citation: PUC § 366

text:
(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.

history: (History: Amended by Stats. 2002, Ch. 838, Sec. 3. Effective January 1, 2003.)


kind: section

code: PUC

text:
(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.

history: (History: Added by Stats. 2002, Ch. 837, Sec. 2. Effective January 1, 2003.)

division: 1. REGULATION OF PUBLIC UTILITIES

part: 1. PUBLIC UTILITIES ACT

chapter: 2.3. Electrical Restructuring

path: 1. REGULATION OF PUBLIC UTILITIES > 1. PUBLIC UTILITIES ACT > 2.3. Electrical Restructuring > 6. Requirements for the Public Utilities Commission


text:
(a) (1) Customers shall be entitled to aggregate their electrical 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 the customer’s 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 shall 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 shall not require a positive written declaration, but each customer shall be informed of the customer’s right to opt out of the community choice aggregation program. If no negative declaration is made by a customer, that customer shall be served through the community choice aggregation program. If an existing customer moves the location of the customer’s electrical service within the jurisdiction of the community choice aggregator, the customer shall retain the same subscriber status as before the move, unless the customer affirmatively changes the customer’s subscriber status. If the customer is moving from outside to inside the jurisdiction of the community choice aggregator, customer participation shall not require a positive written declaration, but the customer shall be informed of the customer’s right to elect not to receive service through the community choice aggregator.

(3) A community choice aggregator establishing electrical load aggregation pursuant to this section shall develop an implementation plan detailing the process and consequences of aggregation. The implementation plan, and any subsequent changes to it, shall be considered and adopted at a duly noticed public hearing. The implementation plan shall contain all of the following:

(A) An organizational structure of the program, its operations, and its funding.

(B) Ratesetting and other costs to participants.

(C) Provisions for disclosure and due process in setting rates and allocating costs among participants.

(D) The methods for entering and terminating agreements with other entities.

(E) The rights and responsibilities of program participants, including, but not limited to, consumer protection procedures, credit issues, and shutoff procedures.

(F) Termination of the program.

(G) A description of the third parties that will be supplying electricity under the program, including, but not limited to, information about financial, technical, and operational capabilities.

(H) The methods for ensuring procurement from small, local, and diverse business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.

(4) A community choice aggregator establishing electrical load aggregation shall prepare a statement of intent with the implementation plan. Any community choice load aggregation established pursuant to this section shall provide for all of 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) An entity proposing community choice aggregation shall not 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 on 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 the joint powers agreement that, unless otherwise agreed by the members of the agency, the debts, liabilities, and obligations of the agency shall not be the debts, liabilities, and obligations, either jointly or severally, of the members of the agency. The commission shall not, as a condition of registration or otherwise, require an agency’s members to voluntarily assume the debts, liabilities, and obligations of the agency to the electrical corporation unless the commission finds that the agreement by the agency’s members is the only reasonable means by which the agency may establish its creditworthiness under the electrical corporation’s tariff to pay charges to the electrical corporation under the tariff.

(13) 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 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) This section does not authorize 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 the customer is 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 service provided by the electrical corporation, or another straightforward means by which the customer may elect to derive electrical 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 before 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 electricity from an electrical corporation on or after February 1, 2001, should bear a fair share of the Department of Water Resources’ electricity purchase costs, and 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, the Energy Commission, an electrical corporation, or a 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) This subdivision does not 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 before authorizing a termination of service, that the community choice aggregator has been provided adequate notice and a reasonable opportunity to be heard regarding any electrical corporation contentions in support of termination. If the contentions made by the electrical corporation in favor of termination include factual claims, the community choice aggregator shall be afforded an opportunity to address those claims in an evidentiary hearing.

(2) Notwithstanding paragraph (1), if the Independent System Operator has transferred the community choice aggregator’s scheduling coordination responsibilities to the incumbent electrical corporation, an administrative law judge or assigned commissioner, after providing the aggregator with notice and an opportunity to respond, may suspend the aggregator’s service to customers pending a full vote of the commission.

(m) (1) The commission shall require each community choice aggregator with gross annual revenues exceeding fifteen million dollars ($15,000,000) to annually submit a detailed and verifiable plan to the commission for increasing procurement from small, local, and diverse business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.

(2) (A) The commission shall require each community choice aggregator with gross annual revenues exceeding fifteen million dollars ($15,000,000) to annually submit a report to the commission regarding its procurement from women, minority, disabled veteran, and LGBT business enterprises in all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.

(B) The report shall be in a form that the commission may require and shall be submitted by an annual date that the commission shall designate.

(C) The report shall include women, minority, disabled veteran, and LGBT business enterprises with whom a prime contractor or grantee of a community choice aggregator has engaged in contracts or subcontracts for all categories, including, but not limited to, renewable energy, energy storage system, and smart grid projects.

(3) The Legislature declares that each community choice aggregator that is not required to submit a plan pursuant to this subdivision is encouraged to voluntarily adopt a plan for increasing procurement from small, local, and diverse business enterprises in all categories.

(n) 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).

(o) (1) As part of each annual report required pursuant to subdivision (m), each community choice aggregator shall provide all of the following information in the aggregate:

(A) The number of new contractors and subcontractors certified pursuant to General Order 156 with which it contracted.

(B) The total dollar amounts expended with in-state contractors certified under General Order 156.

(C) The total dollar amounts expended with in-state subcontractors certified under General Order 156.

(D) The percentage of the total workforce used by contractors and subcontractors that reside in California.

(E) Data regarding the diversity of contractor or subcontractor workforces, to the extent that the data is provided voluntarily by the employees of the contractor or subcontractor.

(2) A community choice aggregator may use data provided to the commission pursuant to subdivision (b) of Section 8284 to satisfy the requirements of paragraph (1).

(p) For purposes of this section, “disabled veteran business enterprise,” “LGBT business enterprise,” “minority business enterprise,” “renewable energy project,” and “women business enterprise,” are defined as in Section 8282.

history: (History: Amended by Stats. 2024, Ch. 784, Sec. 1. (SB 1177) Effective January 1, 2025.)

article: 6. Requirements for the Public Utilities Commission


text: 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.

history: (History: Added by Stats. 2015, Ch. 547, Sec. 15. (SB 350) Effective January 1, 2016.)


text:
(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.

history: (History: Amended by Stats. 2001, 1st Ex. Sess., Ch. 4, Sec. 3. Effective February 1, 2001.)


citation: PUC § 367

text:
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.

history: (History: Amended by Stats. 1997, Ch. 275, Sec. 7. Effective August 15, 1997.)


text:
(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.

history: (History: Added by Stats. 1999, Ch. 408, Sec. 1. Effective January 1, 2000.)


citation: PUC § 368

text:
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.

history: (History: Amended by Stats. 1997, Ch. 17, Sec. 125. Effective January 1, 1998.)


text:
(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.

history: (History: Added by Stats. 2001, 2nd Ex. Sess., Ch. 7, Sec. 2. Effective August 8, 2002.)


citation: PUC § 369

text:
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.

history: (History: Added by Stats. 1996, Ch. 854, Sec. 10. Effective September 24, 1996.)


text:
(a) On or before December 31, 2026, the commission, in consultation with the Energy Commission, shall develop a framework for assessing, tracking, and analyzing total annual energy costs paid by residential households in California. The framework shall include all of the following:

(1) A methodology for identifying, categorizing, and quantifying major residential household energy sources.

(2) The total annual energy costs borne by residential households.

(3) Annual costs for major residential household energy sources, including, but not limited to, electricity, natural gas, propane, gasoline, and diesel.

(4) Changes in the total annual energy costs for residential households over time.

(5) The relative contributions of different energy sources to the total annual energy costs borne by residential households.

(6) The annual growth rate of energy costs for residential households by energy source.

(7) Projections of possible future total energy costs for residential households for the next 10 years.

(8) Scenarios of actions that may lead to a 5 percent, 10 percent, and 15 percent reduction in total annual energy costs paid by residential households in 2035, relative to 2024 total annual energy costs after adjusting for inflation.

(9) An assessment of the actions identified pursuant to paragraph (8) and the effects they may have on public health and safety, electrical and gas system reliability, and the achievement of the state’s 2045 clean electricity goal developed pursuant to Section 454.53 and the state’s 2045 carbon neutrality goal developed pursuant to Section 38562.2 of the Health and Safety Code.

(b) The commission may use the total annual energy cost framework pursuant to subdivision (a) for purposes of evaluating any request by an electrical corporation and gas corporation to track new spending eligible for recovery or to adjust a revenue requirement. In evaluating any such request, the commission shall consider whether the electrical corporation and gas corporation should take additional actions to achieve the reductions in total annual energy costs identified in paragraph (8) of subdivision (a).

(c) (1) On or before December 31, 2026, the commission shall submit a report to the Legislature containing the framework and the information in subdivision (a).

(2) Pursuant to Section 10231.5 of the Government Code, this subdivision shall become inoperative on December 31, 2030.

history: (History: Added by Stats. 2024, Ch. 762, Sec. 2. (AB 3264) Effective January 1, 2025. Inoperative December 31, 2030, by its own provisions.)


citation: PUC § 370

text: 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.


citation: PUC § 371

text:
(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 Energy Commission, 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) This section does not 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. This section does not limit the ability of residential customers to alter their pattern of electricity purchases by activities on the customer side of the meter.

(d) Enhancement or increased efficiency of equipment, as described in subdivision (b), shall include industrial process heat recovery technology that meets the requirements of Section 451.7.

history: (History: Amended by Stats. 2024, Ch. 700, Sec. 2. (AB 2109) Effective January 1, 2025.)


citation: PUC § 372

text:
(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 before 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 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 before 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 before 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, before 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, before June 30, 2000, apply to a load served under an over-the-fence arrangement entered into after December 20, 1995, between unaffiliated entities.

(d) For the purposes of this section, 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.

history: (History: Amended by Stats. 2017, Ch. 561, Sec. 209. (AB 1516) Effective January 1, 2018.)


citation: PUC § 373

text:
(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.


citation: PUC § 374

text:
(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 Energy 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 use 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 Commission shall assess the viability of each submission and whether it can be accomplished in the timeframe proposed. The Energy 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 this paragraph 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. The provisions of subparagraph (C) of this paragraph shall be applicable to any load within the County 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 the County of Yolo 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.

history: (History: Amended by Stats. 2019, Ch. 396, Sec. 18. (AB 1513) Effective January 1, 2020.)


text: 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.

history: (History: Added by Stats. 1999, Ch. 909, Sec. 5. Effective January 1, 2000.)


citation: PUC § 375

text:
(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.


citation: PUC § 376

text: 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.


citation: PUC § 377

text: 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.

history: (History: Amended by Stats. 2001, 1st Ex. Sess., Ch. 2, Sec. 3. Effective January 18, 2001.)


text: 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.

history: (History: Added by Stats. 2002, Ch. 840, Sec. 1. Effective September 24, 2002.)


text: 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.

history: (History: Amended by Stats. 2004, Ch. 183, Sec. 313. Effective January 1, 2005.)


citation: PUC § 378

text: 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.


citation: PUC § 379

text: 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.


text:
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 Energy 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 Commission, adopt and implement a residential, commercial, and industrial peak reduction program that encourages electric customers to reduce electricity consumption during peak power periods.

history: (History: Amended by Stats. 2019, Ch. 396, Sec. 19. (AB 1513) Effective January 1, 2020.)


text:
(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 double the amount authorized for the self-generation incentive program in the 2008 calendar year, through December 31, 2024. 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, 2026. On January 1, 2026, the commission shall provide repayment of all unallocated funds collected pursuant to this section to reduce ratepayer costs.

(b) (1) Eligibility for incentives under the self-generation incentive program that are funded through the annual collection authorized pursuant to paragraph (2) of subdivision (a) 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 both 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 and 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.

(3) The commission shall adopt requirements for energy storage systems to ensure that eligible energy storage systems reduce the emissions of greenhouse gases.

(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 before 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 self-generation incentive 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, net peak electric load.

(2) The distributed energy resource technology is commercially available.

(3) The distributed energy resource technology safely uses 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 incentives 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 self-generation incentive 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 self-generation incentive program 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 self-generation incentive 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.

(m) On and after January 1, 2020, generation technologies using nonrenewable fuels shall not be eligible for incentives under the self-generation incentive program.

history: (History: Amended by Stats. 2022, Ch. 251, Sec. 25. (AB 209) Effective September 6, 2022.)


text:
(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.

history: (History: Amended by Stats. 2014, Ch. 71, Sec. 146. (SB 1304) Effective January 1, 2015.)