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SB-38 Electrical restructuring.(2013-2014)

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SB38:v94#DOCUMENT

Amended  IN  Assembly  August 19, 2014
Amended  IN  Assembly  August 06, 2013
Amended  IN  Assembly  June 27, 2013
Amended  IN  Senate  May 24, 2013
Amended  IN  Senate  April 11, 2013

CALIFORNIA LEGISLATURE— 2013–2014 REGULAR SESSION

Senate Bill No. 38


Introduced by Senator De León Padilla

December 05, 2012


An act to add Section 30009 to the Penal Code, relating to firearms. amend Sections 63010, 63025.1, 63041.5, 63043, 63048.3, 63048.56, 63048.7, 63049.2, 63049.62, 63049.64, 63049.67, and 63071 of, and to repeal Article 4 (commencing with Section 63042) of Chapter 2 of Division 1 of Title 6.7 of, the Government Code, to amend Sections 331, 332.1, 341.5, 348, 349.5, 359, 365, 368, 369, 370, 371, 372, 374, 379, 394.5, 395, 399.2, 2827, 9600, and 9607 of, to repeal Sections 330, 350, 355, 356, 361, 363, 367, 367.7, 368.5, 373, 374.5, 375, 376, 390, 390.1, and 397 of, and to repeal Article 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of Division 1 of, the Public Utilities Code, and to amend Section 31071.5 of the Streets and Highways Code, relating to electricity.


LEGISLATIVE COUNSEL'S DIGEST


SB 38, as amended, De León Padilla. Firearms: prohibited persons. Electrical restructuring.
The existing restructuring of the electrical industry within the Public Utilities Act provides for the establishment of an Independent System Operator and a Power Exchange as nonprofit public benefit corporations. Existing law requires the Independent System Operator, within 6 months after receiving approval for its operation by the Federal Energy Regulatory Commission, to provide a report to the Legislature and the Electricity Oversight Board containing specified matter.
This bill would repeal this reporting requirement, and would abolish the Power Exchange.
Electrical restructuring makes legislative findings and declarations in order to provide guidance to the Public Utilities Commission in carrying out restructuring.
This bill repeals those legislative findings and declarations.
Electrical restructuring states the intent of the Legislature that individual customers not experience rate increases as a result of the allocation of transition costs, as specified, and requires the Public Utilities Commission to implement a methodology for calculating certain Power Exchange energy credits.
This bill would repeal this provision.
Electrical restructuring required the commission to identify and determine those costs and categories of costs for generation-related assets and obligations that were being collected in commission-approved rates on December 20, 1995, that might become uneconomic as a result of a competitive generation market. Electrical restructuring requires each electrical corporation to 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, requires that the plan contain specified matter, and requires that the plan 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 be reduced so that these customers receive rate reductions of no less than 10% for 1998 continuing through 2002. Electrical restructuring prohibits the commission, upon the termination of the 10% rate reduction for residential and small commercial customers, from subjecting those residential and small commercial customers to any rate increase or future rate obligations solely as a result of the termination of the 10% rate reduction. Electrical restructuring authorizes an electrical corporation to apply to the commission for a determination that certain transition costs, as defined, may be recovered through fixed transition amounts, which constitute transition property, as defined, and provides, until December 31, 2015, for the issuance of financing orders by the commission, and provides for the issuance of rate reduction bonds utilizing the California Infrastructure and Economic Development Bank, to be repaid out of rates.
This bill would repeal these provisions.
Electrical restructuring requires the commission to establish an effective mechanism that ensures recovery of specified transition costs from all existing and future consumers in the service territory in which the utility provided electricity services as of December 20, 1995, except 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.
This bill would provide that competition transition charges that are authorized by the commission prior to January 1, 2015, continue to apply to all existing and future consumers in the service territory in which the utility provided electricity services as of December 20, 1995, subject to the exception described above.
Electrical restructuring directed the commission to authorize direct transactions between electricity suppliers and end-use customers, subject to implementation of nonbypassable charges, as specified. Other provisions reference these charges as a nonbypassable charge, while other provisions reference these charges as an obligation to pay uneconomic costs, as specified.
This bill would replace the various references to the specified statutory charges with “competition transition charges.”
Electrical restructuring requires any electrical corporation serving agricultural customers with multiple meters to conduct research based on a statistically valid sample of those customers and meters to determine the typical simultaneous peak load of those customers and to report the results to those customers and the commission by July 1, 2001. Electrical restructuring requires the commission to consider the research results in setting future electrical distribution rates for those customers.
This bill would repeal this provision.
Electrical restructuring requires the commission to allow recovery of reasonable employee related transition costs incurred and projected for severance, retraining, early retirement, outplacement, and related expenses for the employees in order to mitigate potential negative impacts on utility personnel directly affected by restructuring.
This bill would repeal this provision.
Existing law requires, for an electric generating facility sold by an electrical corporation in a transaction initiated prior to December 31, 2001, and approved by the commission by December 31, 2002, that the selling utility contract with the purchaser for the selling utility, an affiliate, or a successor corporation to operate and maintain the facility for at least 2 years, and authorizes the commission to require these conditions for transactions initiated on or after January 1, 2002.
This bill would repeal this provision.
Existing law, enacted as part of restructuring, prescribes how energy prices paid to nonutility electrical generators, known as qualifying facilities under federal law, by an electrical corporation based on the commission’s “short run avoided cost energy methodology” are to be determined, subject to applicable contractual terms. Existing law authorizes a nonutility electrical generator using renewable fuels that entered into a contract with an electrical corporation prior to December 31, 2001, specifying fixed energy prices for 5 years of electrical output to negotiate a contract of an additional 5 years of fixed energy payments upon expiration of the initial 5-year term, at a price to be determined by the commission.
This bill would repeal this provision.
This bill would repeal a provision authorizing an electrical corporation that was also a gas corporation that served fewer than 4,000,000 customers as of December 20, 1995, to file a rate cap mechanism that includes a Fuel Price Index Mechanism, as specified, which authorization became inoperative on December 31, 2001.
This bill would strike references to these repealed statutes.

Existing law requires the Attorney General to establish and maintain an online database, known as the Prohibited Armed Persons File, to cross-reference persons who have ownership or possession of a firearm and who, subsequent to the date of that ownership or possession, became a person who is prohibited from owning or possessing a firearm.

This bill would, no later than January 1, 2015, require the Department of Justice to establish a 30-day amnesty period during which a person prohibited from possessing a firearm may surrender his or her firearms to a local law enforcement agency without being charged with illegal possession of a firearm, except as specified. The bill would require the department to provide written notification of the amnesty period to prohibited persons who are eligible to participate in the amnesty period, and would require the notification to include certain information. The bill would require a local law enforcement agency that receives a firearm from a prohibited person during the amnesty period to report specified information to the department and to sell or destroy surrendered firearms, as provided. The bill would require the department to use the specified information provided by the local law enforcement agency to create a record of each surrendered firearm in the Prohibited Armed Persons File. The bill would also impose a civil fine of up to $2,500 per firearm on a person prohibited from possessing a firearm and who is eligible for the amnesty program who still maintains possession of his or her firearm after the amnesty period. The bill would specify that a prohibited person shall not be charged with illegal possession of a firearm, nor be subject to the fine, if he or she provides evidence satisfactory to the department that he or she lawfully surrendered his or her firearm prior to the commencement of the amnesty period. Because this bill would impose additional duties on local law enforcement agencies, this bill would create a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that, if the Commission on State Mandates determines that the bill contains costs mandated by the state, reimbursement for those costs shall be made pursuant to these statutory provisions.

Vote: MAJORITY   Appropriation: NO   Fiscal Committee: YES   Local Program: YESNO  

The people of the State of California do enact as follows:


SECTION 1.

 Section 63010 of the Government Code is amended to read:

63010.
 For purposes of this division, the following words and terms shall have the following meanings unless the context clearly indicates or requires another or different meaning or intent:
(a) “Act” means the Bergeson-Peace Infrastructure and Economic Development Bank Act.
(b) “Bank” means the California Infrastructure and Economic Development Bank.
(c) “Board” or “bank board” means the Board of Directors of the California Infrastructure and Economic Development Bank.
(d) “Bond purchase agreement” means a contractual agreement executed between the bank and a sponsor, or a special purpose trust authorized by the bank or a sponsor, or both, whereby the bank or special purpose trust authorized by the bank agrees to purchase bonds of the sponsor for retention or sale.
(e) “Bonds” means bonds, including structured, senior, and subordinated bonds or other securities; loans; notes, including bond, revenue, tax, or grant anticipation notes; commercial paper; floating rate and variable maturity securities; and any other evidences of indebtedness or ownership, indebtedness including certificates of participation or beneficial interest, asset backed certificates, or lease-purchase or installment purchase agreements, whether taxable or excludable from gross income for federal income taxation purposes.
(f) “Cost,” as applied to a project or portion thereof financed under this division, means all or any part of the cost of construction, renovation, and acquisition of all lands, structures, real or personal property, rights, rights-of-way, franchises, licenses, easements, and interests acquired or used for a project; the cost of demolishing or removing any buildings or structures on land so acquired, including the cost of acquiring any lands to which the buildings or structures may be moved; the cost of all machinery, equipment, and financing charges; interest prior to, during, and for a period after completion of construction, renovation, or acquisition, as determined by the bank; provisions for working capital; reserves for principal and interest and for extensions, enlargements, additions, replacements, renovations, and improvements; and the cost of architectural, engineering, financial and legal services, plans, specifications, estimates, administrative expenses, and other expenses necessary or incidental to determining the feasibility of any project or incidental to the construction, acquisition, or financing of any project, and transition costs in the case of an electrical corporation. project.
(g) “Economic development facilities” means real and personal property, structures, buildings, equipment, and supporting components thereof that are used to provide industrial, recreational, research, commercial, utility, or service enterprise facilities, community, educational, cultural, or social welfare facilities and any parts or combinations thereof, and all facilities or infrastructure necessary or desirable in connection therewith, including provision for working capital, but shall not include any housing.
(h) “Electrical corporation” has the meaning set forth in Section 218 of the Public Utilities Code.
(i) “Executive director” means the Executive Director of the California Infrastructure and Economic Development Bank appointed pursuant to Section 63021.
(j) “Financial assistance” in connection with a project, includes, but is not limited to, any combination of grants, loans, the proceeds of bonds issued by the bank or special purpose trust, insurance, guarantees or other credit enhancements or liquidity facilities, and contributions of money, property, labor, or other things of value, as may be approved by resolution of the board or the sponsor, or both; the purchase or retention of bank bonds, the bonds of a sponsor for their retention or for sale by the bank, or the issuance of bank bonds or the bonds of a special purpose trust used to fund the cost of a project for which a sponsor is directly or indirectly liable, including, but not limited to, bonds, the security for which is provided in whole or in part pursuant to the powers granted by Section 63025; bonds for which the bank has provided a guarantee or enhancement, including, but not limited to, the purchase of the subordinated bonds of the sponsor, the subordinated bonds of a special purpose trust, or the retention of the subordinated bonds of the bank pursuant to Chapter 4 (commencing with Section 63060); or any other type of assistance deemed appropriate by the bank or the sponsor, except that no direct loans shall be made to nonpublic entities other than in connection with the issuance of rate reduction bonds pursuant to a financing order or in connection with a financing for an economic development facility.
For purposes of this subdivision, “grant” does not include grants made by the bank except when acting as an agent or intermediary for the distribution or packaging of financing available from federal, private, or other public sources.

(k)“Financing order” has the meaning set forth in Section 840 of the Public Utilities Code.

(l)

(k) “Guarantee trust fund” means the California Infrastructure Guarantee Trust Fund.

(m)

(l) “Infrastructure bank fund” means the California Infrastructure and Economic Development Bank Fund.

(n)

(m) “Loan agreement” means a contractual agreement executed between the bank or a special purpose trust and a sponsor that provides that the bank or special purpose trust will loan funds to the sponsor and that the sponsor will repay the principal and pay the interest and redemption premium, if any, on the loan.

(o)

(n) “Participating party” means any person, company, corporation, association, state or municipal governmental entity, partnership, firm, or other entity or group of entities, whether organized for profit or not for profit, engaged in business or operations within the state and that applies for financing from the bank in conjunction with a sponsor for the purpose of implementing a project. However, in the case of a project relating to the financing of transition costs or the acquisition of transition property, or both, on the request of an electrical corporation, or in connection with a financing for an economic development facility, or for the financing of insurance claims, the participating party shall be deemed to be the same entity as the sponsor for the financing.

(p)

(o) “Project” means designing, acquiring, planning, permitting, entitling, constructing, improving, extending, restoring, financing, and generally developing public development facilities or economic development facilities within the state or financing transition costs or the acquisition of transition property, or both, upon approval of a financing order by the Public Utilities Commission, as provided in Article 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of Division 1 of the Public Utilities Code. state.

(q)

(p) “Public development facilities” means real and personal property, structures, conveyances, equipment, thoroughfares, buildings, and supporting components thereof, excluding any housing, that are directly related to providing the following:
(1) “City streets” including any street, avenue, boulevard, road, parkway, drive, or other way that is any of the following:
(A) An existing municipal roadway.
(B) Is shown upon a plat approved pursuant to law and includes the land between the street lines, whether improved or unimproved, and may comprise pavement, bridges, shoulders, gutters, curbs, guardrails, sidewalks, parking areas, benches, fountains, plantings, lighting systems, and other areas within the street lines, as well as equipment and facilities used in the cleaning, grading, clearance, maintenance, and upkeep thereof.
(2) “County highways” including any county highway as defined in Section 25 of the Streets and Highways Code, that includes the land between the highway lines, whether improved or unimproved, and may comprise pavement, bridges, shoulders, gutters, curbs, guardrails, sidewalks, parking areas, benches, fountains, plantings, lighting systems, and other areas within the street lines, as well as equipment and facilities used in the cleaning, grading, clearance, maintenance, and upkeep thereof.
(3) “Drainage, water supply, and flood control” including, but not limited to, ditches, canals, levees, pumps, dams, conduits, pipes, storm sewers, and dikes necessary to keep or direct water away from people, equipment, buildings, and other protected areas as may be established by lawful authority, as well as the acquisition, improvement, maintenance, and management of floodplain areas and all equipment used in the maintenance and operation of the foregoing.
(4) “Educational facilities” including libraries, child care facilities, including, but not limited to, day care facilities, and employment training facilities.
(5) “Environmental mitigation measures” including required construction or modification of public infrastructure and purchase and installation of pollution control and noise abatement equipment.
(6) “Parks and recreational facilities” including local parks, recreational property and equipment, parkways and property.
(7) “Port facilities” including docks, harbors, ports of entry, piers, ships, small boat harbors and marinas, and any other facilities, additions, or improvements in connection therewith.
(8) “Power and communications” including facilities for the transmission or distribution of electrical energy, natural gas, and telephone and telecommunications service.
(9) “Public transit” including air and rail transport of goods, airports, guideways, vehicles, rights-of-way, passenger stations, maintenance and storage yards, and related structures, including public parking facilities, equipment used to provide or enhance transportation by bus, rail, ferry, or other conveyance, either publicly or privately owned, that provides to the public general or special service on a regular and continuing basis.
(10) “Sewage collection and treatment” including pipes, pumps, and conduits that collect wastewater from residential, manufacturing, and commercial establishments, the equipment, structures, and facilities used in treating wastewater to reduce or eliminate impurities or contaminants, and the facilities used in disposing of, or transporting, remaining sludge, as well as all equipment used in the maintenance and operation of the foregoing.
(11) “Solid waste collection and disposal” including vehicles, vehicle-compatible waste receptacles, transfer stations, recycling centers, sanitary landfills, and waste conversion facilities necessary to remove solid waste, except that which is hazardous as defined by law, from its point of origin.
(12) “Water treatment and distribution” including facilities in which water is purified and otherwise treated to meet residential, manufacturing, or commercial purposes and the conduits, pipes, and pumps that transport it to places of use.
(13) “Defense conversion” including, but not limited to, facilities necessary for successfully converting military bases consistent with an adopted base reuse plan.
(14) “Public safety facilities” including, but not limited to, police stations, fire stations, court buildings, jails, juvenile halls, and juvenile detention facilities.
(15) “State highways” including any state highway as described in Chapter 2 (commencing with Section 230) of Division 1 of the Streets and Highways Code, and the related components necessary for safe operation of the highway.
(16) (A) Military infrastructure, including, but not limited to, facilities on or near a military installation, that enhance the military operations and mission of one or more military installations in this state. To be eligible for funding, the project shall be endorsed by the Office of Military and Aerospace Support established pursuant to Section 13998.2.
(B) For purposes of this subdivision, “military installation” means any facility under the jurisdiction of the United States Department of Defense, as defined in paragraph (1) of subsection (e) of Section 2687 of Title 10 of the United States Code.

(r)“Rate reduction bonds” has the meaning set forth in Section 840 of the Public Utilities Code.

(s)

(q) “Revenues” means all receipts, purchase payments, loan repayments, lease payments, and all other income or receipts derived by the bank or a sponsor from the sale, lease, or other financing arrangement undertaken by the bank, a sponsor or a participating party, including, but not limited to, all receipts from a bond purchase agreement, and any income or revenue derived from the investment of any money in any fund or account of the bank or a sponsor and any receipts derived from transition property. sponsor. Revenues shall not include moneys in the General Fund of the state.

(t)

(r) “Special purpose trust” means a trust, partnership, limited partnership, association, corporation, nonprofit corporation, or other entity authorized under the laws of the state to serve as an instrumentality of the state to accomplish public purposes and authorized by the bank to acquire, by purchase or otherwise, for retention or sale, the bonds of a sponsor or of the bank made or entered into pursuant to this division and to issue special purpose trust bonds or other obligations secured by these bonds or other sources of public or private revenues. Special purpose trust also means any entity authorized by the bank to acquire transition property or to issue rate reduction bonds, or both, subject to the approvals by the bank and powers of the bank as are provided by the bank in its resolution authorizing the entity to issue rate reduction bonds.

(u)

(s) “Sponsor” means any subdivision of the state or local government including departments, agencies, commissions, cities, counties, nonprofit corporations formed on behalf of a sponsor, special districts, assessment districts, and joint powers authorities within the state or any combination of these subdivisions that makes an application to the bank for financial assistance in connection with a project in a manner prescribed by the bank. This definition shall not be construed to require that an applicant have an ownership interest in the project. In addition, an electrical corporation shall be deemed to be the sponsor as well as the participating party for any project relating to the financing of transition costs and the acquisition of transition property on the request of the electrical corporation and any person, company, corporation, partnership, firm, or other entity or group engaged in business or operation within the state that applies for financing of any economic development facility, shall be deemed to be the sponsor as well as the participating party for the project relating to the financing of that economic development facility.

(v)

(t) “State” means the State of California.

(w)“Transition costs” has the meaning set forth in Section 840 of the Public Utilities Code.

(x)“Transition property” has the meaning set forth in Section 840 of the Public Utilities Code.

SEC. 2.

 Section 63025.1 of the Government Code is amended to read:

63025.1.
 The bank board may do or delegate the following to the executive director:
(a) Sue and be sued in its own name.
(b) As provided in Chapter 5 (commencing with Section 63070), issue bonds and authorize special purpose trusts to issue bonds, including, at the option of the board, bonds bearing interest that is taxable for the purpose of federal income taxation, or borrow money to pay all or any part of the cost of any project, or to otherwise carry out the purposes of this division.
(c) Engage the services of private consultants to render professional and technical assistance and advice in carrying out the purposes of this division.
(d) Employ attorneys, financial consultants, and other advisers as may, in the bank’s judgment, be necessary in connection with the issuance and sale, or authorization of special purpose trusts for the issuance and sale, of any bonds, notwithstanding Sections 11042 and 11043.
(e) Contract for engineering, architectural, accounting, or other services of appropriate state agencies as may, in its judgment, be necessary for the successful development of a project.
(f) Pay the reasonable costs of consulting engineers, architects, accountants, and construction, land use, recreation, and environmental experts employed by any sponsor or participating party if, in the bank’s judgment, those services are necessary for the successful development of a project.
(g) Acquire, take title to, and sell by installment sale or otherwise, lands, structures, real or personal property, rights, rights-of-way, franchises, easements, and other interests in lands that are located within the state, or transition property as the bank may deem necessary or convenient for the financing of the project, upon terms and conditions that it considers to be reasonable.
(h) Receive and accept from any source including, but not limited to, the federal government, the state, or any agency thereof, loans, contributions, or grants, in money, property, labor, or other things of value, for, or in aid of, a project, or any portion thereof.
(i) Make loans to any sponsor or participating party, either directly or by making a loan to a lending institution, in connection with the financing of a project in accordance with an agreement between the bank and the sponsor or a participating party, either as a sole lender or in participation with other lenders. However, no loan shall exceed the total cost of the project as determined by the sponsor or the participating party and approved by the bank.
(j) Make loans to any sponsor or participating party, either directly or by making a loan to a lending institution, in accordance with an agreement between the bank and the sponsor or participating party to refinance indebtedness incurred by the sponsor or participating party in connection with projects undertaken and completed prior to any agreement with the bank or expectation that the bank would provide financing, either as a sole lender or in participation with other lenders.
(k) Mortgage all or any portion of the bank’s interest in a project and the property on which any project is located, whether owned or thereafter acquired, including the granting of a security interest in any property, tangible or intangible.
(l) Assign or pledge all or any portion of the bank’s interests in transition property and the revenues therefrom, or assets, things of value, mortgages, deeds of trust, bonds, bond purchase agreements, loan agreements, indentures of mortgage or trust, or similar instruments, notes, and security interests in property, tangible or intangible and the revenues therefrom, of a sponsor or a participating party to which the bank has made loans, and the revenues therefrom, including payment or income from any interest owned or held by the bank, for the benefit of the holders of bonds.
(m) Make, receive, or serve as a conduit for the making of, or otherwise provide for, grants, contributions, guarantees, insurance, credit enhancements or liquidity facilities, or other financial enhancements to a sponsor or a participating party as financial assistance for a project.
(n) Lease the project being financed to a sponsor or a participating party, upon terms and conditions that the bank deems proper but shall not be leased at a loss; charge and collect rents therefor; terminate any lease upon the failure of the lessee to comply with any of the obligations thereof; include in any lease, if desired, provisions that the lessee shall have options to renew the lease for a period or periods, and at rents determined by the bank; purchase any or all of the project; or, upon payment of all the indebtedness incurred by the bank for the financing of the project, the bank may convey any or all of the project to the lessee or lessees.
(o) Charge and equitably apportion among sponsors and participating parties the bank’s administrative costs and expenses incurred in the exercise of the powers and duties conferred by this division.
(p) Issue, obtain, or aid in obtaining, from any department or agency of the United States, from other agencies of the state, or from any private company, any insurance or guarantee to, or for, the payment or repayment of interest or principal, or both, or any part thereof, on any loan, lease, or obligation or any instrument evidencing or securing the same, made or entered into pursuant to this division.
(q) Notwithstanding any other provision of this division, enter into any agreement, contract, or any other instrument with respect to any insurance or guarantee; accept payment in the manner and form as provided therein in the event of default by a sponsor or a participating party; and issue or assign any insurance or guarantee as security for the bank’s bonds.
(r) Enter into any agreement or contract, execute any instrument, and perform any act or thing necessary or convenient to, directly or indirectly, secure the bank’s bonds, the bonds issued by a special purpose trust, or a sponsor’s obligations to the bank or to a special purpose trust, including, but not limited to, bonds of a sponsor purchased by the bank or a special purpose trust for retention or sale, with funds or moneys that are legally available and that are due or payable to the sponsor by reason of any grant, allocation, apportionment or appropriation of the state or agencies thereof, to the extent that the Controller shall be the custodian at any time of these funds or moneys, or with funds or moneys that are or will be legally available to the sponsor, the bank, or the state or any agencies thereof by reason of any grant, allocation, apportionment, or appropriation of the federal government or agencies thereof; and in the event of written notice that the sponsor has not paid or is in default on its obligations to the bank or a special purpose trust, direct the Controller to withhold payment of those funds or moneys from the sponsor over which it is or will be custodian and to pay the same to the bank or special purpose trust or their assignee, or direct the state or any agencies thereof to which any grant, allocation, apportionment, or appropriation of the federal government or agencies thereof is or will be legally available to pay the same upon receipt by the bank or special purpose trust or their assignee, until the default has been cured and the amounts then due and unpaid have been paid to the bank or special purpose trust or their assignee, or until arrangements satisfactory to the bank or special purpose trust have been made to cure the default.
(s) Enter into any agreement or contract, execute any instrument, and perform any act or thing necessary, convenient, or appropriate to carry out any power expressly given to the bank by this division, including, but not limited to, agreements for the sale of all or any part, including principal, interest, redemption rights, or any other rights or obligations, of bonds of the bank or of a special purpose trust, liquidity agreements, contracts commonly known as interest rate swap agreements, forward payment conversion agreements, futures or contracts providing for payments based on levels of, or changes in, interest rates or currency exchange rates, or contracts to exchange cash-flows or a series of payments, or contracts, including options, puts or calls to hedge payments, rate, spread, currency exchange, or similar exposure, or any other financial instrument commonly known as a structured financial product.
(t) Purchase, with the proceeds of the bank’s bonds, transition property or bonds issued by, or for the benefit of, any sponsor in connection with a project, pursuant to a bond purchase agreement or otherwise. Bonds or transition property purchased pursuant to this division may be held by the bank, pledged or assigned by the bank, or sold to public or private purchasers at public or negotiated sale, in whole or in part, separately or together with other bonds issued by the bank, and notwithstanding any other provision of law, may be bought by the bank at private sale.
(u) Enter into purchase and sale agreements with all entities, public and private, including state and local government pension funds, with respect to the sale or purchase of bonds or transition property. bonds.
(v) Invest any moneys held in reserve or sinking funds, or any moneys not required for immediate use or disbursement, in obligations that are authorized by law for the investment of trust funds in the custody of the Treasurer.
(w) Authorize a special purpose trust or trusts to purchase or retain, with the proceeds of the bonds of a special purpose trust, transition property or bonds issued by, or for the benefit of, any sponsor in connection with a project or issued by the bank or a special purpose trust, pursuant to a bond purchase agreement or otherwise. Bonds or transition property purchased pursuant to this title may be held by a special purpose entity, pledged or assigned by a special purpose entity, or sold to public or private purchasers at public or negotiated sale, in whole or in part, with or without structuring, subordination, or credit enhancement, separately or together with other bonds issued by a special purpose trust, and notwithstanding any other provision of law, may be bought by the bank or by a special purpose trust at private sale.
(x) Approve the issuance of any bonds, notes, or other evidences of indebtedness by the Rural Economic Development Infrastructure Panel, established pursuant to Section 15373.7.

(y)Approve the issuance of rate reduction bonds by an entity other than the bank or a special purpose trust to acquire transition property upon approval of the transaction in a financing order by the Public Utilities Commission, as provided in Article 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of Division 1 of the Public Utilities Code.

(z)

(y) Apply for and accept subventions, grants, loans, advances, and contributions from any source of money, property, labor, or other things of value. The sources may include bond proceeds, dedicated taxes, state appropriations, federal appropriations, federal grant and loan funds, public and private sector retirement system funds, and proceeds of loans from the Pooled Money Investment Account.

(aa)

(z) Do all things necessary and convenient to carry out its purposes and exercise its powers, provided, however, that nothing herein shall be construed to authorize the bank to engage directly in the business of a manufacturing, industrial, real estate development, or nongovernmental service enterprise. Further, the bank shall not be organized to accept deposits of money for time or demand deposits or to constitute a bank or trust company.

SEC. 3.

 Section 63041.5 of the Government Code is amended to read:

63041.5.
 (a) It is the intent of the Legislature to provide a one-time appropriation for financial assistance to local government to meet capital outlay and infrastructure needs.
(b) From the funds appropriated in Item 2920-111-0001 of the Budget Act of 1999, the sum of four hundred twenty-five million dollars ($425,000,000) shall be available for financial assistance, including, but not limited to, leveraged revolving fund loans, to local government sponsors for public development facilities, as specified in subdivision (q) (p) of Section 63010 of the Government Code.
(c) From the funds appropriated in Item 2920-111-0001 of the Budget Act of 1999 and in Item 2920-111-0001 of the Budget Act of 1998 (Chapter 324 of the Statutes of (Ch. 324, Stats. 1998), the California Infrastructure and Economic Development Bank shall make no single loan in excess of 10 percent of the combined amount of these appropriations to the bank unless approved by unanimous consent of the membership of the Board of Directors of the California Infrastructure and Economic Development Bank and the Director of Finance provides a 30-day written notice to the Chairperson and Vice-Chairperson of the Joint Legislative Budget Committee.

SEC. 4.

 Article 4 (commencing with Section 63042) of Chapter 2 of Division 1 of Title 6.7 of the Government Code is repealed.

SEC. 5.

 Section 63043 of the Government Code is amended to read:

63043.
 Notwithstanding any other provision of this division, Article 3 (commencing with Section 63040) and Article 4 (commencing with Section 63042), shall not apply to any conduit financing for economic development facilities by the bank directly for the benefit of a participating party.

SEC. 6.

 Section 63048.3 of the Government Code is amended to read:

63048.3.
 Notwithstanding any other provision of this division, Article 3 (commencing with Section 63040), Article 4 (commencing with Article 63042), 63040) and Article 5 (commencing with Section 63043) do not apply to any financing provided by the bank to, or at the request of, the board in connection with the revolving fund.

SEC. 7.

 Section 63048.56 of the Government Code is amended to read:

63048.56.
 Notwithstanding any other law, Article 3 (commencing with Section 63040), Article 4 (commencing with Section 63042), 63040) and Article 5 (commencing with Section 63043) shall not apply to any financing provided by the bank to, or at the request of, the department in connection with the revolving fund.

SEC. 8.

 Section 63048.7 of the Government Code is amended to read:

63048.7.
 Notwithstanding any other provision of this division, Article 3 (commencing with Section 63040), Article 4 (commencing with Section 63042), 63040) and Article 5 (commencing with Section 63043) do not apply to any bonds issued by the special purpose trust established by this article. All matters authorized in this article are in addition to powers granted to the bank in this division.

SEC. 9.

 Section 63049.2 of the Government Code is amended to read:

63049.2.
 Notwithstanding any other provision of this division, Article 3 (commencing with Section 63040), Article 4 (commencing with Section 63042), 63040) and Article 5 (commencing with Section 63043) do not apply to any bonds issued by the special purpose trust established by this article. All matters authorized in this article are in addition to powers granted to the bank in this division.

SEC. 10.

 Section 63049.62 of the Government Code is amended to read:

63049.62.
 Notwithstanding any other provision of this division, a financing of the costs of claims of insolvent insurers upon the request of the association pursuant to Section 1063.73 of the Insurance Code shall be deemed to be in the public interest and eligible for financing by the bank, and Article 3 (commencing with Section 63040), Article 4 (commencing with Section 63042), Article 5 (commencing with Section 63043), Article 6 (commencing with Section 63048), and Article 7 (commencing with Section 63049) shall not apply to the financing provided by the bank to, or at the request of, the association or the department in connection with the fund. Notwithstanding any other provision of this division, the bank shall have no authority over any matter that is subject to the approval of the Insurance Commissioner under Article 14.2 (commencing with Section 1063) of Chapter 1 of Part 2 of Division 1 of the Insurance Code.

SEC. 11.

 Section 63049.64 of the Government Code is amended to read:

63049.64.
 (a) The bank may issue bonds pursuant to Chapter 5 (commencing with Section 63070) and may loan the proceeds thereof to the association, and deposit the proceeds into a separate account in the fund, or use the proceeds to refund bonds previously issued under this article. Bond proceeds may also be used to fund necessary reserves, capitalized interest, credit enhancement costs, or costs of issuance.
(b) Bonds issued under this article shall not be deemed to constitute a debt or liability of the state or of any political subdivision thereof, other than the bank, or a pledge of the faith and credit of the state or of any political subdivision, but shall be payable solely from the fund and other revenues and assets securing the bonds. All bonds issued under this article shall contain on the face of the bonds a statement to that effect.
(c) For purposes of this article, the term “project,” as defined in subdivision (p) (o) of Section 63010, shall include financing of the costs of claims of insolvent workers’ compensation insurers, in an amount (together with associated costs of financing) that may be determined by the association in making a request for financing to the bank.

SEC. 12.

 Section 63049.67 of the Government Code is amended to read:

63049.67.
 (a) Notwithstanding any other provision of this division, a financing of emergency apportionments upon the request of a school district pursuant to Article 2.7 (commencing with Section 41329.50) of Chapter 3 of Part 24 of Division 3 of Title 2 of the Education Code, is deemed to be in the public interest and eligible for financing by the bank. Article 3 (commencing with Section 63040), Article 4 (commencing with Section 63042), 63040) and Article 5 (commencing with Section 63043) do not apply to the financing provided by the bank in connection with an emergency apportionment.
(b) The bank may issue bonds pursuant to Chapter 5 (commencing with Section 63070) and provide the proceeds to a school district pursuant to a lease agreement. The proceeds may be used as an emergency apportionment, to reimburse the interim emergency apportionment from the General Fund authorized pursuant to subdivision (b) of Section 41329.52 of the Education Code, or to refund bonds previously issued under this section. Bond proceeds may also be used to fund necessary reserves, capitalized interest, credit enhancement costs, and costs of issuance.
(c) Bonds issued under this article are not deemed to constitute a debt or liability of the state or of any political subdivision of the state, other than a limited obligation of the bank, or a pledge of the faith and credit of the state or of any political subdivision. All bonds issued under this article shall contain on the face of the bonds a statement to the same effect.
(d) Any fund or account established in connection with the bonds shall be established outside of the centralized treasury system. Notwithstanding any other law, the bank shall select the financing team and the trustee for the bonds, and the trustee shall be a corporation or banking association authorized to exercise corporate trust powers.
(e) Pursuant to Section 41329.55 of the Education Code, a school district other than the Compton Community College District shall instruct the Controller to repay the lease from moneys in the State School Fund and the Education Protection Account designated for apportionment to the school district. Pursuant to Section 41329.55 of the Education Code, if the school district is the Compton Community College District, the Controller shall be instructed to repay the lease from moneys in Section B of the State School Fund. Any amounts necessary to make this repayment shall be drawn from the total statewide funding available for community college apportionment consisting of funds in Section B of the State School Fund. Thereafter the Controller shall transfer to Section B of the State School Fund, either in a single or multiple transfers, an amount equal to the total repayment, which amount shall be transferred from the amount designated for apportionment to the Compton Community College District from the State School Fund. If these transfers from the district prove inadequate to repay any repayments for any reason, the Compton Community College District is required to use any revenue sources available to it for transfer and repayment purposes.
(f) Notwithstanding any other law, as long as any bonds issued pursuant to this section are outstanding, the following requirements apply:
(1) The school district for which the bonds were issued is not eligible to be a debtor in a case under Chapter 9 of the United States Bankruptcy Code, as it may be amended from time to time, and no governmental officer or organization is or may be empowered to authorize the school district to be a debtor under that chapter.
(2) It is the intent of the Legislature that the Legislature should not in the future abolish the Compton Community College District or take any action that would prevent the Compton Community College District from entering into or performing binding agreements or invalidate any prior binding agreements of the Compton Community College District, where invalidation may have a material adverse effect on the bonds issued pursuant to this section.
(3) The Compton Community College District shall not be reorganized or merged with another community college district unless all of the following apply:
(A) The successor district becomes by operation of law the owner of all property previously owned by the Compton Community College District.
(B) Any agreement entered into by the Compton Community College District in connection with bonds issued pursuant to this section are assumed by the successor district.
(C) The apportionment authorized by subdivision (e) remains in effect.
(D) Receipt by the bank of an opinion of bond counsel that the bonds issued for the Compton Community College District will remain tax exempt following the reorganization or merger.
(g) Nothing in this section limits the authority of the Legislature to abolish the Compton Community College District when bonds issued for that district are no longer outstanding. Further, the Legislature may provide for the redemption or defeasance of the bonds at any time so that no bonds are outstanding. If the Legislature provides for the redemption or defeasance of the bonds issued for the Compton Community College District in order to abolish that district, it is the intent of the Legislature that the funds required for the redemption or defeasance should be appropriated from Section B of the State School Fund.
(h) The bank may enter into contracts or agreements with banks, insurers, or other financial institutions or parties that it determines are necessary or desirable to improve the security and marketability of, or to manage interest rates or other risks associated with, the bonds issued pursuant to this section. The bank may pledge apportionments made by the Controller directly to the bond trustee pursuant to Section 41329.55 of the Education Code as security for repayment of any obligation owed to a bank, insurer, or other financial institution pursuant to this subdivision.

SEC. 13.

 Section 63071 of the Government Code is amended to read:

63071.
 (a) Notwithstanding any other provision of law, but consistent with Sections 1 and 18 of Article XVI of the California Constitution, a sponsor may issue bonds for purchase by the bank pursuant to a bond purchase agreement. The bank may issue bonds or authorize a special purpose trust to issue bonds. These bonds may be issued pursuant to the charter of any city or any city and county that authorized the issuance of these bonds as a sponsor and may also be issued by any sponsor pursuant to the Revenue Bond Law of 1941 (Chapter 6 (commencing with Section 54300) of Division 2 of Title 5) to pay the costs and expenses pursuant to this title, subject to the following conditions:
(1) With the prior approval of the bank, the sponsor may sell these bonds in any manner as it may determine, either by private sale or by means of competitive bid.
(2) Notwithstanding Section 54418, the bonds may be sold at a discount at any rate as the bank and sponsor shall determine.
(3) Notwithstanding Section 54402, the bonds shall bear interest at any rate and be payable at any time as the sponsor shall determine with the consent of the bank.
(b) The total amount of bonds issued to finance public development facilities that may be outstanding at any one time under this chapter shall not exceed five billion dollars ($5,000,000,000). The total amount of rate reduction bonds that may be outstanding at any one time under this chapter shall not exceed ten billion dollars ($10,000,000,000).
(c) Bonds for which moneys or securities have been deposited in trust, in amounts necessary to pay or redeem the principal, interest, and any redemption premium thereon, shall be deemed not to be outstanding for purposes of this section.

SEC. 14.

 Section 330 of the Public Utilities Code is repealed.
330.

In order 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 not later than 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 Public Utilities Commission has opened rulemaking and investigation proceedings with regard to restructuring California’s electric power 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 electric power and customers would be allowed to have the right to choose their supplier of electric power.

(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)In order 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 electric power.

(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 and an independent Power Exchange.

(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 electric power 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 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 electric power 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, prior to 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, provided that 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 Public Utilities 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 Public Utilities Commission and for rate reduction bonds from the California Infrastructure and Economic Development Bank.

(x)California’s public utility 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 electric power.

SEC. 15.

 Section 331 of the Public Utilities Code is amended to read:

331.
 The definitions set forth in this section shall govern the construction of this chapter.
(a) “Aggregator” means any 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 electric energy, transmission, and other services on behalf of these customers.
(b) “Broker” means an entity that arranges the sale and purchase of electric energy, transmission, and other services between buyers and sellers, but does not take title to any of the power sold.
(c) “Direct transaction” means a contract between any one or more electric generators, marketers, or brokers of electric power and one or more retail customers providing for the purchase and sale of electric power 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)

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

(f)

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

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

(h)

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

SEC. 16.

 Section 332.1 of the Public Utilities Code is amended to read:

332.1.
 (a) (1) It is the intent of the Legislature to enact Item 1 (revised) on the commission’s August 21, 2000, agenda, entitled “Opinion Modifying Decision (D.) D.00-06-034 and D.00-08-021 to Regarding Interim Rate Caps for San Diego Gas and Electric Company,” as modified below.
(2) It is also the intent of the Legislature that to the extent that the Federal Energy Regulatory Commission orders refunds to electrical corporations pursuant to their findings, the commission shall ensure that any refunds are returned to customers.
(b) The commission shall establish a ceiling of six and five-tenths cents ($0.065) per kilowatthour on the energy component of electric bills for electricity supplied to residential, small commercial, and street lighting customers by the San Diego Gas and Electric Company, through December 31, 2002, retroactive to June 1, 2000. If the commission finds it in the public interest, this ceiling may be extended through December 2003 and may be adjusted as provided in subdivision (d).
(c) The commission shall establish an accounting procedure to track and recover reasonable and prudent costs of providing electric energy to retail customers unrecovered through retail bills due to the application of the ceiling provided for in subdivision (b). The accounting procedure shall utilize revenues associated with sales of energy from utility-owned or managed generation assets to offset an undercollection, if undercollection occurs. The accounting procedure shall be reviewed periodically by the commission, but not less frequently than semiannually. The commission may utilize an existing proceeding to perform the review. The accounting procedure and review shall provide a reasonable opportunity for San Diego Gas and Electric Company to recover its reasonable and prudent costs of service over a reasonable period of time.
(d) If the commission determines that it is in the public interest to do so, the commission, after the date of the completion of the proceeding described in subdivision (g), may adjust the ceiling from the level specified in subdivision (b), and may adjust the frozen rate from the levels specified in subdivision (f), consistent with the Legislature’s intent to provide substantial protections for customers of the San Diego Gas and Electric Company and their interest in just and reasonable rates and adequate service.
(e) For purposes of this section, “small commercial customer” includes, but is not limited to, all San Diego Gas and Electric Company accounts on Rate Schedule A of the San Diego Gas and Electric Company, all accounts of customers who are “general acute care hospitals,” as defined in Section 1250 of the Health and Safety Code, all San Diego Gas and Electric Company accounts of customers who are public or private schools for pupils in kindergarten or any of grades 1 to 12, inclusive, and all accounts on Rate Schedule AL-TOU under 100 kilowatts.
(f) The commission shall establish an initial frozen rate of six and five-tenths cents ($0.065) per kilowatthour on the energy component of electric bills for electricity supplied to all customers by the San Diego Gas and Electric Company not subject to subdivision (b), for the time period ending with the end of the rate freeze for the Pacific Gas and Electric Company and the Southern California Edison Company pursuant to Section 368, retroactive to February 7, 2001. The commission shall consider the comparable energy components of rates for comparable customer classes served by the Pacific Gas and Electric Company and the Southern California Edison Company and, if it determines it to be in the public interest, the commission may adjust this frozen rate, and may do so, retroactive to the date that rate increases took effect for customers of Pacific Gas and Electric Company and Southern California Edison Company pursuant to the commission’s March 27, 2001, decision. The commission shall determine the Fixed Department of Water Resources Set-Aside pursuant to Section 360.5 for customers subject to this section, reflecting a retail rate consistent with the rate for the energy component of electric bills as determined in this subdivision, in place of the retail rate in effect on January 5, 2001. This section shall be construed to modify the payment provisions, but may not be construed to modify the electric procurement obligations of the Department of Water Resources, pursuant to any contract or agreement in accordance with Division 27 (commencing with Section 80000) of the Water Code, and in effect as of February 7, 2001, between the Department of Water Resources and San Diego Gas and Electric Company.
(g) The commission shall institute a proceeding to examine the prudence and reasonableness of the San Diego Gas and Electric Company in the procurement of wholesale energy on behalf of its customers, for a period beginning, at the latest, on June 1, 2000. If the commission finds that San Diego Gas and Electric Company acted imprudently or unreasonably, the commission shall issue orders that it determines to be appropriate affecting the retail rates of San Diego Gas and Electric Company customers including, but not limited to, refunds.
(h) Nothing in this section may be construed to limit the authority of the Department of Water Resources pursuant to Division 27 (commencing with Section 80000) of the Water Code.

SEC. 17.

 Section 341.5 of the Public Utilities Code is amended to read:

341.5.
 (a) The Independent System Operator and Power Exchange bylaws shall contain provisions that identify those matters specified in subdivision (b) of Section 339 as matters within state jurisdiction. The bylaws shall also contain provisions which state that California’s bylaws approval function with respect to the matters specified in subdivision (b) of Section 339 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.A. 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 Power Exchange 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 and Power Exchange board appointment function among participating states associated with the expansion of the Independent System Operator and Power Exchange into multistate entities shall be filed with the Federal Energy Regulatory Commission pursuant to Section 205 of the Federal Power Act (16 U.S.C.A. Sec. 824d).
(b) Any necessary bylaw changes to implement the provisions of Section 335, 337, 338, 339, 339 or subdivision (a) of this section, or changes required pursuant to an agreement as contemplated by subdivision (a) of this section with a participating state for a regional organization, shall be effective upon approval of the respective governing boards and the Oversight Board and acceptance for filing by the Federal Energy Regulatory Commission.

SEC. 18.

 Section 348 of the Public Utilities Code is amended to read:

348.
 The Independent System Operator shall adopt inspection, maintenance, repair, and replacement standards for the transmission facilities under its control no later than September 30, 1997. control. 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 electric 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 report to the Oversight Board, at such times as the Oversight Board may specify, on the development and implementation of the standards in relation to facilities under the operational control of the Independent System Operator. 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.

SEC. 19.

 Section 349.5 of the Public Utilities Code is amended to read:

349.5.
 (a) Beginning January 15, 2002, and at At least once monthly thereafter, each month, the Independent System Operator shall notify each air pollution control district and air quality management district of the name and address of each entity within the district’s boundaries within the Independent System Operator’s control area with whom the Independent System Operator enters into an interruptible service contract or similar arrangement.
(b) For the purposes of this section, “interruptible service contract or similar arrangement” means any arrangement in which a nonresidential entity agrees to reduce or consider reducing its electrical consumption during periods of peak demand or at the request of the Independent System Operator in exchange for compensation, or for assurances not to be blacked out or other similar nonmonetary assurances.
(c) The local air pollution control district or air quality management district shall maintain in a confidential manner the information received pursuant to this section. However, nothing in this subdivision shall affect the applicability of Chapter 3.5 (commencing with Section 6250) of Division 7 of Title 1 of the Government Code, or of any other similar open records statute or ordinance, to information provided pursuant to this section.

SEC. 20.

 Section 350 of the Public Utilities Code is repealed.
350.

The Independent System Operator, in consultation with the California Energy Resources Conservation and Development Commission, the Public Utilities Commission, the Western Electricity Coordinating Council, and concerned regulatory agencies in other western states, shall within six months after the Federal Energy Regulatory Commission approval of the Independent System Operator, provide a report to the Legislature and to the Oversight Board that does the following:

(a)Conducts an independent review and assessment of Western Electricity Coordinating Council operating reliability criteria.

(b)Quantifies the economic cost of major transmission outages relating to the Pacific Intertie, Southwest Power Link, DC link, and other important high voltage lines that carry power both into and from California.

(c)Identifies the range of cost-effective options that would prevent or mitigate the consequences of major transmission outages.

(d)Identifies communication protocols that may be needed to be established to provide advance warning of incipient problems.

(e)Identifies the need for additional generation reserves and other voltage support equipment, if any, or other resources that may be necessary to carry out its functions.

(f)Identifies transmission capacity additions that may be necessary at certain times of the year or under certain conditions.

(g)Assesses the adequacy of current and prospective institutional provisions for the maintenance of reliability.

(h)Identifies mechanisms to enforce transmission right-of-way maintenance.

(i)Contains recommendations regarding cost-beneficial improvements to electric system reliability for the citizens of California.

SEC. 21.

 Section 355 of the Public Utilities Code is repealed.
355.

The Power Exchange shall provide an efficient competitive auction, open on a nondiscriminatory basis to all suppliers, that meets the loads of all exchange customers at efficient prices.

SEC. 22.

 Section 356 of the Public Utilities Code is repealed.
356.

The Power Exchange governing board may form appropriate technical advisory committees comprised of market and nonmarket participants to advise the governing board on relevant issues.

SEC. 23.

 Section 359 of the Public Utilities Code is amended to read:

359.
 (a) It is the intent of the Legislature to provide for the evolution of the Independent System Operator and the Power Exchange into regional organizations to promote the development of regional electricity transmission markets in the western states and to improve the access of consumers served by the Independent System Operator and the Power Exchange to those markets.
(b) The preferred means by which the voluntary evolution described in subdivision (a) should occur is through the adoption of a regional compact or other comparable agreement among cooperating party states, the retail customers of which states would reside within the geographic territories served by the Independent System Operator and the Power Exchange. Operator.
(c) The agreement described in subdivision (b) should provide for all of the following:
(1) An equitable process for the appointment or confirmation by party states of members of the governing boards of the Independent System Operator and the Power Exchange. Operator.
(2) A respecification of the size, structure, representation, eligible membership, nominating procedures, and member terms of service of the governing boards of the Independent System Operator and the Power Exchange. Operator.
(3) Mechanisms by which each party state, jointly or separately, can oversee effectively the actions of the Independent System Operator and the Power Exchange as those actions relate to the assurance of electricity system reliability within the party state and to matters that affect electricity sales to the retail customers of the party state or otherwise affect the general welfare of the electricity consumers and the general public of the party state.
(4) The adherence by publicly owned and investor-owned utilities located in party states to enforceable standards and protocols to protect the reliability of the interconnected regional transmission and distribution systems.

SEC. 24.

 Section 361 of the Public Utilities Code is repealed.
361.

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

SEC. 25.

 Section 363 of the Public Utilities Code is repealed.
363.

(a)In order to ensure the continued safe and reliable operation of public utility electric generating facilities, the commission shall require in any proceeding under Section 851 involving the sale, but not spinoff, of a public utility electric generating facility, for transactions initiated prior to December 31, 2001, and approved by the commission by December 31, 2002, that the selling utility contract with the purchaser of the facility for the selling utility, an affiliate, or a successor corporation to operate and maintain the facility for at least two years. The commission may require these conditions to be met for transactions initiated on or after January 1, 2002. The commission shall require the contracts to be reasonable for both the seller and the buyer.

(b)Subdivision (a) shall apply only if the facility is actually operated during the two-year period following the sale. Subdivision (a) shall not require the purchaser to operate a facility, nor shall it preclude a purchaser from temporarily closing the facility to make capital improvements.

(c)For those bayside fossil fueled electric generation and associated transmission facilities that an electrical corporation has proposed to divest in a public auction and for which the Legislature has appropriated state funds in the Budget Act of 1998 to assist local governmental entities in acquiring the facilities or to mitigate environmental and community issues, and where the local governmental entity proposes that the closure of the power plant would serve the public interest by mitigating air, water and other environmental, health and safety, and community impacts associated with the facilities, and where the local governmental entity and electrical corporation have engaged in significant negotiations with the purpose of shutting down the power plant, and where there is an agreement between the electrical corporation and the local governmental entity for closure of the facilities or for the local governmental entity to acquire the facilities, the commission shall approve the closure of these facilities or the transfer of these electric generation and associated transmission facilities to the local governmental entity and shall consider the utility transactions with the community to be just and reasonable for its ratepayers. For purposes of calculating the Competition Transition Charge, the commission shall not use any inferred market value for the facilities predicated on the continued use of the plant, the construction of successor facilities or alternative use of the site and shall net the costs of the depreciated book value of the power plant and the unrecovered costs of decommissioning, environmental remediation and site restoration against the net proceeds received from the local governmental entity for the acquisition or closure of the facilities. Thereafter, any net proceeds received from the ultimate disposition, by the electrical corporation, of the site shall be credited to recovery of Competition Transition Charges.

SEC. 26.

 Section 365 of the Public Utilities Code is amended to read:

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

SEC. 27.

 Section 367 of the Public Utilities Code is repealed.
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, 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.

SEC. 28.

 Section 367.7 of the Public Utilities Code is repealed.
367.7.

(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.

SEC. 29.

 Section 368 of the Public Utilities Code is amended to read:

368.
 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: 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 section shall be used to ensure that customers of the electrical corporation who purchase electricity from suppliers other than the electrical corporation pay the same unbundled component charges, other than energy, that a bundled service customer pays.

(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.

SEC. 30.

 Section 368.5 of the Public Utilities Code is repealed.
368.5.

(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.

SEC. 31.

 Section 369 of the Public Utilities Code is amended to read:

369.
 The commission shall establish an effective mechanism that ensures recovery of transition costs referred to in Sections 367, 368, 375, and 376, and Competition transition charges, subject to the conditions in Sections 371 to 374, inclusive, from the recovery of which was authorized by the commission prior to January 1, 2015, shall continue to apply to 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.

SEC. 32.

 Section 370 of the Public Utilities Code is amended to read:

370.
 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, competition transition charges, 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.

SEC. 33.

 Section 371 of the Public Utilities Code is amended to read:

371.
 (a) Except as provided in Sections 372 and 374, the uneconomic costs provided in Sections 367, 368, 375, and 376 competition transition charges shall be applied to each customer based on the amount of electricity purchased by the customer from an electrical corporation or alternate supplier of electricity, subject to changes in usage occurring in the normal course of business.
(b) Changes in usage occurring in the normal course of business are those resulting from changes in business cycles, termination of operations, departure from the utility service territory, weather, reduced production, modifications to production equipment or operations, changes in production or manufacturing processes, fuel switching, including installation of fuel cells pending a contrary determination by the California Energy Resources Conservation and Development Commission in Section 383, 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) Nothing in this section shall be interpreted to exempt or alter the obligation of a customer to comply with Chapter 5 (commencing with Section 119075) of Part 15 of Division 104 of the Health and Safety Code. Nothing in this section shall be construed as a limitation on the ability of residential customers to alter their pattern of electricity purchases by activities on the customer side of the meter.

SEC. 34.

 Section 372 of the Public Utilities Code is amended to read:

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

SEC. 35.

 Section 373 of the Public Utilities Code is repealed.
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, 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.

SEC. 36.

 Section 374 of the Public Utilities Code is amended to read:

374.
 (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 Competition transition charges shall not apply to the following:
(1) One hundred ten megawatts of load served by irrigation districts, as hereafter allocated by this paragraph:
(A) The 110 megawatts of load shall be allocated among the service territories of the three largest electrical corporations in the ratio of the number of irrigation districts in the service territory of each utility to the total number of irrigation districts in the service territories of all three utilities.
(B) The total amount of load allocated to each utility service area shall be phased in over five years beginning January 1, 1997, so that one-fifth of the allocation is allocated in each of the five years. Any allocation that remains unused at the end of any year shall be carried over to the succeeding year and added to the allocation for that year.
(C) The load allocated to each utility service territory pursuant to subparagraph (A) shall be further allocated among the respective irrigation districts within that service territory by the California Energy Resources Conservation and Development 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 utilize the allocation within the timeframe requested. These plans shall include specific information on the irrigation districts’ organization for electric distribution, contracts, financing and engineering plans for capital facilities, as well as detailed information about the loads to be served, and shall not be less than eight megawatts or more than 40 megawatts, provided, however, that any portion of the 110 megawatts that remains unallocated may be reallocated to projects without regard to the 40 megawatts limitation. In making an allocation among irrigation districts, the Energy Resources Conservation and Development Commission shall assess the viability of each submission and whether it can be accomplished in the timeframe proposed. The Energy Resources Conservation and Development Commission shall have the discretion to allocate the load covered by this section in a manner that best ensures its usage within the allocation period.
(D) At least 50 percent of each year’s allocation to a district shall be applied to that portion of load that is used to power pumps for agricultural purposes.
(E) Any load pursuant to this subdivision shall be served by distribution facilities owned by, or leased to, the district in question.
(F) Any load allocated pursuant to paragraph (1) shall be located within the boundaries of the affected irrigation district, or within the boundaries specified in an applicable service territory boundary agreement between an electrical corporation and the affected irrigation district; additionally, the provisions of subparagraph (C) of paragraph (1) shall be applicable to any load within the Counties of Stanislaus or San Joaquin, or both, served by any irrigation district that is currently serving or will be serving retail customers.
(2) Seventy-five megawatts of load served by the Merced Irrigation District hereafter prescribed in this paragraph:
(A) The total allocation provided by this paragraph shall be phased in over five years beginning January 1, 1997, so that one-fifth of the allocation is received in each of the five years. Any allocation that remains unused at the end of any year shall be carried over to the succeeding year and added to the allocation for that year.
(B) Any load to which the provision of this paragraph is applicable shall be served by distribution facilities owned by, or leased to, Merced Irrigation District.
(C) A load to which the provisions of this paragraph are applicable shall be located within the boundaries of Merced Irrigation District as those boundaries existed on December 20, 1995, together with the territory of Castle Air Force Base that was located outside of the district on that date.
(D) The total allocation provided by this paragraph shall be phased in over five years beginning January 1, 1997, with the exception of load already being served by the district as of June 1, 1996, which shall be deducted from the total allocation and shall not be subject to the costs provided in Sections 367, 368, 375, and 376. competition transition charges.
(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 competition transition charges 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 competition transition charges shall not apply to that portion of the load of the University of California campus situated in Yolo County that was being served as of May 31, 1996, by preference power purchased from a federal marketing agency, or its successor, provided that the power is used solely for the facility load of that campus and not, directly or indirectly, for sale.

SEC. 37.

 Section 374.5 of the Public Utilities Code is repealed.
374.5.

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.

SEC. 38.

 Section 375 of the Public Utilities Code is repealed.
375.

(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.

SEC. 39.

 Section 376 of the Public Utilities Code is repealed.
376.

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.

SEC. 40.

 Section 379 of the Public Utilities Code is amended to read:

379.
 Nuclear decommissioning costs shall not be part of the costs described in Sections 367, 368, 375, and 376, competition transition charges, 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.

SEC. 41.

 Section 390 of the Public Utilities Code is repealed.
390.

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

(b)Until the requirements of subdivision (c) have been satisfied, 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 public utility 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)The short-run avoided cost energy payments paid to nonutility power generators by electrical corporations shall be based on the clearing price paid by the independent Power Exchange if (1) the commission has issued an order determining that the independent Power Exchange is functioning properly for the purposes of determining the short-run avoided cost energy payments to be made to nonutility power generators, and either (2) the fossil-fired generation units owned, directly or indirectly, by the public utility electrical corporation are authorized to charge market-based rates and the “going forward” costs of those units are being recovered solely through the clearing prices paid by the independent Power Exchange or from contracts with the Independent System Operator, whether those contracts are market-based or based on operating costs for particular utility-owned powerplant units and at particular times when reactive power/voltage support is not yet procurable at market-based rates at locations where it is needed, and are not being recovered directly or indirectly through any other source, or (3) the public utility electrical corporation has divested 90 percent of its gas-fired generation facilities that were operated to meet load in 1994 and 1995. However, nonutility power generators subject to this section may, upon appropriate notice to the public utility electrical corporation, exercise a one-time option to elect to thereafter receive energy payments based upon the clearing price from the independent Power Exchange.

(d)If a nonutility power generator is being paid short-run avoided costs energy payments by an electrical corporation by a firm capacity contract, a forecast as-available capacity contract, or a forecast as-delivered capacity contract on the basis of the clearing price paid by the independent Power Exchange as described in subdivision (c) above, the value of capacity in the clearing price, if any, shall not be paid to the nonutility power generator. The value of capacity in the clearing price, if any, equals the difference between the market clearing customer demand bid at the level of generation dispatched by the independent Power Exchange and the highest supplier bid dispatched.

(e)Short-run avoided energy cost payments made pursuant to this section are in addition to contractually specified capacity payments. Nothing in this section shall be construed to 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.

(f)Nothing in this section shall be construed to limit the level of transition cost recovery provided to utilities under electric industry restructuring policies established by the commission.

(g)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; provided that, for purposes of this section, the following shall not be considered “going forward costs”: (1) commission-approved capital costs for capital additions to fossil-fueled powerplants, provided that such additions are necessary for the continued operation of the powerplants utilized to meet load and such additions are not undertaken primarily to expand, repower or enhance the efficiency of plant operations; or, (2) commission-approved operating costs for particular utility-owned powerplant units and at particular times when reactive power/voltage support is not yet procurable at market-based rates in locations where it is needed, provided that the recovery shall end on December 31, 2001.

SEC. 42.

 Section 390.1 of the Public Utilities Code is repealed.
390.1.

Any nonutility power generator using renewable fuels that has entered into a contract with an electrical corporation prior to December 31, 2001, specifying fixed energy prices for five years of output may negotiate a contract for an additional five years of fixed energy payments upon expiration of the initial five-year term, at a price to be determined by the commission.

SEC. 43.

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

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

SEC. 44.

 Section 395 of the Public Utilities Code is amended to read:

395.
 (a) In addition to any other right to revoke an offer, residential and small commercial customers of electrical service, as defined in subdivision (h) (g) of Section 331, have the right to cancel a contract for electric service until midnight of the third business day after the day on which the buyer signs an agreement or offer to purchase.
(b) Cancellation occurs when the buyer gives written notice of cancellation to the seller at the address specified in the agreement or offer.
(c) Notice of cancellation, if given by mail, is effective when deposited in the mail properly addressed with postage prepaid.
(d) Notice of cancellation given by the buyer need not take the particular form as provided with the contract or offer to purchase and, however expressed, is effective if it indicates the intention of the buyer not to be bound by the contract.

SEC. 45.

 Section 397 of the Public Utilities Code is repealed.
397.

(a)Notwithstanding subdivision (a) of Section 368, to ensure the continued safe and reliable provision of electric service during the transition to competition, and to limit the effect of fuel price volatility in electric rates paid by California consumers, it is in the public interest to allow an electrical corporation which is also a gas corporation and served fewer than four million customers as of December 20, 1995, to file with the commission a rate cap mechanism which shall include a Fuel Price Index Mechanism requiring limited adjustments in an electrical corporation’s authorized System Average Rate in effect on June 10, 1996, to reflect price changes in the fuel market. The commission shall authorize an electrical corporation to implement a rate cap mechanism which includes a Fuel Price Index Mechanism provided the following criteria are met:

(1)The Fuel Price Index Mechanism shall be based on the Southern California Border Index price for natural gas as published periodically in Natural Gas Intelligence Magazine. The “Starting Point” of the Fuel Price Index Mechanism shall be defined as the California Border Index price as published in Natural Gas Intelligence for January 1, 1996.

(2)The Fuel Price Index Mechanism shall include a “deadband” defined as a price range for natural gas that is any price up to 10 percent higher, or lower, than the Starting Point.

(3)The electrical corporation shall not file for a change in its authorized System Average Rate unless the California Border Index price, on a 12-month, rolling average basis, is outside the deadband. If the published California Border Index is outside of the deadband, the electrical corporation shall increase, or decrease, its authorized System Average Rate by an amount equal to the product of 25 percent multiplied by the percentage by which the 12-month rolling average natural gas price is higher, or lower, than the deadband.

(4)In no case shall an electrical corporation’s authorized System Average Rate under the Fuel Price Index Mechanism exceed the average of the authorized system average rates for the two largest electrical corporations as of June 10, 1996.

(5)This section shall become inoperative on December 31, 2001.

SEC. 46.

 Section 399.2 of the Public Utilities Code is amended to read:

399.2.
 (a) (1) It is the policy of this state, and the intent of the Legislature, to reaffirm that each electrical corporation shall continue to operate its electric distribution grid in its service territory and shall do so in a safe, reliable, efficient, and cost-effective manner.
(2) In furtherance of this policy, it is the intent of the Legislature that each electrical corporation shall continue to be responsible for operating its own electric distribution grid including, but not limited to, owning, controlling, operating, managing, maintaining, planning, engineering, designing, and constructing its own electric distribution grid, emergency response and restoration, service connections, service turnons and turnoffs, and service inquiries relating to the operation of its electric distribution grid, subject to the commission’s authority.
(b) In order to ensure the continued efficient use, and cost-effective, safe, and reliable operation of the electric distribution grid, each electrical corporation shall continue to operate its electric distribution grid in its service territory consistent with Section 330. territory.
(c) In carrying out the purposes of this section, each electrical corporation shall continue to make reasonable investments in its electric distribution grid. Each electrical corporation shall continue to have a reasonable opportunity to fully recover from all customers of the electrical corporation, in a manner determined by the commission pursuant to this code, all of the following:
(1) Reasonable investments in its electric distribution grid.
(2) A reasonable return on the investments in its electric distribution grid.
(3) Reasonable costs to operate its electric distribution grid.
(d) For purposes of this section, the term “electric distribution grid” means those facilities owned or operated by an electrical corporation that are not under the control of the Independent System Operator and that are used to transmit, deliver, or furnish electricity for light, heat, or power.
(e) Nothing in this section shall be construed to alter or to affect any of the following:
(1) Section 216, 218, or 2827.
(2) The authority of the commission to establish and enforce standards and tariff conditions for the interconnection of customer-owned facilities to the electric distribution grid.
(3) The ratemaking authority of the commission under this code.
(4) The authority of the commission to establish rules governing the extension of service to new customers.
(f) Nothing in this section shall be construed to alter or affect any authority or lack of authority of the commission regarding the ownership and operation of new electric generation used in whole, or in part, for the purpose of maintaining or enhancing the reliability of the electric distribution grid.
(g) Nothing in this section diminishes or expands any existing authority of a local governmental entity.
(h) The commission shall require every electrical corporation operating an electric distribution grid to inform all customers who request residential service connections via telephone of the availability of the California Alternative Rates for Energy (CARE) program and how they may qualify for and obtain these services and shall accept applications for the CARE program according to procedures specified by the commission. Electrical corporations shall recover the reasonable costs of implementing this subdivision.

SEC. 47.

 Article 5.5 (commencing with Section 840) of Chapter 4 of Part 1 of Division 1 of the Public Utilities Code is repealed.

SEC. 48.

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

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

SEC. 49.

 Section 9600 of the Public Utilities Code is amended to read:

9600.
 (a) It is the intent of the Legislature that California’s local publicly owned electric utilities and electric corporations should commit control of their transmission facilities to the Independent System Operator as described in Chapter 2.3 (commencing with Section 330) of Part 1 of Division 1. 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 and is based on the following principles:
(1) Utility specific access charge rates as proposed in Docket No. EC96-19-000 as finally approved by the Federal Energy Regulatory Commission reflecting the costs of that utility’s transmission facilities shall go into effect on the first day of the Independent System Operator operation. The utility specific rates shall honor all of the terms and conditions of existing transmission service contracts and shall recognize any wheeling revenues of existing transmission service arrangements to the transmission owner.
(2) (A) No later than two years after the initial operation of the Independent System Operator, the Independent System Operator shall recommend for adoption by the Federal Energy Regulatory Commission a rate methodology determined by a decision of the Independent System Operator governing board, provided that the decision shall be based on principles approved by the governing board including, but not limited to, an equitable balance of costs and benefits, and shall define the transmission facility costs, if any, which shall be rolled in to the transmission service rate and spread equally among all Independent System Operator transmission users, and those transmission facility costs, if any, which should be specifically assigned to a specific utility’s service area.
(B) If there is no governing board decision, the rate methodology shall be determined following a decision by the alternative dispute resolution method set forth in the Independent System Operator bylaws.
(C) If no alternative dispute resolution decision is rendered, then a default rate methodology shall be a uniform regional transmission access charge and a utility specific local transmission access charge, provided that the default rate methodology shall be recommended for implementation upon termination of the cost recovery plan set forth in Section 368 or no later than two years after the initial operation of the Independent System Operator, whichever is later. For purposes of this paragraph, regional transmission facilities are defined to be transmission facilities operating at or above 230 kilovolts plus an appropriate percentage of transmission facilities operating below 230 kilovolts; all other transmission facilities shall be considered local. The appropriate percentage of transmission facilities described above shall be consistent with the guidelines in Federal Energy Regulatory Commission Order No. 888 and any exception approved by that commission.
(3) If the rate methodology implemented as a result of a decision by the Independent System Operator governing board or resulting from the independent system operator Independent System Operator alternative dispute resolution process results in rates different than those in effect prior to the decision for any transmission facility owner, the amount of any differences between the new rates and the prior rates shall be recorded in a tracking account to be recovered from customers and paid to the appropriate transmission owners by the transmission facility owner after termination of the cost recovery plan set forth in Section 368. The recovery and payments shall be based on an amortization period not to exceed three years in the case of the electrical corporations or five years in the case of the local publicly owned electric utilities.
(4) The costs of transmission facilities placed in service after the date of initial implementation of the Independent System Operator shall be recovered using the rate methodology in effect at the time the facilities go into operation.
(5) The electrical corporations and the local publicly owned electric utilities shall jointly develop language for implementation proposals to the Federal Energy Regulatory Commission based on these principles.
(6) Nothing in this section shall compel any party to violate restrictions applicable to facilities financed with tax-exempt bonds or contractual restrictions and covenants regarding use of transmission facilities existing as of December 20, 1995.
(b) Following a final Federal Energy Regulatory Commission decision approving the Independent System Operator, no California electrical corporation or local publicly owned electric utility shall be authorized to collect any competition transition charge authorized pursuant to this division and Chapter 2.3 (commencing with Section 330) of Part 1 of Division 1 unless it commits control of its transmission facilities to the Independent System Operator.

SEC. 50.

 Section 9607 of the Public Utilities Code is amended to read:

9607.
 (a) The intent of this section is to avoid cost-shifting to customers of an electrical corporation resulting from the transfer of distribution services from an electrical corporation to an irrigation district.
(b) Except as otherwise provided in this section and Section 9608, and notwithstanding any other provision of law, an irrigation district that offered electric service to retail customers as of January 1, 1999, may not construct, lease, acquire, install, or operate facilities for the distribution or transmission of electricity to retail customers located in the service territory of an electrical corporation providing electric distribution services, unless the district has first applied for and received the approval of the commission and implements its service consistent with the commission’s order. The commission shall find that service to be in the public interest and shall approve the request of a district to provide distribution or transmission of electricity to retail customers located in the service territory of an electrical corporation providing electric distribution service if, after notice and hearing, the commission determines all of the following:
(1) The district will provide universal service to all retail customers who request service within the area to be served, at published tariff rates and on a just, reasonable, and nondiscriminatory basis, comparable to that provided by the current retail service provider.
(2) If the area the district is proposing to serve is either of the following:
(A) Is within the district’s boundaries but less than the entire district, the area to be served includes a percentage of residential customers and small customers, based on load, comparable to the percentage of residential and small customers in the district, based on load.
(B) Includes territory outside the district’s boundaries, in which case the territory outside the district’s boundaries must include a percentage of residential customers and small customers, based on load, comparable to the percentage of residential and small customers in the county or counties where service is to be provided, based on load.
(3) Service by the district will be consistent with the intent of the state to avoid economic waste caused by duplication of facilities as set forth in Section 8101.
(4) Service by the district will include reasonable mitigation of any adverse effects on the reliability of an existing service by the electrical corporation.
(5) The district has established, funded, and is carrying out public purpose and low-income programs comparable to those provided by the current electric retail service provider.
(6) That district’s tariffed electric rates, exclusive of commodity costs, will be at least 15 percent below the tariffed electric rates, exclusive of commodity costs and nonbypassable charges under Sections 367, 368, 375, 376, and 379, competition transition charges of the electrical corporation for comparable services.
(7) Service by the district is in the public interest.
(c) An irrigation district that obtains the approval of the commission under this section to serve an area shall prepare an annual report available to the public on the total load and number of accounts of residential, low-income, agricultural, commercial, and industrial customers served by the irrigation district in the approved service area.
(d) The commission shall have jurisdiction to resolve and adjudicate complaint cases brought against an irrigation district that offered electric service to retail customers as of January 1, 1999, by an interested party where the complaint concerns retail electric service outside the boundaries of the district and within the service territory of an electrical corporation. Nothing in this section grants the commission jurisdiction to adjudicate complaint cases involving retail electric service by an irrigation district inside its boundaries or inside an irrigation district’s exclusive service territory.
(e) Any project involving electric transmission or distribution facilities to be constructed or installed by an irrigation district to serve retail customers located in the service territory of an electrical corporation providing electric distribution services shall comply with the California Environmental Quality Act, Act (Division 13 (commencing with Section 21000)) of the Public Resources Code. The county in which the construction or installation is to occur shall act as the lead agency. If a project involves the construction or installation of electric transmission or distribution facilities in more than one county, the county where the majority of the construction is anticipated to occur shall act as the lead agency.
(f) An irrigation district may not offer service to customers outside of its district boundaries before offering service to all customers within its district boundaries.
(g) This section does not apply to electric distribution service provided by Modesto Irrigation District to those customers or within those areas described in subdivisions (a), (b), and (c) of Section 9610.
(h) The provisions of this section shall not apply to (1) a cumulative 90 megawatts of load served by the Merced Irrigation District that is 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 which was located outside the District district on that date, or (2) electric load served by the District district which was not previously served by an electric corporation that is 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 which was located outside the District district on that date.
(i) For purposes of this section, a megawatt of load shall be calculated in accordance with the methodology established by the California Energy Resource Conservation and Development Energy Commission in its Docket No. 96-IRR-1890, but the 90 megawatts shall not include electrical usage by customers that move to the areas described in paragraph (1) after December 31, 2000.
(j) Subdivision (a) of this section shall not apply to the construction, modification, lease, acquisition, installation, or operation of facilities for the distribution or transmission of electricity to customers electrically connected to a district as of December 31, 2000, or to other customers who subsequently locate at the same premises.
(k) In recognition of contractual arrangements and settlements existing as of June 1, 2000, this section does not apply to the acquisition or operation of the electric distribution facilities that are the subject of the Settlement Agreement dated May 1, 2000, between Pacific Gas and Electric Company and the San Joaquin Irrigation District.
(l) For purposes of this section, retail customers do not include an irrigation district’s own electric load being served of retail by an electrical corporation.

SEC. 51.

 Section 31071.5 of the Streets and Highways Code is amended to read:

31071.5.
 (a) Bonds issued under this chapter may not be deemed to constitute a debt or liability of the state or of any political subdivision thereof, other than the bank, or a pledge of the faith and credit of the state or of any political subdivision thereof, but shall be payable solely from the account, and the assets of the account, and the security provided by the account. All bonds issued under this chapter shall contain on the face of the bonds a statement to this effect.
(b) Notwithstanding any other provision of law, Article 3 (commencing with Section 63040) of, Article 4 (commencing with 63042) of, 63040) and Article 5 (commencing with Section 63043) of Chapter 2 of Division 1 of Title 6.7 of the Government Code do not apply to any financing provided by the bank to, or at the request of, the department in connection with the account.

SECTION 1.Section 30009 is added to the Penal Code, to read:
30009.

(a)In order to reduce the number of firearms possessed by prohibited persons listed in the Prohibited Armed Persons File, a 30-day amnesty period shall be established, commencing on a date to be determined by the Department of Justice but not later than January 1, 2015, during which a person prohibited from possessing a firearm may surrender his or her firearms to a local law enforcement agency without being charged with illegal possession of firearms, as provided in subdivision (e). No person convicted of a felony shall be permitted to participate in the amnesty period.

(b)The department shall provide written notification of the amnesty period to all prohibited persons eligible to participate in the amnesty period by first-class mail no later than 60 calendar days prior to the commencement of the amnesty period. The notification shall specify the firearms possessed by the prohibited person and provide instructions for the surrender of the illegal firearms.

(c)For each instance in which a local law enforcement agency receives a firearm from a prohibited person during the amnesty period described in subdivision (a), the agency shall submit to the department the following information:

(1)The name of the prohibited person who surrendered the firearm.

(2)The person’s date of birth.

(3)A description of the firearm or firearms surrendered.

(4)The serial number of the firearm or firearms surrendered.

(5)Any other information deemed necessary by the department.

(d)The department shall enter the information received pursuant to subdivision (c) in the Prohibited Armed Persons File to create a record of each firearm surrendered during the amnesty period.

(e)A prohibited person who surrenders a firearm pursuant to subdivision (a) shall not be charged with illegal possession of firearms for any firearm the department has on record as having been surrendered pursuant to subdivision (d).

(f)At the expiration of the 30-day amnesty period described in subdivision (a), a person prohibited from possessing a firearm and eligible to participate in the amnesty program who still maintains possession of his or her firearms shall be subject to a civil fine of up to two thousand five hundred dollars ($2,500) per firearm in addition to any criminal penalties authorized by law, including, but not limited to, penalties described in Chapter 3 (commencing with Section 29900) of this code and Sections 8100 and 8103 of the Welfare and Institutions Code.

(g)A prohibited person shall not to be charged with illegal possession of a firearm, nor be subject to the fine described in subdivision (f), if he or she provides evidence satisfactory to the department that he or she lawfully surrendered his or her firearm prior to the commencement of the amnesty period.

(h)Any firearms surrendered to a local law enforcement agency pursuant to this section shall be sold or destroyed as provided in Section 18005.

(i)Sections 26500 and 27545, and subdivision (a) of Section 31615, shall not apply to the surrender of firearms to a local law enforcement agency pursuant to this section.

SEC. 2.

If the Commission on State Mandates determines that this act contains costs mandated by the state, reimbursement to local agencies and school districts for those costs shall be made pursuant to Part 7 (commencing with Section 17500) of Division 4 of Title 2 of the Government Code.