above market utility-owned generation-related assets against the positive value of all below market utility-owned generation related assets. For those assets subject to valuation, the valuations used for the calculation of the uneconomic portion of the net book value shall be determined not later than December 31, 2001, and shall be based on appraisal, sale, or other divestiture. The commission's determination of the costs eligible for recovery and of the valuation of those assets at the time the assets are exposed to market risk or retired, in a proceeding under Section 455.5, 851, or otherwise, shall be final, and notwithstanding Section 1708 or any other provision of law, may not be rescinded, altered or amended.
  (c) Be limited in the case of utility-owned fossil generation to the uneconomic portion of the net book value of the fossil capital investment existing as of January 1, 1998, and appropriate costs incurred after December 20, 1995, for capital additions to generating facilities existing as of December 20, 1995, that the commission determines are reasonable and should be recovered, provided that the additions are necessary to maintain the facilities through December 31, 2001. All "going forward costs" of fossil plant operation, including operation and maintenance, administrative and general, fuel and fuel transportation costs, shall be recovered solely from independent Power Exchange revenues or from contracts with the Independent System Operator, provided that for the purposes of this chapter, the following costs may be recoverable pursuant to this section:
  (1) Commission-approved operating costs for particular utility-owned fossil powerplants or units, at particular times when reactive power/voltage support is not yet procurable at market-based rates in locations where it is deemed needed for the reactive power/voltage support by the Independent System Operator, provided that the units are otherwise authorized to recover market-based rates and provided further that for an electrical corporation that is also a gas corporation and that serves at least four million customers as of December 20, 1995, the commission shall allow the electrical corporation to retain any earnings from operations of the reactive power/voltage support plants or units and shall not require the utility to apply any portions to offset recovery of transition costs. Cost recovery under the cost recovery mechanism shall end on December 31, 2001.
  (2) An electrical corporation that, as of December 20, 1995, served at least four million customers, and that was also a gas corporation that served less than four thousand customers, may recover, pursuant to this section, 100 percent of the uneconomic portion of the fixed costs paid under fuel and fuel transportation contracts that were executed prior to December 20, 1995, and were subsequently determined to be reasonable by the commission, or 100 percent of the buy-down or buy-out costs associated with the contracts to the extent the costs are determined to be reasonable by the commission.
  (d) Be adjusted throughout the period through March 31, 2002, to track accrual and recovery of costs provided for in this subdivision. Recovery of costs prior to December 31, 2001, shall include a return as provided for in Decision 95-12-063, as modified by Decision 96-01-009, together with associated taxes.
  (e) (1) Be allocated among the various classes of customers, rate schedules, and tariff options to ensure that costs are recovered from these classes, rate schedules, contract rates, and tariff options, including self-generation deferral, interruptible, and standby rate options in substantially the same proportion as similar costs are recovered as of June 10, 1996, through the regulated retail rates of the relevant electric utility, provided that there shall be a firewall segregating the recovery of the costs of competition transition charge exemptions such that the costs of competition transition charge exemptions granted to members of the combined class of residential and small commercial customers shall be recovered only from these customers, and the costs of competition transition charge exemptions granted to members of the combined class of customers, other than residential and small commercial customers, shall be recovered only from these customers.
  (2) Individual customers shall not experience rate increases as a result of the allocation of transition costs. However, customers who elect to purchase energy from suppliers other than the Power Exchange through a direct transaction, may incur increases in the total price they pay for electricity to the extent the price for the energy exceeds the Power Exchange price.
  (3) The commission shall retain existing cost allocation authority, provided the firewall and rate freeze principles are not violated.

(a) It is the intent of the Legislature in enacting this section to ensure that individual customers do not experience rate increases as a result of the allocation of transition costs, in accordance with paragraph (2) of subdivision (e) of Section 367.
  (b) The commission shall implement a methodology whereby the Power Exchange energy credit for a customer with a meter installed on or after June 30, 2000, that is capable of recording hourly data is calculated based on the actual hourly data for that customer. The Power Exchange energy credit for a customer with a meter installed before June 30, 2000, that is capable of recording hourly data shall, at the election of the customer, on a one-time basis before June 30, 2000, be calculated based on either (1) the actual hourly data for that customer or (2) the average load profile for that customer class. If the customer fails to make an election, that customer's Power Exchange energy credit shall continue to be based on the average load profile for that customer class.
  (c) Additional incremental billing costs incurred as a result of the methodology implemented by the commission pursuant to subdivision (b) may be recoverable through rates for that customer class, if the commission finds that the costs are reasonable.
  (d) The methodology implemented by the commission pursuant to subdivisions (b) and (c) shall not result in any shifts in cost between customer classes and shall be consistent with the firewall provision set forth in subdivision (e) of Section 367.

Each electrical corporation shall propose a cost recovery plan to the commission for the recovery of the uneconomic costs of an electrical corporation's generation-related assets and obligations identified in Section 367. The commission shall authorize the electrical corporation to recover the costs pursuant to the plan if the plan meets the following criteria:
  (a) The cost recovery plan shall set rates for each customer class, rate schedule, contract, or tariff option, at levels equal to the level as shown on electric rate schedules as of June 10, 1996, provided that rates for residential and small commercial customers shall be reduced so that these customers shall receive rate reductions of no less than 10 percent for 1998 continuing through 2002. These rate levels for each customer class, rate schedule, contract, or tariff option shall remain in effect until the earlier of March 31, 2002, or the date on which the commission-authorized costs for utility generation-related assets and obligations have been fully recovered. The electrical corporation shall be at risk for those costs not recovered during that time period. Each utility shall amortize its total uneconomic costs, to the extent possible, such that for each year during the transition period its recorded rate of return on the remaining uneconomic assets does not exceed its authorized rate of return for those assets. For purposes of determining the extent to which the costs have been recovered, any over-collections recorded in Energy Costs Adjustment Clause and Electric Revenue Adjustment Mechanism balancing accounts, as of December 31, 1996, shall be credited to the recovery of the costs.
  (b) The cost recovery plan shall provide for identification and separation of individual rate components such as charges for energy, transmission, distribution, public benefit programs, and recovery of uneconomic costs. The separation of rate components required by this subdivision shall be used to ensure that customers of the electrical corporation who become eligible to purchase electricity from suppliers other than the electrical corporation pay the same unbundled component charges, other than energy, that a bundled service customer pays. No cost shifting among customer classes, rate schedules, contract, or tariff options shall result from the separation required by this subdivision. Nothing in this provision is intended to affect the rates, terms, and conditions or to limit the use of any Federal Energy Regulatory Commission-approved contract entered into by the electrical corporation prior to the effective date of this provision.
  (c) In consideration of the risk that the uneconomic costs identified in Section 367 may not be recoverable within the period identified in subdivision (a) of Section 367, an electrical corporation that, as of December 20, 1995, served more than four million customers, and was also a gas corporation that served less than four thousand customers, shall have the flexibility to employ risk management tools, such as forward hedges, to manage the market price volatility associated with unexpected fluctuations in natural gas prices, and the out-of-pocket costs of acquiring the risk management tools shall be considered reasonable and collectible within the transition freeze period. This subdivision applies only to the transaction costs associated with the risk management tools and shall not include any losses from changes in market prices.
  (d) In order to ensure implementation of the cost recovery plan, the limitation on the maximum amount of cost recovery for nuclear facilities that may be collected in any year adopted by the commission in Decision 96-01-011 and Decision 96-04-059 shall be eliminated to allow the maximum opportunity to collect the nuclear costs within the transition cap period.
  (e) As to an electrical corporation that is also a gas corporation serving more than four million California customers, so long as any cost recovery plan adopted in accordance with this section satisfies subdivision (a), it shall also provide for annual increases in base revenues, effective January 1, 1997, and January 1, 1998, equal to the inflation rate for the prior year plus two percentage points, as measured by the consumer price index. The increase shall do both of the following:
  (1) Remain in effect pending the next general rate case review, which shall be filed not later than December 31, 1997, for rates that would become effective in January 1999. For purposes of any commission-approved performance-based ratemaking mechanism or general rate case review, the increases in base revenue authorized by this subdivision shall create no presumption that the level of base revenue reflecting those increases constitute the appropriate starting point for subsequent revenues.
  (2) Be used by the utility for the purposes of enhancing its transmission and distribution system safety and reliability, including, but not limited to, vegetation management and emergency response. To the extent the revenues are not expended for system safety and reliability, they shall be credited against subsequent safety and reliability base revenue requirements. Any excess revenues carried over shall not be used to pay any monetary sanctions imposed by the commission.
  (f) The cost recovery plan shall provide the electrical corporation with the flexibility to manage the renegotiation, buy-out, or buy-down of the electrical corporation's power purchase obligations, consistent with review by the commission to assure that the terms provide net benefits to ratepayers and are otherwise reasonable in protecting the interests of both ratepayers and shareholders.
  (g) An example of a plan authorized by this section is the document entitled "Restructuring Rate Settlement" transmitted to the commission by Pacific Gas and Electric Company on June 12, 1996.

(a) Notwithstanding any other provision of law, upon the termination of the 10-percent rate reduction for residential and small commercial customers set forth in subdivision (a) of Section 368, the commission may not subject those residential and small commercial customers to any rate increases or future rate obligations solely as a result of the termination of the 10-percent rate reduction.
  (b) The provisions of subdivision (a) do not affect the authority of the commission to raise rates for reasons other than the termination of the 10-percent rate reduction set forth in subdivision (a) of Section 368.
  (c) Nothing in this section shall further extend the authority to impose fixed transition amounts, as defined in subdivision (d) of Section 840, or further authorize or extend rate reduction bonds, as defined in subdivision (e) of Section 840.

The commission shall establish an effective mechanism that ensures recovery of transition costs referred to in Sections 367, 368, 375, and 376, and subject to the conditions in Sections 371 to 374, inclusive, from all existing and future consumers in the service territory in which the utility provided electricity services as of December 20, 1995; provided, that the costs shall not be recoverable for new customer load or incremental load of an existing customer where the load is being met through a direct transaction and the transaction does not otherwise require the use of transmission or distribution facilities owned by the utility. However, the obligation to pay the competition transition charges cannot be avoided by the formation of a local publicly owned electrical corporation on or after December 20, 1995, or by annexation of any portion of an electrical corporation's service area by an existing local publicly owned electric utility. This section shall not apply to service taken under tariffs, contracts, or rate schedules that are on file, accepted, or approved by the Federal Energy Regulatory Commission, unless otherwise authorized by the Federal Energy Regulatory Commission.

The commission shall require, as a prerequisite for any consumer in California to engage in direct transactions permitted in Section 365, that beginning with the commencement of these direct transactions, the consumer shall have an obligation to pay the costs provided in Sections 367, 368, 375, and 376, and subject to the conditions in Sections 371 to 374, inclusive, directly to the electrical corporation providing electricity service in the area in which the consumer is located. This obligation shall be set forth in the applicable rate schedule, contract, or tariff option under which the customer is receiving service from the electrical corporation. To the extent the consumer does not use the electrical corporation's facilities for direct transaction, the obligation to pay shall be confirmed in writing, and the customer shall be advised by any electricity marketer engaged in the transaction of the requirement that the customer execute a confirmation. The requirement for marketers to inform customers of the written requirement shall cease on January 1, 2002.

(a) Except as provided in Sections 372 and 374, the uneconomic costs provided in Sections 367, 368, 375, and 376 shall be applied to each customer based on the amount of electricity purchased by the customer from an electrical corporation or alternate supplier of electricity, subject to changes in usage occurring in the normal course of business.
  (b) Changes in usage occurring in the normal course of business are those resulting from changes in business cycles, termination of operations, departure from the utility service territory, weather, reduced production, modifications to production equipment or operations, changes in production or manufacturing processes, fuel switching, including installation of fuel cells pending a contrary determination by the California Energy Resources Conservation and Development Commission in Section 383, enhancement or increased efficiency of equipment or performance of existing self-cogeneration equipment, replacement of existing cogeneration equipment with new power generation equipment of similar size as described in paragraph (1) of subdivision (a) of Section 372, installation of demand-side management equipment or facilities, energy conservation efforts, or other similar factors.
  (c) Nothing in this section shall be interpreted to exempt or alter the obligation of a customer to comply with Chapter 5 (commencing with Section 119075) of Part 15 of Division 104 of the Health and Safety Code. Nothing in this section shall be construed as a limitation on the ability of residential customers to alter their pattern of electricity purchases by activities on the customer side of the meter.

(a) It is the policy of the state to encourage and support the development of cogeneration as an efficient, environmentally beneficial, competitive energy resource that will enhance the reliability of local generation supply, and promote local business growth. Subject to the specific conditions provided in this section, the commission shall determine the applicability to customers of uneconomic costs as specified in Sections 367, 368, 375, and 376. Consistent with this state policy, the commission shall provide that these costs shall not apply to any of the following:
  (1) To load served onsite or under an over the fence arrangement by a nonmobile self-cogeneration or cogeneration facility that was operational on or before December 20, 1995, or by increases in the capacity of a facility to the extent that the increased capacity was constructed by an entity holding an ownership interest in or operating the facility and does not exceed 120 percent of the installed capacity as of December 20, 1995, provided that prior to June 30, 2000, the costs shall apply to over the fence arrangements entered into after December 20, 1995, between unaffiliated parties. For the purposes of this subdivision, "affiliated" means any person or entity that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with another specified entity. "Control" means either of the following:
  (A) The possession, directly or indirectly, of the power to direct or to cause the direction of the management or policies of a person or entity, whether through an ownership, beneficial, contractual, or equitable interest.
  (B) Direct or indirect ownership of at least 25 percent of an entity, whether through an ownership, beneficial, or equitable interest.
  (2) To load served by onsite or under an over the fence arrangement by a nonmobile self-cogeneration or cogeneration facility for which the customer was committed to construction as of December 20, 1995, provided that the facility was substantially operational on or before January 1, 1998, or by increases in the capacity of a facility to the extent that the increased capacity was constructed by an entity holding an ownership interest in or operating the facility and does not exceed 120 percent of the installed capacity as of January 1, 1998, provided that prior to June 30, 2000, the costs shall apply to over the fence arrangements entered into after December 20, 1995, between unaffiliated parties.
  (3) To load served by existing, new, or portable emergency generation equipment used to serve the customer's load requirements during periods when utility service is unavailable, provided the emergency generation is not operated in parallel with the integrated electric grid, except on a momentary parallel basis.
  (4) After June 30, 2000, to any load served onsite or under an over the fence arrangement by any nonmobile self-cogeneration or cogeneration facility.
  (b) Further, consistent with state policy, with respect to self-cogeneration or cogeneration deferral agreements, the commission shall do the following:
  (1) Provide that a utility shall execute a final self-cogeneration or cogeneration deferral agreement with any customer that, on or before December 20, 1995, had executed a letter of intent (or similar documentation) to enter into the agreement with the utility, provided that the final agreement shall be consistent with the terms and conditions set forth in the letter of intent and the commission shall review and approve the final agreement.
  (2) Provide that a customer that holds a self-cogeneration or cogeneration deferral agreement that was in place on or before December 20, 1995, or that was executed pursuant to paragraph (1) in the event the agreement expires, or is terminated, may do any of the following:
  (A) Continue through December 31, 2001, to receive utility service at the rate and under terms and conditions applicable to the customer under the deferral agreement that, as executed, includes an allocation of uneconomic costs consistent with subdivision (e) of Section 367.
  (B) Engage in a direct transaction for the purchase of electricity and pay uneconomic costs consistent with Sections 367, 368, 375, and 376.
  (C) Construct a self-cogeneration or cogeneration facility of approximately the same capacity as the facility previously deferred, provided that the costs provided in Sections 367, 368, 375, and 376 shall apply consistent with subdivision (e) of Section 367, unless otherwise authorized by the commission pursuant to subdivision (c).
  (3) Subject to the firewall described in subdivision (e) of Section 367, provide that the ratemaking treatment for self-cogeneration or cogeneration deferral agreements executed prior to December 20, 1995, or executed pursuant to paragraph (1) shall be consistent with the ratemaking treatment for the contracts approved before January 1995.
  (c) The commission shall authorize, within 60 days of the receipt of a joint application from the serving utility and one or more interested parties, applicability conditions as follows:
  (1) The costs identified in Sections 367, 368, 375, and 376 shall not, prior to June 30, 2000, apply to load served onsite by a nonmobile self-cogeneration or cogeneration facility that became operational on or after December 20, 1995.
  (2) The costs identified in Sections 367, 368, 375, and 376 shall not, prior to June 30, 2000, apply to any load served under over the fence arrangements entered into after December 20, 1995, between unaffiliated entities.
  (d) For the purposes of this subdivision, all onsite or over the fence arrangements shall be consistent with Section 218 as it existed on December 20, 1995.
  (e) To facilitate the development of new microcogeneration applications, electrical corporations may apply to the commission for a financing order to finance the transition costs to be recovered from customers employing the applications.
  (f) To encourage the continued development, installation, and interconnection of clean and efficient self-generation and cogeneration resources, to improve system reliability for consumers by retaining existing generation and encouraging new generation to connect to the electric grid, and to increase self-sufficiency of consumers of electricity through the deployment of self-generation and cogeneration, both of the following shall occur:
  (1) The commission and the Electricity Oversight Board shall determine if any policy or action undertaken by the Independent System Operator, directly or indirectly, unreasonably discourages the connection of existing self-generation or cogeneration or new self-generation or cogeneration to the grid.
  (2) If the commission and the Electricity Oversight Board find that any policy or action of the Independent System Operator unreasonably discourages the connection of existing self-generation or cogeneration or new self-generation or cogeneration to the grid, the commission and the Electricity Oversight Board shall undertake all necessary efforts to revise, mitigate, or eliminate that policy or action of the Independent System Operator.

(a) Electrical corporations may apply to the commission for an order determining that the costs identified in Sections 367, 368, 375, and 376 not be collected from a particular class of customer or category of electricity consumption.
  (b) Subject to the fire wall specified in subdivision (e) of Section 367, the provisions of this section and Sections 372 and 374 shall apply in the event the commission authorizes a nonbypassable charge prior to the implementation of an Independent System Operator and Power Exchange referred to in subdivision (a) of Section 365.

(a) In recognition of statutory authority and past investments existing as of December 20, 1995, and subject to the firewall specified in subdivision (e) of Section 367, the obligation to pay the uneconomic costs identified in Sections 367, 368, 375, and 376 shall not apply to the following:
  (1) One hundred ten megawatts of load served by irrigation districts, as hereafter allocated by this paragraph:
  (A) The 110 megawatts of load shall be allocated among the service territories of the three largest electrical corporations in the ratio of the number of irrigation districts in the service territory of each utility to the total number of irrigation districts in the service territories of all three utilities.
  (B) The total amount of load allocated to each utility service area shall be phased in over five years beginning January 1, 1997, so that one-fifth of the allocation is allocated in each of the five years. Any allocation that remains unused at the end of any year shall be carried over to the succeeding year and added to the allocation for that year.
  (C) The load allocated to each utility service territory pursuant to subparagraph (A) shall be further allocated among the respective irrigation districts within that service territory by the California Energy Resources Conservation and Development Commission. An individual irrigation district requesting an allocation shall submit to the commission by January 31, 1997, detailed plans that show the load that it serves or will serve and for which it intends to utilize the allocation within the timeframe requested. These plans shall include specific information on the irrigation districts' organization for electric distribution, contracts, financing and engineering plans for capital facilities, as well as detailed information about the loads to be served, and shall not be less than eight megawatts or more than 40 megawatts, provided, however, that any portion of the 110 megawatts that remains unallocated may be reallocated to projects without regard to the 40 megawatts limitation. In making an allocation among irrigation districts, the Energy Resources Conservation and Development Commission shall assess the viability of each submission and whether it can be accomplished in the timeframe proposed. The Energy Resources Conservation and Development Commission shall have the discretion to allocate the load covered by this section in a manner that best ensures its usage within the allocation period.
  (D) At least 50 percent of each year's allocation to a district shall be applied to that portion of load that is used to power pumps for agricultural purposes.
  (E) Any load pursuant to this subdivision shall be served by distribution facilities owned by, or leased to, the district in question.
  (F) Any load allocated pursuant to paragraph (1) shall be located within the boundaries of the affected irrigation district, or within the boundaries specified in an applicable service territory boundary agreement between an electrical corporation and the affected irrigation district; additionally, the provisions of subparagraph (C) of paragraph (1) shall be applicable to any load within the Counties of Stanislaus or San Joaquin, or both, served by any irrigation district that is currently serving or will be serving retail customers.
  (2) Seventy-five megawatts of load served by the Merced Irrigation District hereafter prescribed in this paragraph:
  (A) The total allocation provided by this paragraph shall be phased in over five years beginning January 1, 1997, so that one-fifth of the allocation is received in each of the five years. Any allocation that remains unused at the end of any year shall be carried over to the succeeding year and added to the allocation for that year.
  (B) Any load to which the provision of this paragraph is applicable shall be served by distribution facilities owned by, or leased to, Merced Irrigation District.
  (C) A load to which the provisions of this paragraph are applicable shall be located within the boundaries of Merced Irrigation District as those boundaries existed on December 20, 1995, together with the territory of Castle Air Force Base that was located outside of the district on that date.
  (D) The total allocation provided by this paragraph shall be phased in over five years beginning January 1, 1997, with the exception of load already being served by the district as of June 1, 1996, which shall be deducted from the total allocation and shall not be subject to the costs provided in Sections 367, 368, 375, and 376.
  (3) To loads served by irrigation districts, water districts, water storage districts, municipal utility districts, and other water agencies that, on December 20, 1995, were members of the Southern San Joaquin Valley Power Authority, or the Eastside Power Authority, provided, however, that this paragraph shall be applicable only to that portion of each district or agency's load that is used to power pumps that are owned by that district or agency as of December 20, 1995, or replacements thereof, and is being used to pump water for district purposes. The rates applicable to these districts and agencies shall be adjusted as of January 1, 1997.
  (4) The provisions of this subdivision shall no longer be operative after March 31, 2002.
  (5) The provisions of paragraph (1) shall not be applicable to any irrigation district, water district, or water agency described in paragraph (2) or (3).
  (6) Transmission services provided to any irrigation district described in paragraph (1) or (2) shall be provided pursuant to otherwise applicable tariffs.
  (7) Nothing in this chapter shall be deemed to grant the commission any jurisdiction over irrigation districts not already granted to the commission by existing law.
  (b) To give the full effect to the legislative intent in enacting Section 701.8, the costs provided in Sections 367, 368, 375, and 376 shall not apply to the load served by preference power purchased from a federal power marketing agency, or its successor, pursuant to Section 701.8 as it existed on January 1, 1996, provided that the power is used solely for the customer's own systems load and not for sale. The costs of this provision shall be borne by all ratepayers in the affected service territory, notwithstanding the firewall established in subdivision (e) of Section 367.
  (c) To give effect to an existing relationship, the obligation to pay the uneconomic costs specified in Sections 367, 368, 375, and 376 shall not apply to that portion of the load of the University of California campus situated in Yolo County that was being served as of May 31, 1996, by preference power purchased from a federal marketing agency, or its successor, provided that the power is used solely for the facility load of that campus and not, directly or indirectly, for sale.

Any electrical corporation serving agricultural customers that have multiple electric meters shall conduct research based on a statistically valid sample of those customers and meters to determine the typical simultaneous peak load of those customers. The results of the research shall be reported to the customers and the commission not later than July 1, 2001. The commission shall consider the research results in setting future electric distribution rates for those customers.

(a) In order to mitigate potential negative impacts on utility personnel directly affected by electric industry restructuring, as described in Decision 95-12-063, as modified by Decision 96-01-009, the commission shall allow the recovery of reasonable employee related transition costs incurred and projected for severance, retraining, early retirement, outplacement and related expenses for the employees.
  (b) The costs, including employee related transition costs for employees performing services in connection with Section 363, shall be added to the amount of uneconomic costs allowed to be recovered pursuant to this section and Sections 367, 368, and 376, provided recovery of these employee related transition costs shall extend beyond December 31, 2001, provided recovery of the costs shall not extend beyond December 31, 2006. However, there shall be no recovery for employee related transition costs associated with officers, senior supervisory employees, and professional employees performing predominantly regulatory functions.

To the extent that the costs of programs to accommodate implementation of direct access, the Power Exchange, and the Independent System Operator, that have been funded by an electrical corporation and have been found by the commission or the Federal Energy Regulatory Commission to be recoverable from the utility's customers, reduce an electrical corporation's opportunity to recover its utility generation-related plant and regulatory assets by the end of the year 2001, the electrical corporation may recover unrecovered utility generation-related plant and regulatory assets after December 31, 2001, in an amount equal to the utility's cost of commission-approved or Federal Energy Regulatory Commission approved restructuring-related implementation programs. An electrical corporation's ability to collect the amounts from retail customers after the year 2001 shall be reduced to the extent the Independent System Operator or the Power Exchange reimburses the electrical corporation for the costs of any of these programs.

The commission shall continue to regulate the facilities for the generation of electricity owned by any public utility prior to January 1, 1997, that are subject to commission regulation until the owner of those facilities has applied to the commission to dispose of those facilities and has been authorized by the commission under Section 851 to undertake that disposal. Notwithstanding any other provision of law, no facility for the generation of electricity owned by a public utility may be disposed of prior to January 1, 2006. The commission shall ensure that public utility generation assets remain dedicated to service for the benefit of California ratepayers.

Section 377 does not apply to the four run-of-river hydroelectric project works located on the Truckee River, as referenced in Section 210(b)(17) of Public Law 101-618 or to the two run-of-river hydroelectric projects, also known as the Naches Drop plant and Naches plant, located on the Wapatox Canal on the Naches River in the State of Washington.

Notwithstanding Section 377, a facility for the generation of electricity, or an interest in a facility for the generation of electricity, that is located outside of this state, is owned by a public utility that serves 60,000 or fewer customer accounts in this state, and is not necessary to serve that public utility's customers in this state, may be disposed of upon approval of the commission pursuant to Section 851 or upon exemption by the commission pursuant to Section 853.

The commission shall authorize new optional rate schedules and tariffs, including new service offerings, that accurately reflect the loads, locations, conditions of service, cost of service, and market opportunities of customer classes and subclasses.

Nuclear decommissioning costs shall not be part of the costs described in Sections 367, 368, 375, and 376, but shall be recovered as a nonbypassable charge until the time as the costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible.

Notwithstanding any other provision of law, on or before March 7, 2001, the commission, in consultation with the Independent System Operator, shall take all of the following actions, and shall include the reasonable costs involved in taking those actions in the distribution revenue requirements of utilities regulated by the commission, as appropriate:
  (a) (1) Identify and undertake those actions necessary to reduce or remove constraints on the state's existing electrical transmission and distribution system, including, but not limited to, reconductoring of transmission lines, the addition of capacitors to increase voltage, the reinforcement of existing transmission capacity, and the installation of new transformer banks. The commission shall, in consultation with the Independent System Operator, give first priority to those geographical regions where congestion reduces or impedes electrical transmission and supply.
  (2) Consistent with the existing statutory authority of the commission, afford electrical corporations a reasonable opportunity to fully recover costs it determines are reasonable and prudent to plan, finance, construct, operate, and maintain any facilities under its jurisdiction required by this section.
  (b) In consultation with the State Energy Resources Conservation and Development Commission, adopt energy conservation demand-side management and other initiatives in order to reduce demand for electricity and reduce load during peak demand periods. Those initiatives shall include, but not be limited to, all of the following:
  (1) Expansion and acceleration of residential and commercial weatherization programs.
  (2) Expansion and acceleration of programs to inspect and improve the operating efficiency of heating, ventilation, and air-conditioning equipment in new and existing buildings, to ensure that these systems achieve the maximum feasible cost-effective energy efficiency.
  (3) Expansion and acceleration of programs to improve energy efficiency in new buildings, in order to achieve the maximum feasible reductions in uneconomic energy and peak electricity consumption.
  (4) Incentives to equip commercial buildings with the capacity to automatically shut down or dim nonessential lighting and incrementally raise thermostats during a peak electricity demand period.
  (5) Evaluation of installing local infrastructure to link temperature setback thermostats to real-time price signals.
  (6) Incentives for load control and distributed generation to be paid for enhancing reliability.
  (7) Differential incentives for renewable or super clean distributed generation resources pursuant to Section 379.6.
  (8) Reevaluation of all efficiency cost-effectiveness tests in light of increases in wholesale electricity costs and of natural gas costs to explicitly include the system value of reduced load on reducing market clearing prices and volatility.
  (c) In consultation with the Energy Resources Conservation and Development Commission, adopt and implement a residential, commercial, and industrial peak reduction program that encourages electric customers to reduce electricity consumption during peak power periods.

(a) (1) It is the intent of the Legislature that the self-generation incentive program increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs. It is the further intent of the Legislature that the commission, in future proceedings, provide for an equitable distribution of the costs and benefits of the program.
  (2) The commission, in consultation with the Energy Commission, may authorize the annual collection of not more than the amount authorized for the self-generation incentive program in the 2008 calendar year, through December 31, 2019. The commission shall require the administration of the program for distributed energy resources originally established pursuant to Chapter 329 of the Statutes of 2000 until January 1, 2021. On January 1, 2021, the commission shall provide repayment of all unallocated funds collected pursuant to this section to reduce ratepayer costs.
  (3) The commission shall administer solar technologies separately, pursuant to the California Solar Initiative adopted by the commission in Decisions 05-12-044 and 06-01-024, as modified by Article 1 (commencing with Section 2851) of Chapter 9 of Part 2 of Division 1 of this code and Chapter 8.8 (commencing with Section 25780) of Division 15 of the Public Resources Code.
  (b) (1) Eligibility for incentives under the self-generation incentive program shall be limited to distributed energy resources that the commission, in consultation with the State Air Resources Board, determines will achieve reductions in emissions of greenhouse gases pursuant to the California Global Warming Solutions Act of 2006 (Division 25.5 (commencing with Section 38500) of the Health and Safety Code).
  (2) On or before July 1, 2015, the commission shall update the factor for avoided greenhouse gas emissions based on the most recent data available to the State Air Resources Board for greenhouse gas emissions from electricity sales in the self-generation incentive program administrators' service areas as well as current estimates of greenhouse gas emissions over the useful life of the distributed energy resource, including consideration of the effects of the California Renewables Portfolio Standard.
  (c) Eligibility for the funding of any combustion-operated distributed generation projects using fossil fuel is subject to all of the following conditions:
  (1) An oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per megawatthour and a minimum efficiency of 60 percent, or any other NOx emissions rate and minimum efficiency standard adopted by the State Air Resources Board. A minimum efficiency of 60 percent shall be measured as useful energy output divided by fuel input. The efficiency determination shall be based on 100 percent load.
  (2) Combined heat and power units that meet the 60-percent efficiency standard may take a credit to meet the applicable NOx emissions standard of 0.07 pounds per megawatthour. Credit shall be at the rate of one megawatthour for each 3,400,000 British thermal units (Btus) of heat recovered.
  (3) The customer receiving incentives shall adequately maintain and service the combined heat and power units so that during operation the system continues to meet or exceed the efficiency and emissions standards established pursuant to paragraphs (1) and (2).
  (4) Notwithstanding paragraph (1), a project that does not meet the applicable NOx emissions standard is eligible if it meets both of the following requirements:
  (A) The project operates solely on waste gas. The commission shall require a customer that applies for an incentive pursuant to this paragraph to provide an affidavit or other form of proof that specifies that the project shall be operated solely on waste gas. Incentives awarded pursuant to this paragraph shall be subject to refund and shall be refunded by the recipient to the extent the project does not operate on waste gas. As used in this paragraph, "waste gas" means natural gas that is generated as a byproduct of petroleum production operations and is not eligible for delivery to the utility pipeline system.
  (B) The air quality management district or air pollution control district, in issuing a permit to operate the project, determines that operation of the project will produce an onsite net air emissions benefit compared to permitted onsite emissions if the project does not operate. The commission shall require the customer to secure the permit prior to receiving incentives.
  (d) In determining the eligibility for the self-generation incentive program, minimum system efficiency shall be determined either by calculating electrical and process heat efficiency as set forth in Section 216.6, or by calculating overall electrical efficiency.
  (e) Eligibility for incentives under the program shall be limited to distributed energy resource technologies that the commission determines meet all of the following requirements:
  (1) The distributed energy resource technology shifts onsite energy use to off-peak time periods or reduces demand from the grid by offsetting some or all of the customer's onsite energy load, including, but not limited to, peak electric load.
  (2) The distributed energy resource technology is commercially available.
  (3) The distributed energy resource technology safely utilizes the existing transmission and distribution system.
  (4) The distributed energy resource technology improves air quality by reducing criteria air pollutants.
  (f) Recipients of the self-generation incentive program funds shall provide relevant data to the commission and the State Air Resources Board, upon request, and shall be subject to onsite inspection to verify equipment operation and performance, including capacity, thermal output, and usage to verify criteria air pollutant and greenhouse gas emissions performance.
  (g) In administering the self-generation incentive program, the commission shall determine a capacity factor for each distributed generation system energy resource technology in the program.
  (h) (1) In administering the self-generation incentive program, the commission may adjust the amount of rebates and evaluate other public policy interests, including, but not limited to, ratepayers, energy efficiency, peak load reduction, load management, and environmental interests.
  (2) The commission shall consider the relative amount and the cost of greenhouse gas emissions reductions, peak demand reductions, system reliability benefits, and other measurable factors when allocating program funds between eligible technologies.
  (i) The commission shall ensure that distributed generation resources are made available in the program for all ratepayers.
  (j) In administering the self-generation incentive program, the commission shall provide an additional incentive of 20 percent from existing program funds for the installation of eligible distributed generation resources manufactured in California.
  (k) The costs of the program adopted and implemented pursuant to this section shall not be recovered from customers participating in the California Alternate Rates for Energy (CARE) program.
  (l) The commission shall evaluate the overall success and impact of the self-generation incentive program based on the following performance measures:
  (1) The amount of reductions of emissions of greenhouse gases.
  (2) The amount of reductions of emissions of criteria air pollutants measured in terms of avoided emissions and reductions of criteria air pollutants represented by emissions credits secured for project approval.
  (3) The amount of energy reductions measured in energy value.
  (4) The amount of reductions of customer peak demand.
  (5) The ratio of the electricity generated by distributed energy resource generation projects receiving incentives from the program to the electricity capable of being produced by those projects, commonly known as a capacity factor.
  (6) The value to the electrical transmission and distribution system measured in avoided costs of transmission and distribution upgrades and replacement.
  (7) The ability to improve onsite electricity reliability as compared to onsite electricity reliability before the self-generation incentive program technology was placed in service.

(a) The Legislature finds and declares that the demonstration project authorized pursuant to this section, at the Antelope Valley Fairgrounds, to determine actual energy and cost savings that may be achieved when investments are made onsite to both reduce overall electricity demand and to offset peak electricity demand through the installation of (1) cost-effective energy efficient equipment and fixtures, and (2) a photovoltaic solar energy system, will provide valuable empirical data upon which to optimize future ratepayer investments in cost-effective energy efficiency and photovoltaic solar systems.
  (b) (1) The demonstration project authorized pursuant to this section shall be referred to as the Antelope Valley Fairgrounds EE and PV Synergy Demonstration Project.
  (2) To ensure that potential energy and cost savings from cost-effective energy efficient equipment and fixtures are achieved, the Antelope Valley Fairgrounds shall do both of the following:
  (A) Implement the recommendations of the energy audit performed on July 27, 2004.
  (B) Include cost-effective energy efficient equipment and fixtures in all future expansions of the fairgrounds.
  (3) To ensure that potential energy and cost savings are achieved from a photovoltaic solar energy system of up to 630 kilowatts installed at the Antelope Valley Fairgrounds, the photovoltaic solar energy system shall meet both of the following criteria:
  (A) Be installed in a manner that optimizes operating efficiency, including appropriate siting.
  (B) Consist of components that are new and unused and have a warranty of not less than 10 years to protect against defects and undue degradation of electrical generation output.
  (c) An electrical corporation providing electrical service to the Antelope Valley Fairgrounds shall, by February 1, 2006, file with the commission a tariff providing for an incentive rate consistent with this section. The incentive rate shall provide stability and certainty over a 10-year period in an amount and in a manner to support investment in, and to test the durability of, the photovoltaic solar energy system installed at the fairgrounds. The incentive rate, together with an incentive from the self-generation incentive program that recognizes the energy efficiency investments made at the fairgrounds as authorized pursuant to Section 379.6, shall provide for a 10-year payback period for the photovoltaic solar energy system. The incentive rate shall not result in any cost shifting among customer classes of the electrical corporation.
  (d) Actual energy and cost savings shall be determined through annual energy audits and ongoing metering of electricity used and electricity produced on a time-of-use basis.
  (e) The demonstration project will be complete 10 years from the date the Antelope Valley Fairgrounds first takes electrical service pursuant to the incentive rate required by this section.
  (f) This section shall remain in effect only until January 1, 2017, and as of that date is repealed, unless a later enacted statute, that is enacted before January 1, 2017, deletes or extends that date.

(a) As used in this section, "advanced electrical distributed generation technology" means any electrical distributed generation technology that generates useful electricity and meets all of the following conditions:
  (1) The emissions standards adopted by the State Air Resources Board pursuant to the distributed generation certification program requirements of Article 3 (commencing with Section 94200) of Subchapter 8 of Chapter 1 of Division 3 of Title 17 of the California Code of Regulations.
  (2) Produces de minimis emissions of sulfur oxides and nitrogen oxides.
  (3) Meets the greenhouse gases emission performance standard established by the commission pursuant to Section 8341.
  (4) Has a total electrical efficiency of not less than 45 percent. If legislation is enacted that increases the 42.5 percent efficiency described in subdivision (b) of Section 216.6 above 45 percent, the commission may adjust the electrical efficiency standard described in this paragraph to ensure that this electrical efficiency standard meets or exceeds the standard enacted for the purposes of subdivision (b) of Section 216.6.
  (5) Is sized to meet the generator's onsite electrical demand.
  (6) Has parallel operation to the electrical distribution grid.
  (7) Utilizes renewable or nonrenewable fuel.
  (b) (1) An advanced electrical distributed generation technology shall qualify for the rate established by the commission pursuant to Section 454.4.
  (2) The limitation in subdivision (b) of Section 6352 upon the assessment of surcharges for gas used to generate electricity by a nonutility facility applies to an advanced electrical distributed generation technology.
  (3) The limitation in Section 2773.5 upon imposing alternative fuel capability requirements upon gas customers that use gas for purposes of cogeneration applies to an advanced electrical distributed generation technology.
  (c) The commission or State Air Resources Board may, in furtherance of the state's goals for achieving cost-effective reductions in emissions of greenhouse gases, meeting resource adequacy requirements, or meeting the renewables portfolio standard, treat advanced electrical distributed generation technology as cogeneration.
  (d) Subdivisions (b) and (c) do not apply to an advanced electrical distributed generation technology that is first operational at a site on and after January 1, 2016.

(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 achieve all of the following objectives:
  (1) Facilitate development of new generating capacity and retention of existing generating capacity that is economic and needed.
  (2) Establish new or maintain existing demand response products and tariffs that facilitate the economic 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) Equitably allocate the cost of generating capacity and demand response in a manner that prevents the shifting of costs between customer classes.
  (4) 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 electric service system reliability and local area reliability.
  (d) Each load-serving entity shall, at a minimum, meet the most recent minimum planning reserve and reliability criteria approved by the Board of Directors 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 and the renewables portfolio standard program that are applicable to electrical corporations pursuant to this section, or otherwise required by 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) 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.
  (g) An electrical corporation's costs of meeting or reducing resource adequacy requirements, including, but not limited to, the costs associated with system reliability and local area reliability, 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, 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 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.
  (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, as well as in planning proceedings and associated analyses, and shall encourage reflection of these changes in demand in the operation of the grid.
  (k) 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 transmission or distribution grid, so that, if the customer generation fails, backup electricity is not supplied from the electrical 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.

(a) In establishing a demand response program, the commission shall do all of the following:
  (1) Establish rules consistent with state and federal law for how and when back-up generation may be used within the program and establish reporting and data collection requirements to verify compliance with those rules.
  (2) Ensure the program approved for resource adequacy requirements delivers the expected results and provides ratepayer benefits.
  (3) Before the implementation of a program for residential customers, establish customer protection rules regarding the participation, cost of participation, and ability to not enroll in the program. A residential customer who does not enroll in the program shall lose eligibility for rebates, discounts, and other incentives offered to customers who participate in the program. The commission shall prohibit the imposition of charges on a residential customer for not enrolling in the program.
  (4) Establish a method to accurately calculate the customer's load shift at time intervals in which the customer would be eligible for demand response program payments or credits.
  (5) Establish metering and monitoring policies for the program.
  (b) This section does not apply to time-variant pricing as defined in Section 745, including time-of-use rates, critical peak pricing, and real-time pricing, or to similar tariffs, including peak time rebates.