AB 1301: Electricity.

25217.1.

The commission shall nominate and the Governor shall appoint for a term of three years a public advisor to the commission who shall carry out Section 25222 and other duties prescribed by this division or by the commission. The public advisor may be removed from office only upon the joint concurrence of four commissioners and the Governor.

25301.

(a) At least every two years, the commission shall conduct assessments and forecasts of all aspects of energy industry supply, production, transportation, delivery and distribution, demand, and prices. The commission shall use these assessments and forecasts to develop and evaluate energy policies and programs that conserve resources, protect the environment, ensure energy reliability, enhance the state’s economy, and protect public health and safety. To perform these assessments and forecasts, the commission may require the submission of demand forecasts, resource plans, market assessments, related outlooks, individual customer historical electrical or gas service usage, or both, and individual customer historical billing data, in a format and level of granularity specified by the commission from electrical and natural gas utilities, transportation fuel and technology suppliers, and other market participants. These assessments and forecasts shall be done in consultation with the appropriate state and federal agencies, including, but not limited to, the Public Utilities Commission, the Public Advocate’s Office of the Public Utilities Commission, the State Air Resources Board, the Independent System Operator, the Department of Water Resources, the Department of Transportation, and the Department of Motor Vehicles. The commission shall maintain reasonable policies and procedures to protect customer information from unauthorized disclosure.

(b) In developing the assessments and forecasts prepared pursuant to subdivision (a), the commission shall do all of the following:

(1) Provide information about the performance of energy industries.

(2) Develop and maintain the analytical capability sufficient to answer inquiries about energy issues from the government, market participants, and the public.

(3) Analyze, develop, and evaluate energy policies and programs.

(4) Provide an analytical foundation for regulatory and policy decisionmaking.

(5) Facilitate efficient and reliable energy markets.

25302.

(a) Beginning November 1, 2003, and every two years thereafter, the commission shall adopt an integrated energy policy report. This integrated report shall contain an overview of major energy trends and issues facing the state, including, but not limited to, supply, demand, pricing, reliability, efficiency, and impacts on public health and safety, the economy, resources, and the environment. The integrated energy policy report shall present policy recommendations based on an in-depth and integrated analysis of the most current and pressing energy issues facing the state. The analyses supporting this integrated energy policy report shall explicitly address interfuel and intermarket effects to provide a more informed evaluation of potential tradeoffs when developing energy policy across different markets and systems.

(b) The integrated energy policy report shall include an assessment and forecast of system reliability and the need for resource additions, efficiency, and conservation that considers all aspects of energy industries and markets that are essential for the state economy, general welfare, public health and safety, energy diversity, and protection of the environment. This assessment shall be based on the determinations made pursuant to this chapter.

(c) Beginning November 1, 2004, and every two years thereafter, the commission shall prepare an energy policy review to update analyses from the integrated energy policy report prepared pursuant to subdivisions (a) and (b), or to raise energy issues that have emerged since the release of the integrated energy policy report. The commission may also periodically prepare and release technical analyses and assessments of energy issues and concerns to provide timely and relevant information for the Governor, the Legislature, market participants, and the public.

(d) In the preparation of the report, the commission shall consult with the following entities: the Public Utilities Commission, the Public Advocate’s Office of the Public Utilities Commission, the State Air Resources Board, the Independent System Operator, the Department of Water Resources, the Department of Transportation, and the Department of Motor Vehicles, and any federal, state, and local agencies it deems necessary in preparation of the integrated energy policy report. To ensure the collaborative development of state energy policies, these agencies shall make a good faith effort to provide data, assessment, and proposed recommendations for review by the commission.

(e) The commission shall provide the report to the Public Utilities Commission, the Public Advocate’s Office of the Public Utilities Commission, the State Air Resources Board, the Independent System Operator, the Department of Water Resources, and the Department of Transportation. For the purpose of ensuring consistency in the underlying information that forms the foundation of energy policies and decisions affecting the state, those entities shall carry out their energy-related duties and responsibilities based upon the information and analyses contained in the report. If an entity listed in this subdivision objects to information contained in the report and has a reasonable basis for that objection, the entity shall not be required to consider that information in carrying out its energy-related duties.

(f) The commission shall make the report accessible to state, local, and federal entities and to the general public.

25334.

(a) Upon receipt of an application or upon its own motion for designation of a transmission corridor zone, the commission shall arrange for the publication of a summary of the application in a newspaper of general circulation in each county where the proposed transmission corridor zone would be located, and shall notify all property owners within, or adjacent to, the transmission corridor zone. The commission shall transmit a copy of the application for designation to all cities, counties, and state and federal agencies having an interest in the proposed transmission corridor zone. The commission shall publish the application for designation on its internet website and notify members of the public that the application is available on the commission’s internet website.

(b) As soon as practicable after the receipt of an application or upon its own motion for designation of a transmission corridor zone, the commission shall notify cities, counties, state and federal agencies, and California Native American tribes in whose jurisdictions the proposed transmission corridor zone would be located regarding the proposed transmission corridor zone and the objectives of the most recent strategic plan for the state’s electrical transmission grid. The commission’s notice shall solicit information from, and the commission shall confer with, all interested cities, counties, state and federal agencies, and California Native American tribes regarding their land use plans, existing land uses, and other factors in which they have expertise or interest with respect to the proposed transmission corridor zone. The commission shall provide any interested city, county, state or federal agency, California Native American tribe, or member of the public, including any property owner within the proposed transmission corridor zone, ample opportunity to participate in the commission’s review of a proposed transmission corridor zone.

(c) The commission shall request affected cities, counties, state and federal agencies, the Independent System Operator, interested California Native American tribes, and members of the public, including any property owner within the proposed transmission corridor zone, to provide comments on the suitability of the proposed transmission corridor zone with respect to environmental, public health and safety, land use, economic, and transmission-system impacts or other factors on which they may have expertise.

(d) The commission shall require a person who files an application for the designation of a transmission corridor zone to pay a fee sufficient to reimburse the commission for all costs associated with reviewing the application. If the commission initiates the designation of a transmission corridor zone on its own motion, the commission shall fix the surcharge imposed pursuant to subdivision (b) of Section 40016 of the Revenue and Taxation Code, at a level sufficient to cover the commission’s added costs.

(e) Upon receiving the commission’s request for review of a proposed transmission corridor zone, a city or county may request a fee pursuant to Section 25538 to cover for the actual and added costs of this review and the commission shall pay this amount to the city or county.

25421.

(a) Except as provided in subdivision (b), this chapter shall remain in effect only until January 1, 2038, and as of that date is repealed, unless a later enacted statute, which is enacted before January 1, 2038, deletes or extends that date.

(b) Except as specified in subdivisions (c) and (d), all loans outstanding as of January 1, 2038, shall continue to be repaid on a semiannual basis, as specified in Section 25415, until paid in full. All unexpended funds in the State Energy Conservation Assistance Account on January 1, 2038, and after that date, shall revert to the General Fund.

(c) To the extent required under applicable bond obligations, unexpended funds from the proceeds of bonds sold pursuant to Section 25417.5 that remain in the State Energy Conservation Assistance Account on January 1, 2038, shall remain in the account. These funds shall be expended pursuant to the applicable requirements for bond proceeds. Once all applicable bond obligations have been satisfied, unexpended funds shall revert to the General Fund.

(d) Unexpended funds from the federal American Recovery and Reinvestment Act of 2009 (Public Law 111-5) remaining in the State Energy Conservation Assistance Account on January 1, 2038, shall revert to the Federal Trust Fund.

25660.2.

(a) On or before March 1, 2024, and annually thereafter by that date until all funds appropriated for purposes of this chapter have been expended, the commission shall publish on its internet website and report, as applicable, to the budget and relevant policy committees of the Legislature all of the following for each clean energy program:

(1) The amount of moneys expended for the program and balance of moneys remaining to be spent, including geographic distribution of those moneys.

(2) The amount of moneys expended on administrative, technical, or scientific services for the program.

(3) Quantitative estimates and qualitative information on how moneys expended by the program are achieving the specific purposes of that program.

(4) Estimates of additional electrical generation or storage capacity at net peak hours or during critical grid conditions created, expanded, or otherwise made available as a direct result of the program.

(5) Estimated onsite reductions of the emissions of greenhouse gases and criteria air pollutants that occurred as a direct result of the program.

(6) A description of how the appropriated moneys were used for the program and industries receiving program funding.

(b) (1) In addition to the publishing and reporting requirements of subdivision (a), on or before March 1, 2027, and annually thereafter by that date until all funds appropriated for purposes of Article 5 (commencing with Section 25665) have been expended, the commission shall publish on its internet website and report, as applicable, to the budget and relevant policy committees of the Legislature all of the following information about the Equitable Building Decarbonization Program:

(A) Information about the progress of the program, including, but not limited to, selected administrators and implementers.

(B) The status of implementation.

(C) The program budget and status.

(D) The number of each project type implemented.

(E) The number of residents and buildings provided low- and zero-cost projects.

(F) The estimated reductions of the emissions of greenhouse gases.

(G) The locational distribution of the expenditures by county and region.

(2) Upon the complete expenditure of all moneys for the Equitable Building Decarbonization Program, the commission shall notify the Secretary of State contemporaneously with the submission of the report required by subdivision (a) that includes information regarding the last expended moneys.

330.

To provide guidance in carrying out this chapter, the Legislature finds and declares all of the following:

(a) It is the intent of the Legislature that a cumulative rate reduction of at least 20 percent be achieved on or before April 1, 2002, for residential and small commercial customers, from the rates in effect on June 10, 1996. In determining that the April 1, 2002, rate reduction has been met, the commission shall exclude the costs of the competitively procured electricity and the costs associated with the rate reduction bonds, as defined in Section 840.

(b) The people, businesses, and institutions of California spend nearly twenty-three billion dollars ($23,000,000,000) annually on electricity, so that reductions in the price of electricity would significantly benefit the economy of the state and its residents.

(c) The commission has opened rulemaking and investigation proceedings with regard to restructuring California’s electricity industry and reforming utility regulation.

(d) The commission has found, after an extensive public review process, that the interests of ratepayers and the state as a whole will be best served by moving from the regulatory framework existing on January 1, 1997, in which retail electricity service is provided principally by electrical corporations subject to an obligation to provide ultimate consumers in exclusive service territories with reliable electric service at regulated rates, to a framework under which competition would be allowed in the supply of electricity and customers would be allowed to have the right to choose their supplier of electricity.

(e) Competition in the electric generation market will encourage innovation, efficiency, and better service from all market participants, and will permit the reduction of costly regulatory oversight.

(f) The delivery of electricity over transmission and distribution systems is currently regulated, and will continue to be regulated to ensure system safety, reliability, environmental protection, and fair access for all market participants.

(g) Reliable electric service is of utmost importance to the safety, health, and welfare of the state’s citizenry and economy. It is the intent of the Legislature that electric industry restructuring should enhance the reliability of the interconnected regional transmission systems, and provide strong coordination and enforceable protocols for all users of the power grid.

(h) It is important that sufficient supplies of electric generation will be available to maintain the reliable service to the citizens and businesses of the state.

(i) Reliable electric service depends on conscientious inspection and maintenance of transmission and distribution systems. To continue and enhance the reliability of the delivery of electricity, the Independent System Operator and the commission, respectively, should set inspection, maintenance, repair, and replacement standards.

(j) It is the intent of the Legislature that California enter into a compact with western region states. That compact should require the publicly and investor-owned utilities located in those states, that sell energy to California retail customers, to adhere to enforceable standards and protocols to protect the reliability of the interconnected regional transmission and distribution systems.

(k) To achieve meaningful wholesale and retail competition in the electric generation market, it is essential to do all of the following:

(1) Separate monopoly utility transmission functions from competitive generation functions, through development of independent, third-party control of transmission access and pricing.

(2) Permit all customers to choose from among competing suppliers of electricity.

(3) Provide customers and suppliers with open, nondiscriminatory, and comparable access to transmission and distribution services.

(l) The commission has properly concluded that:

(1) This competition will best be introduced by the creation of an Independent System Operator.

(2) Generation of electricity should be open to competition.

(3) There is a need to ensure that no participant in these new market institutions has the ability to exercise significant market power so that operation of the new market institutions would be distorted.

(4) These new market institutions should commence simultaneously with the phase-in of customer choice, and the public will be best served if these institutions and the nonbypassable transition cost recovery mechanism referred to in subdivisions (s) to (w), inclusive, are in place simultaneously and no later than January 1, 1998.

(m) It is the intention of the Legislature that California’s publicly owned electric utilities and investor-owned electric utilities should commit control of their transmission facilities to the Independent System Operator. These utilities should jointly advocate to the Federal Energy Regulatory Commission a pricing methodology for the Independent System Operator that results in an equitable return on capital investment in transmission facilities for all Independent System Operator participants.

(n) Opportunities to acquire electricity in the competitive market must be available to California consumers as soon as practicable, but no later than January 1, 1998, so that all customers can share in the benefits of competition.

(o) Under the existing regulatory framework, California’s electrical corporations were granted franchise rights to provide electricity to consumers in their service territories.

(p) Consistent with federal and state policies, California’s electrical corporations invested in power plants and entered into contractual obligations in order to provide reliable electrical service on a nondiscriminatory basis to all consumers within their service territories who requested service.

(q) The cost of these investments and contractual obligations are currently being recovered in electricity rates charged by electrical corporations to their consumers.

(r) Transmission and distribution of electricity remain essential services imbued with the public interest that are provided over facilities owned and maintained by the state’s electrical corporations.

(s) It is proper to allow electrical corporations an opportunity to continue to recover, over a reasonable transition period, those costs and categories of costs for generation-related assets and obligations, including costs associated with any subsequent renegotiation or buyout of existing generation-related contracts, that the commission, before December 20, 1995, had authorized for collection in rates and that may not be recoverable in market prices in a competitive generation market, and appropriate additions 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, if the costs are necessary to maintain those facilities through December 31, 2001. In determining the costs to be recovered, it is appropriate to net the negative value of above market assets against the positive value of below market assets.

(t) The transition to a competitive generation market should be orderly, protect electric system reliability, provide the investors in these electrical corporations with a fair opportunity to fully recover the costs associated with commission-approved generation-related assets and obligations, and be completed as expeditiously as possible.

(u) The transition to expanded customer choice, competitive markets, and performance-based ratemaking as described in Decision 95-12-063, as modified by Decision 96-01-009, of the commission, can produce hardships for employees who have dedicated their working lives to utility employment. It is preferable that any necessary reductions in the utility workforce directly caused by electrical restructuring be accomplished through offers of voluntary severance, retraining, early retirement, outplacement, and related benefits. Whether workforce reductions are voluntary or involuntary, reasonable costs associated with these sorts of benefits should be included in the competition transition charge.

(v) Charges associated with the transition should be collected over a specific period of time on a nonbypassable basis and in a manner that does not result in an increase in rates to customers of electrical corporations. In order to insulate the policy of nonbypassability against incursions, if exemptions from the competition transition charge are granted, a firewall shall be created that segregates recovery of the cost of exemptions as follows:

(1) The cost of the competition transition charge exemptions granted to members of the combined class of residential and small commercial customers shall be recovered only from those customers.

(2) The cost of the 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 those customers. The commission shall retain existing cost allocation authority provided that the firewall and rate freeze principles are not violated.

(w) It is the intent of the Legislature to require and enable electrical corporations to monetize a portion of the competition transition charge for residential and small commercial consumers so that these customers will receive rate reductions of no less than 10 percent for 1998 continuing through 2002. Electrical corporations shall, by June 1, 1997, or earlier, secure the means to finance the competition transition charge by applying concurrently for financing orders from the commission and for rate reduction bonds from the California Infrastructure and Economic Development Bank.

(x) California’s electrical corporations provide substantial benefits to all Californians, including employment and support of the state’s economy. Restructuring the electric services industry pursuant to the act that added this chapter will continue these benefits, and will also offer meaningful and immediate rate reductions for residential and small commercial customers, and facilitate competition in the supply of electricity.

331.

The definitions set forth in this section shall govern the construction of this chapter.

(a) “Aggregator” means a marketer, broker, public agency, city, county, or special district, that combines the loads of multiple end-use customers in facilitating the sale and purchase of electricity, transmission, and other services on behalf of these customers.

(b) “Broker” means an entity that arranges the sale and purchase of electricity, transmission, and other services between buyers and sellers, but does not take title to any of the electricity sold.

(c) “Direct transaction” means a contract between any one or more electric generators, marketers, or brokers of electricity and one or more retail customers providing for the purchase and sale of electricity or any ancillary services.

(d) “Fire wall” means the line of demarcation separating residential and small commercial customers from all other customers as described in subdivision (e) of Section 367.

(e) “Marketer” means an entity that buys electricity, transmission, and other services from traditional utilities and other suppliers, and then resells those services at wholesale or to an end-use customer.

(f) “Microcogeneration facility” means a cogeneration facility of less than one megawatt.

(g) “Restructuring trust” means the tax-exempt public benefit trust established by Decision 96-08-038 of the commission to provide for design and development of the hardware and software systems for the Independent System Operator and that may undertake other activities, as needed, as ordered by the commission.

(h) “Small commercial customer” means a customer that has a maximum peak demand of less than 20 kilowatts.

337.

(a) The Independent System Operator governing board shall comprise a five-member independent governing board of directors appointed by the Governor and subject to confirmation by the Senate. Any reference in this chapter or in any other provision of law to the Independent System Operator governing board means the independent governing board appointed under this subdivision.

(b) A member of the independent governing board appointed under subdivision (a) may not be affiliated with any actual or potential participant in any market administered by the Independent System Operator.

(c) (1) All appointments shall be for three-year terms.

(2) There shall not be a limit on the number of terms that may be served by any member.

(d) The Independent System Operator shall ensure that its articles of incorporation and bylaws are in accordance with this section, and shall make filings with the Federal Energy Regulatory Commission as it determines to be necessary.

(e) For purposes of the initial appointments to the Independent System Operator governing board, as provided in subdivision (a), the Governor shall appoint one member to a one-year term, two members to a two-year term, and two members to a three-year term.

341.5.

(a) The Independent System Operator bylaws shall contain provisions that identify those matters specified in subdivision (b) of Section 339, as that subdivision read on January 1, 2000, as matters within state jurisdiction. The bylaws shall also contain provisions that state that California’s bylaws approval function with respect to the matters specified in subdivision (b) of Section 339, as that subdivision read on January 1, 2000, shall not preclude the Federal Energy Regulatory Commission from taking any action necessary to address undue discrimination or other violations of the Federal Power Act (16 U.S.C. Sec. 791a et seq.) or to exercise any other commission responsibility under the Federal Power Act. In taking any such action, the Federal Energy Regulatory Commission shall give due respect to California’s jurisdictional interests in the functions of the Independent System Operator and to attempt to accommodate state interests to the extent those interests are not inconsistent with the Federal Energy Regulatory Commission’s statutory responsibilities. The bylaws shall state that any future agreement regarding the apportionment of the Independent System Operator board appointment function among participating states associated with the expansion of the Independent System Operator into a multistate entity shall be filed with the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act (16 U.S.C. Sec. 824d).

(b) Any necessary bylaw changes to implement Section 337, Sections 335, 338, and 339, as those sections read on January 1, 2002, or subdivision (a) of this section, or changes required pursuant to an agreement as contemplated by subdivision (a) with a participating state for a regional organization, shall be effective upon approval of the respective governing boards and acceptance for filing by the Federal Energy Regulatory Commission.

348.

The Independent System Operator shall adopt inspection, maintenance, repair, and replacement standards for the transmission facilities under its control on or before September 30, 1997. The standards, which shall be performance or prescriptive standards, or both, as appropriate, for each substantial type of transmission equipment or facility, shall provide for high quality, safe, and reliable service. In adopting its standards, the Independent System Operator shall consider: cost, local geography and weather, applicable codes, national electrical industry practices, sound engineering judgment, and experience. The Independent System Operator shall also adopt standards for reliability, and safety during periods of emergency and disaster. The Independent System Operator shall require each transmission facility owner or operator to report annually on its compliance with the standards. That report shall be made available to the public.

361.

The commission shall ensure that any funds secured by the restructuring trust established for the purpose of developing the Independent System Operator shall be placed at the disposal of the Independent System Operator.

365.

The actions of the commission pursuant to this chapter shall be consistent with the findings and declarations contained in Section 330. In addition, the commission shall do all of the following:

(a) Facilitate the efforts of the state’s electrical corporations to develop and obtain authorization from the Federal Energy Regulatory Commission for the creation and operation of an Independent System Operator for the determination of which transmission and distribution facilities are subject to the exclusive jurisdiction of the commission, and for approval, to the extent necessary, of the cost recovery mechanism established as provided in Sections 367 to 376, inclusive. The commission shall also participate fully in all proceedings before the Federal Energy Regulatory Commission in connection with the Independent System Operator and shall encourage the Federal Energy Regulatory Commission to adopt protocols and procedures that strengthen the reliability of the interconnected transmission grid, encourage all publicly owned utilities in California to become full participants, and maximize enforceability of those protocols and procedures by all market participants.

(b) (1) Authorize direct transactions between electricity suppliers and end use customers, subject to implementation of the nonbypassable charge referred to in Sections 367 to 376, inclusive. Direct transactions shall commence simultaneously with the start of an Independent System Operator referred to in subdivision (a). The simultaneous commencement shall occur as soon as practicable, but no later than January 1, 1998. The commission shall develop a phase-in schedule at the conclusion of which all customers shall have the right to engage in direct transactions. Any phase-in of customer eligibility for direct transactions ordered by the commission shall be equitable to all customer classes and accomplished as soon as practicable, consistent with operational and other technological considerations, and shall be completed for all customers on or before January 1, 2002.

(2) Customers shall be eligible for direct access irrespective of any direct access phase-in implemented pursuant to this section if at least one-half of that customer’s electrical load is supplied by energy from a certified renewable resource provider, provided however that nothing in this section shall provide for direct access for electricity consumers served by municipal utilities unless authorized by the governing board of that municipal utility.

367.

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, if 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 meet all of the following requirements:

(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 on or before 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 law, shall 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, if 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, and fuel and fuel transportation costs, shall be recovered solely 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 or voltage support is not yet procurable at market-based rates in locations where it is deemed needed for the reactive power or voltage support by the Independent System Operator, if the units are otherwise authorized to recover market-based rates and if for an electrical corporation that is also a gas corporation and that serves at least 4,000,000 customers as of December 20, 1995, the commission shall authorize the electrical corporation to retain any earnings from operations of the reactive power or 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 4,000,000 customers, and that was also a gas corporation that served fewer than 4,000 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 before 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 before December 31, 2001, shall include a return as provided for in commission 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.

(3) The commission shall retain existing cost allocation authority, if the firewall and rate freeze principles are not violated.

372.

(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 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 electrical 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 all of 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 purposes of this section, all onsite or over-the-fence arrangements shall be consistent with Section 218 as that section 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 electrical 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 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 finds 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 shall undertake all necessary efforts to revise, mitigate, or eliminate that policy or action of the Independent System Operator.

373.

(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, this section and Sections 372 and 374 shall apply in the event the commission authorizes a nonbypassable charge before the implementation of an Independent System Operator referred to in subdivision (a) of Section 365.

376.

To the extent that the costs of programs to accommodate implementation of direct access 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 reimburses the electrical corporation for the costs of any of these programs.

390.

(a) Subject to applicable contractual terms, energy prices paid to nonutility power generators by an electrical corporation based on the commission’s prescribed “short run avoided cost energy methodology” shall be determined as set forth in subdivision (b).

(b) Short run avoided cost energy payments paid to nonutility power generators by an electrical corporation shall be based on a formula that reflects a starting energy price, adjusted monthly to reflect changes in a starting gas index price in relation to an average of current California natural gas border price indices. The starting energy price shall be based on 12-month averages of recent, pre-January 1, 1996, short-run avoided energy prices paid by each electrical corporation to nonutility power generators. The starting gas index price shall be established as an average of index gas prices for the same annual periods.

(c) Short-run avoided energy cost payments made pursuant to this section are in addition to contractually specified capacity payments. This section does not affect, modify, or amend the terms and conditions of existing nonutility power generators’ contracts with respect to the sale of energy or capacity or otherwise.

(d) This section does not limit the level of transition cost recovery provided to utilities under electric industry restructuring policies established by the commission.

(e) (1) The term “going forward costs” shall include, but not be limited to, all costs associated with fuel transportation and fuel supply, administrative and general, and operation and maintenance.

(2) The following shall not be considered “going forward costs”:

(A) Commission-approved capital costs for capital additions to fossil-fueled powerplants, if such additions are necessary for the continued operation of the powerplants used to meet load and such additions are not undertaken primarily to expand, repower, or enhance the efficiency of plant operations.

(B) Commission-approved operating costs for particular utility-owned powerplant units and at particular times when reactive power or voltage support is not yet procurable at market-based rates in locations where it is needed, if the recovery shall end on December 31, 2001.

464.

(a) Reasonable expenditures by transmission owners that are electrical corporations to plan, design, and engineer reconfiguration, replacement, or expansion of transmission facilities are in the public interest and are deemed prudent if made for purposes of facilitating competition in electricity generation markets, ensuring open access and comparable service, or maintaining or enhancing reliability, whether or not these expenditures are for transmission facilities that become operational.

(b) The commission shall facilitate the efforts of the state’s transmission owning electrical corporations to obtain authorization from the Federal Energy Regulatory Commission to recover reasonable expenditures made for the purposes stated in subdivision (a).

(c) This section does not alter or affect the recovery of the reasonable costs of other electrical facilities in rates pursuant to the commission’s existing ratemaking authority under this code or pursuant to the Federal Power Act (41 Stat. 1063; 16 U.S.C. Sec. 791a, et seq.). The commission may periodically review and adjust depreciation schedules and rates authorized for an electric plant that is under the jurisdiction of the commission and owned by an electrical corporation and periodically review and adjust depreciation schedules and rates authorized for a gas plant that is under the jurisdiction of the commission and owned by a gas corporation, consistent with this code.

739.12.

(a) The commission shall continue a program of assistance to residential customers of the state’s three largest electrical corporations consisting of households with total household annual gross income levels between 200 percent and 250 percent of the federal poverty guideline level. The program shall continue to be referred to as the Family Electric Rate Assistance or FERA program.

(b) The FERA program discount shall be an 18-percent line-item discount applied to an eligible customer’s bill calculated at the applicable rate for the billing period.

(c) The commission shall authorize the state’s three largest electrical corporations to increase or expand marketing and outreach efforts beyond those in effect as of December 31, 2018, to increase eligible customer participation in the FERA program.

(d) (1) The commission, on or before March 1, 2025, and on or before May 1 each year thereafter, shall require the state’s three largest electrical corporations to report on their efforts to enroll customers in the FERA program.

(2) The commission, on or before June 1, 2025, and on or before December 1 each year thereafter, shall review each electrical corporation’s report to ensure it has made reasonable efforts to enroll eligible households in the FERA program commensurate with the proportion of households the commission determines to be eligible within the electrical corporation’s service territory.

(3) If the commission, in its review of an electrical corporation’s report, determines the electrical corporation has not made reasonable efforts to enroll eligible households in the FERA program commensurate with the proportion of households the commission determines to be eligible within the electrical corporation’s service territory, the commission shall require the electrical corporation to develop a strategy and plan to sufficiently enroll eligible households within three years of the adoption of the strategy and plan.

(4) An electrical corporation may market enrollment for the FERA program separately from the CARE program and provide a separate FERA program-only application form.

2778.

(a) An electrical cooperative is subject to a provision of the Public Utilities Act (Part 1 (commencing with Section 201)) only if the provision expressly provides that it applies to an electrical cooperative.

(b) Subdivision (a) is applicable only to a provision of the Public Utilities Act (Part 1 (commencing with Section 201)) that becomes effective after January 1, 2027.