Amended in Assembly August 19, 2014

Amended in Assembly August 6, 2013

Amended in Assembly June 27, 2013

Amended in Senate May 24, 2013

Amended in Senate April 11, 2013

Senate BillNo. 38


Introduced by Senatorbegin delete De Leónend deletebegin insert Padillaend insert

December 5, 2012


An act tobegin delete add Section 30009 to the Penal Code, relating to firearms.end deletebegin insert 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.end insert

LEGISLATIVE COUNSEL’S DIGEST

SB 38, as amended, begin deleteDe Leónend delete begin insertPadillaend insert. begin deleteFirearms: prohibited persons. end deletebegin insertElectrical restructuring.end insert

begin insert

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.

end insert
begin insert

This bill would repeal this reporting requirement, and would abolish the Power Exchange.

end insert
begin insert

Electrical restructuring makes legislative findings and declarations in order to provide guidance to the Public Utilities Commission in carrying out restructuring.

end insert
begin insert

This bill repeals those legislative findings and declarations.

end insert
begin insert

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.

end insert
begin insert

This bill would repeal this provision.

end insert
begin insert

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.

end insert
begin insert

This bill would repeal these provisions.

end insert
begin insert

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.

end insert
begin insert

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.

end insert
begin insert

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.

end insert
begin insert

This bill would replace the various references to the specified statutory charges with “competition transition charges.”

end insert
begin insert

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.

end insert
begin insert

This bill would repeal this provision.

end insert
begin insert

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.

end insert
begin insert

This bill would repeal this provision.

end insert
begin insert

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.

end insert
begin insert

This bill would repeal this provision.

end insert
begin insert

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.

end insert
begin insert

This bill would repeal this provision.

end insert
begin insert

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.

end insert
begin insert

This bill would strike references to these repealed statutes.

end insert
begin delete

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.

end delete
begin delete

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.

end delete
begin delete

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.

end delete
begin delete

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.

end delete

Vote: majority. Appropriation: no. Fiscal committee: yes. State-mandated local program: begin deleteyes end deletebegin insertnoend insert.

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

P5    1begin insert

begin insertSECTION 1.end insert  

end insert

begin insertSection 63010 of the end insertbegin insertGovernment Codeend insertbegin insert is
2amended to read:end insert

3

63010.  

For purposes of this division, the following words and
4terms shall have the following meanings unless the context clearly
5indicates or requires another or different meaning or intent:

6(a) “Act” means the Bergeson-Peace Infrastructure and
7Economic Development Bank Act.

8(b) “Bank” means the California Infrastructure and Economic
9Development Bank.

10(c) “Board” or “bank board” means the Board of Directors of
11the California Infrastructure and Economic Development Bank.

P6    1(d) “Bond purchase agreement” means a contractual agreement
2executed between the bank and a sponsor, or a special purpose
3trust authorized by the bank or a sponsor, or both, whereby the
4bank or special purpose trust authorized by the bank agrees to
5purchase bonds of the sponsor for retention or sale.

6(e) “Bonds” means bonds, including structured, senior, and
7subordinated bonds or other securities; loans; notes, including
8bond, revenue, taxbegin insert,end insert or grant anticipation notes; commercial paper;
9floating rate and variable maturity securities; and any other
10evidences ofbegin delete indebtedness or ownership,end deletebegin insert indebtednessend insert including
11certificates of participationbegin delete or beneficial interest, asset backed
12certificates,end delete
or lease-purchasebegin delete or installment purchaseend delete agreements,
13whether taxable or excludable from gross income for federal
14income taxation purposes.

15(f) “Cost,” as applied to a project or portion thereof financed
16under this division, means all or any part of the cost of construction,
17renovation, and acquisition of all lands, structures, real or personal
18property, rights, rights-of-way, franchises, licenses, easements,
19and interests acquired or used for a project; the cost of demolishing
20or removing any buildings or structures on land so acquired,
21including the cost of acquiring any lands to which the buildings
22or structures may be moved; the cost of all machinery, equipment,
23and financing charges; interest prior to, during, and for a period
24after completion of construction, renovation, or acquisition, as
25determined by the bank; provisions for working capital; reserves
26for principal and interest and for extensions, enlargements,
27additions, replacements, renovations, and improvements; and the
28cost of architectural, engineering, financial and legal services,
29plans, specifications, estimates, administrative expenses, and other
30expenses necessary or incidental to determining the feasibility of
31any project or incidental to the construction, acquisition, or
32financing of anybegin delete project, and transition costs in the case of an
33electrical corporation.end delete
begin insert project.end insert

34(g) “Economic development facilities” means real and personal
35property, structures, buildings, equipment, and supporting
36components thereof that are used to provide industrial, recreational,
37research, commercial, utility, or service enterprise facilities,
38community, educational, cultural, or social welfare facilities and
39any parts or combinations thereof, and all facilities or infrastructure
P7    1necessary or desirable in connection therewith, including provision
2for working capital, but shall not include any housing.

3(h) “Electrical corporation” has the meaning set forth in Section
4218 of the Public Utilities Code.

5(i) “Executive director” means the Executive Director of the
6California Infrastructure and Economic Development Bank
7appointed pursuant to Section 63021.

8(j) “Financial assistance” in connection with a project, includes,
9but is not limited to, any combination of grants, loans, the proceeds
10of bonds issued by the bank or special purpose trust, insurance,
11guarantees or other credit enhancements or liquidity facilities, and
12contributions of money, property, labor, or other things of value,
13as may be approved by resolution of the board or the sponsor, or
14both; the purchase or retention of bank bonds, the bonds of a
15sponsor for their retention or for sale by the bank, or the issuance
16of bank bonds or the bonds of a special purpose trust used to fund
17the cost of a project for which a sponsor is directly or indirectly
18liable, including, but not limited to, bonds, the security for which
19is provided in whole or in part pursuant to the powers granted by
20Section 63025; bonds for which the bank has provided a guarantee
21or enhancement, including, but not limited to, the purchase of the
22subordinated bonds of the sponsor, the subordinated bonds of a
23special purpose trust, or the retention of the subordinated bonds
24of the bank pursuant to Chapter 4 (commencing with Section
2563060); or any other type of assistance deemed appropriate by the
26bank or the sponsor, except that no direct loans shall be made to
27nonpublic entities other thanbegin delete in connection with the issuance of
28rate reduction bonds pursuant to a financing order orend delete
in connection
29withbegin delete aend delete financing for an economic development facility.

30For purposes of this subdivision, “grant” does not include grants
31made by the bank except when acting as an agent or intermediary
32for the distribution or packaging of financing available from
33federal, private, or other public sources.

begin delete

34(k) “Financing order” has the meaning set forth in Section 840
35of the Public Utilities Code.

end delete
begin delete

36(l)

end delete

37begin insert(k)end insert “Guarantee trust fund” means the California Infrastructure
38Guarantee Trust Fund.

begin delete

39(m)

end delete

P8    1begin insert(l)end insert “Infrastructure bank fund” means the California Infrastructure
2and Economic Development Bank Fund.

begin delete

3(n)

end delete

4begin insert(m)end insert “Loan agreement” means a contractual agreement executed
5between the bank or a special purpose trust and a sponsor that
6provides that the bank or special purpose trust will loan funds to
7the sponsor and that the sponsor will repay the principal and pay
8the interest and redemption premium, if any, on the loan.

begin delete

9(o)

end delete

10begin insert(n)end insert “Participating party” means any person, company,
11corporation, association, state or municipal governmental entity,
12partnership, firm, or other entity or group of entities, whether
13organized for profit or not for profit, engaged in business or
14operations within the state and that applies for financing from the
15bank in conjunction with a sponsor for the purpose of implementing
16a project.begin delete However, in the case of a project relating to the financing
17of transition costs or the acquisition of transition property, or both,
18on the request of an electrical corporation, or in connection with
19a financing for an economic development facility, or for the
20financing of insurance claims, the participating party shall be
21deemed to be the same entity as the sponsor for the financing.end delete

begin delete

22(p)

end delete

23begin insert(o)end insert “Project” means designing, acquiring, planning, permitting,
24entitling, constructing, improving, extending, restoring, financing,
25and generally developing public development facilities or economic
26development facilities within thebegin delete state or financing transition costs
27or the acquisition of transition property, or both, upon approval of
28a financing order by the Public Utilities Commission, as provided
29in Article 5.5 (commencing with Section 840) of Chapter 4 of Part
301 of Division 1 of the Public Utilities Code.end delete
begin insert state.end insert

begin delete

31(q)

end delete

32begin insert(p)end insert “Public development facilities” means real and personal
33property, structures, conveyances, equipment, thoroughfares,
34buildings, and supporting components thereof, excluding any
35housing, that are directly related to providing the following:

36(1) “City streets” including any street, avenue, boulevard, road,
37parkway, drive, or other way that is any of the following:

38(A) An existing municipal roadway.

39(B) Is shown upon a plat approved pursuant to law and includes
40the land between the street lines, whether improved or unimproved,
P9    1and may comprise pavement, bridges, shoulders, gutters, curbs,
2guardrails, sidewalks, parking areas, benches, fountains, plantings,
3lighting systems, and other areas within the street lines, as well as
4equipment and facilities used in the cleaning, grading, clearance,
5maintenance, and upkeep thereof.

6(2) “County highways” including any county highway as defined
7in Section 25 of the Streets and Highways Code, that includes the
8land between the highway lines, whether improved or unimproved,
9and may comprise pavement, bridges, shoulders, gutters, curbs,
10guardrails, sidewalks, parking areas, benches, fountains, plantings,
11lighting systems, and other areas within the street lines, as well as
12equipment and facilities used in the cleaning, grading, clearance,
13maintenance, and upkeep thereof.

14(3) “Drainage, water supply, and flood control” including, but
15not limited to, ditches, canals, levees, pumps, dams, conduits,
16pipes, storm sewers, and dikes necessary to keep or direct water
17away from people, equipment, buildings, and other protected areas
18as may be established by lawful authority, as well as the
19acquisition, improvement, maintenance, and management of
20floodplain areas and all equipment used in the maintenance and
21operation of the foregoing.

22(4) “Educational facilities” including libraries, child care
23facilities, including, but not limited to, day care facilities, and
24employment training facilities.

25(5) “Environmental mitigation measures” including required
26construction or modification of public infrastructure and purchase
27and installation of pollution control and noise abatement
28equipment.

29(6) “Parks and recreational facilities” including local parks,
30recreational property and equipment, parkways and property.

31(7) “Port facilities” including docks, harbors, ports of entry,
32piers, ships, small boat harbors and marinas, and any other
33facilities, additions, or improvements in connection therewith.

34(8) “Power and communications” including facilities for the
35transmission or distribution of electrical energy, natural gas, and
36telephone and telecommunications service.

37(9) “Public transit” including air and rail transport of goods,
38airports, guideways, vehicles, rights-of-way, passenger stations,
39maintenance and storage yards, and related structures, including
40public parking facilities, equipment used to provide or enhance
P10   1transportation by bus, rail, ferry, or other conveyance, either
2publicly or privately owned, that provides to the public general or
3special service on a regular and continuing basis.

4(10) “Sewage collection and treatment” including pipes, pumps,
5and conduits that collect wastewater from residential,
6manufacturing, and commercial establishments, the equipment,
7structures, and facilities used in treating wastewater to reduce or
8eliminate impurities or contaminants, and the facilities used in
9disposing of, or transporting, remaining sludge, as well as all
10equipment used in the maintenance and operation of the foregoing.

11(11) “Solid waste collection and disposal” including vehicles,
12vehicle-compatible waste receptacles, transfer stations, recycling
13centers, sanitary landfills, and waste conversion facilities necessary
14to remove solid waste, except that which is hazardous as defined
15by law, from its point of origin.

16(12) “Water treatment and distribution” including facilities in
17which water is purified and otherwise treated to meet residential,
18manufacturing, or commercial purposes and the conduits, pipes,
19and pumps that transport it to places of use.

20(13) “Defense conversion” including, but not limited to, facilities
21necessary for successfully converting military bases consistent
22with an adopted base reuse plan.

23(14) “Public safety facilities” including, but not limited to, police
24stations, fire stations, court buildings, jails, juvenile halls, and
25juvenile detention facilities.

26(15) “State highways” including any state highway as described
27in Chapter 2 (commencing with Section 230) of Division 1 of the
28Streets and Highways Code, and the related components necessary
29for safe operation of the highway.

30(16) (A) Military infrastructure, including, but not limited to,
31facilities on or near a military installation, that enhance the military
32operations and mission of one or more military installations in this
33state. To be eligible for funding, the project shall be endorsed by
34the Office of Military and Aerospace Support established pursuant
35to Section 13998.2.

36(B) For purposes of this subdivision, “military installation”
37means any facility under the jurisdiction of thebegin insert United Statesend insert
38 Department of Defense, as defined in paragraph (1) of subsection
39(e) of Section 2687 of Title 10 of the United States Code.

begin delete

P11   1(r) “Rate reduction bonds” has the meaning set forth in Section
2840 of the Public Utilities Code.

end delete
begin delete

3(s)

end delete

4begin insert(q)end insert “Revenues” means all receipts, purchase payments, loan
5repayments, lease payments, and all other income or receipts
6derived by the bank or a sponsor from the sale, lease, or other
7financing arrangement undertaken by the bank, a sponsor or a
8participating party, including, but not limited to, all receipts from
9a bond purchase agreement, and any income or revenue derived
10from the investment of any money in any fund or account of the
11bank or abegin delete sponsor and any receipts derived from transition property.end delete
12begin insert sponsor.end insert Revenues shall not include moneys in the General Fund
13of the state.

begin delete

14(t)

end delete

15begin insert(r)end insert “Special purpose trust” means a trust, partnership, limited
16partnership, association, corporation, nonprofit corporation, or
17other entity authorized under the laws of the state to serve as an
18instrumentality of the state to accomplish public purposes and
19authorized by the bank to acquire, by purchase or otherwise, for
20retention or sale, the bonds of a sponsor or of the bank made or
21entered into pursuant to this division and to issue special purpose
22trust bonds or other obligations secured by these bonds or other
23sources of public or private revenues.begin delete Special purpose trust also
24means any entity authorized by the bank to acquire transition
25property or to issue rate reduction bonds, or both, subject to the
26approvals by the bank and powers of the bank as are provided by
27the bank in its resolution authorizing the entity to issue rate
28reduction bonds.end delete

begin delete

29(u)

end delete

30begin insert(s)end insert “Sponsor” means any subdivision of the state or local
31government including departments, agencies, commissions, cities,
32counties, nonprofit corporations formed on behalf of a sponsor,
33special districts, assessment districts, and joint powers authorities
34within the state or any combination of these subdivisions that
35makes an application to the bank for financial assistance in
36connection with a project in a manner prescribed by the bank. This
37definition shall not be construed to require that an applicant have
38an ownership interest in the project. In addition,begin delete an electrical
39corporation shall be deemed to be the sponsor as well as the
40participating party for any project relating to the financing of
P12   1transition costs and the acquisition of transition property on the
2request of the electrical corporation andend delete
any person, company,
3corporation, partnership, firm, or other entity or group engaged in
4business or operation within the state that applies for financing of
5any economic development facility, shall be deemed to be the
6sponsor as well as the participating party for the project relating
7to the financing of that economic development facility.

begin delete

8(v)

end delete

9begin insert(t)end insert “State” means the State of California.

begin delete

10(w) “Transition costs” has the meaning set forth in Section 840
11of the Public Utilities Code.

end delete
begin delete

12(x) “Transition property” has the meaning set forth in Section
13840 of the Public Utilities Code.

end delete
14begin insert

begin insertSEC. 2.end insert  

end insert

begin insertSection 63025.1 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
15to read:end insert

16

63025.1.  

The bank board may do or delegate the following to
17the executive director:

18(a) Sue and be sued in its own name.

19(b) As provided in Chapter 5 (commencing with Section 63070),
20issue bonds and authorize special purpose trusts to issue bonds,
21including, at the option of the board, bonds bearing interest that
22is taxable for the purpose of federal income taxation, or borrow
23money to pay all or any part of the cost of any project, or to
24otherwise carry out the purposes of this division.

25(c) Engage the services of private consultants to render
26professional and technical assistance and advice in carrying out
27the purposes of this division.

28(d) Employ attorneys, financial consultants, and other advisers
29as may, in the bank’s judgment, be necessary in connection with
30the issuance and sale, or authorization of special purpose trusts for
31the issuance and sale, of any bonds, notwithstanding Sections
3211042 and 11043.

33(e) Contract for engineering, architectural, accounting, or other
34services of appropriate state agencies as may, in its judgment, be
35necessary for the successful development of a project.

36(f) Pay the reasonable costs of consulting engineers, architects,
37accountants, and construction, land use, recreation, and
38environmental experts employed by any sponsor or participating
39party if, in the bank’s judgment, those services are necessary for
40the successful development of a project.

P13   1(g) Acquire, take title to, and sell by installment sale or
2otherwise, lands, structures, real or personal property, rights,
3rights-of-way, franchises, easements, and other interests in lands
4that are located within the state,begin delete or transition propertyend delete as the bank
5may deem necessary or convenient for the financing of the project,
6upon terms and conditions that it considers to be reasonable.

7(h) Receive and accept from any source including, but not
8limited to, the federal government, the state, or any agency thereof,
9loans, contributions, or grants, in money, property, labor, or other
10things of value, for, or in aid of, a project, or any portion thereof.

11(i) Make loans to any sponsor or participating party, either
12directly or by making a loan to a lending institution, in connection
13with the financing of a project in accordance with an agreement
14between the bank and the sponsor or a participating party, either
15as a sole lender or in participation with other lenders. However,
16no loan shall exceed the total cost of the project as determined by
17the sponsor or the participating party and approved by the bank.

18(j) Make loans to any sponsor or participating party, either
19directly or by making a loan to a lending institution, in accordance
20with an agreement between the bank and the sponsor or
21participating party to refinance indebtedness incurred by the
22sponsor or participating party in connection with projects
23undertaken and completed prior to any agreement with the bank
24or expectation that the bank would provide financing, either as a
25sole lender or in participation with other lenders.

26(k) Mortgage all or any portion of the bank’s interest in a project
27and the property on which any project is located, whether owned
28or thereafter acquired, including the granting of a security interest
29in any property, tangible or intangible.

30(l) Assign or pledge all or any portion of the bank’s interests in
31begin delete transition property and the revenues therefrom, orend delete assets, things
32of value, mortgages, deeds of trust, bonds, bond purchase
33agreements, loan agreements, indentures of mortgage or trust, or
34similar instruments, notes, and security interests in property,
35tangible or intangible and the revenues therefrom, of a sponsor or
36a participating party to which the bank has made loans, and the
37revenues therefrom, including payment or income from any interest
38owned or held by the bank, for the benefit of the holders of bonds.

39(m) Make, receive, or serve as a conduit for the making of, or
40otherwise provide for, grants, contributions, guarantees, insurance,
P14   1credit enhancements or liquidity facilities, or other financial
2enhancements to a sponsor or a participating party as financial
3assistance for a project.

4(n) Lease the project being financed to a sponsor or a
5participating party, upon terms and conditions that the bank deems
6 proper but shall not be leased at a loss; charge and collect rents
7therefor; terminate any lease upon the failure of the lessee to
8comply with any of the obligations thereof; include in any lease,
9if desired, provisions that the lessee shall have options to renew
10the lease for a period or periods, and at rents determined by the
11bank; purchase any or all of the project; or, upon payment of all
12the indebtedness incurred by the bank for the financing of the
13project, the bank may convey any or all of the project to the lessee
14or lessees.

15(o) Charge and equitably apportion among sponsors and
16participating parties the bank’s administrative costs and expenses
17incurred in the exercise of the powers and duties conferred by this
18division.

19(p) Issue, obtain, or aid in obtaining, from any department or
20agency of the United States, from other agencies of the state, or
21from any private company, any insurance or guarantee to, or for,
22the payment or repayment of interest or principal, or both, or any
23part thereof, on any loan, lease, or obligation or any instrument
24evidencing or securing the same, made or entered into pursuant to
25this division.

26(q) Notwithstanding any other provision of this division, enter
27into any agreement, contract, or any other instrument with respect
28to any insurance or guarantee; accept payment in the manner and
29form as provided therein in the event of default by a sponsor or a
30participating party; and issue or assign any insurance or guarantee
31as security for the bank’s bonds.

32(r) Enter into any agreement or contract, execute any instrument,
33and perform any act or thing necessary or convenient to, directly
34or indirectly, secure the bank’s bonds, the bonds issued by a special
35purpose trust, or a sponsor’s obligations to the bank or to a special
36 purpose trust, including, but not limited to, bonds of a sponsor
37purchased by the bank or a special purpose trust for retention or
38sale, with funds or moneys that are legally available and that are
39due or payable to the sponsor by reason of any grant, allocation,
40apportionment or appropriation of the state or agencies thereof, to
P15   1the extent that the Controller shall be the custodian at any time of
2these funds or moneys, or with funds or moneys that are or will
3be legally available to the sponsor, the bank, or the state or any
4agencies thereof by reason of any grant, allocation, apportionment,
5or appropriation of the federal government or agencies thereof;
6and in the event of written notice that the sponsor has not paid or
7is in default on its obligations to the bank or a special purpose
8trust, direct the Controller to withhold payment of those funds or
9moneys from the sponsor over which it is or will be custodian and
10to pay the same to the bank or special purpose trust or their
11assignee, or direct the state or any agencies thereof to which any
12grant, allocation, apportionmentbegin insert,end insert or appropriation of the federal
13government or agencies thereof is or will be legally available to
14pay the same upon receipt by the bank or special purpose trust or
15their assignee, until the default has been cured and the amounts
16then due and unpaid have been paid to the bank or special purpose
17trust or their assignee, or until arrangements satisfactory to the
18bank or special purpose trust have been made to cure the default.

19(s) Enter into any agreement or contract, execute any instrument,
20and perform any act or thing necessary, convenient, or appropriate
21to carry out any power expressly given to the bank by this division,
22including, but not limited to, agreements for the sale of all or any
23part, including principal, interest, redemption rightsbegin insert,end insert or any other
24rights or obligations, of bonds of the bank or of a special purpose
25trust, liquidity agreements, contracts commonly known as interest
26rate swap agreements, forward payment conversion agreements,
27futures or contracts providing for payments based on levels of, or
28changes in, interest rates or currency exchange rates, or contracts
29to exchange cash-flows or a series of payments, or contracts,
30including options, puts or calls to hedge payments, rate, spread,
31currency exchange, or similar exposure, or any other financial
32instrument commonly known as a structured financial product.

33(t) Purchase, with the proceeds of the bank’s bonds, transition
34property or bonds issued by, or for the benefit of, any sponsor in
35connection with a project, pursuant to a bond purchase agreement
36or otherwise. Bonds or transition property purchased pursuant to
37this division may be held by the bank, pledged or assigned by the
38bank, or sold to public or private purchasers at public or negotiated
39sale, in whole or in part, separately or together with other bonds
P16   1issued by the bank, and notwithstanding any other provision of
2law, may be bought by the bank at private sale.

3(u) Enter into purchase and sale agreements with all entities,
4public and private, including state and local government pension
5funds, with respect to the sale or purchase ofbegin delete bonds or transition
6property.end delete
begin insert bonds.end insert

7(v) Invest any moneys held in reserve or sinking funds, or any
8moneys not required for immediate use or disbursement, in
9obligations that are authorized by law for the investment of trust
10funds in the custody of the Treasurer.

11(w) Authorize a special purpose trust or trusts to purchase or
12retain, with the proceeds of the bonds of a special purpose trust,
13transition property or bonds issued by, or for the benefit of, any
14sponsor in connection with a project or issued by the bank or a
15special purpose trust, pursuant to a bond purchase agreement or
16otherwise. Bonds or transition property purchased pursuant to this
17title may be held by a special purpose entity, pledged or assigned
18by a special purpose entity, or sold to public or private purchasers
19at public or negotiated sale, in whole or in part, with or without
20structuring, subordinationbegin insert,end insert or credit enhancement, separately or
21together with other bonds issued by a special purpose trust, and
22notwithstanding any other provision of law, may be bought by the
23bank or by a special purpose trust at private sale.

24(x) Approve the issuance of any bonds, notes, or other evidences
25of indebtedness by the Rural Economic Development Infrastructure
26Panel, established pursuant to Section 15373.7.

begin delete

27(y) Approve the issuance of rate reduction bonds by an entity
28other than the bank or a special purpose trust to acquire transition
29property upon approval of the transaction in a financing order by
30the Public Utilities Commission, as provided in Article 5.5
31(commencing with Section 840) of Chapter 4 of Part 1 of Division
321 of the Public Utilities Code.

end delete
begin delete

33(z)

end delete

34begin insert(y)end insert Apply for and accept subventions, grants, loans, advances,
35and contributions from any source of money, property, labor, or
36other things of value. The sources may include bond proceeds,
37dedicated taxes, state appropriations, federal appropriations, federal
38grant and loan funds, public and private sector retirement system
39funds, and proceeds of loans from the Pooled Money Investment
40Account.

begin delete

P17   1(aa)

end delete

2begin insert(z)end insert Do all things necessary and convenient to carry out its
3purposes and exercise its powers, provided, however, that nothing
4herein shall be construed to authorize the bank to engage directly
5in the business of a manufacturing, industrial, real estate
6development, or nongovernmental service enterprise. Further, the
7bank shall not be organized to accept deposits of money for time
8or demand deposits or to constitute a bank or trust company.

9begin insert

begin insertSEC. 3.end insert  

end insert

begin insertSection 63041.5 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
10to read:end insert

11

63041.5.  

(a) It is the intent of the Legislature to provide a
12one-time appropriation for financial assistance to local government
13to meet capital outlay and infrastructure needs.

14(b) From the funds appropriated in Item 2920-111-0001 of the
15Budget Act of 1999, the sum of four hundred twenty-five million
16dollars ($425,000,000) shall be available for financial assistance,
17including, but not limited to, leveraged revolving fund loans, to
18local government sponsors for public development facilities, as
19specified in subdivisionbegin delete (q)end deletebegin insert (p)end insert of Section 63010 of the Government
20Code.

21(c) From the funds appropriated in Item 2920-111-0001 of the
22Budget Act of 1999 and in Item 2920-111-0001 of the Budget Act
23of 1998begin delete (Chapter 324 of the Statutes ofend deletebegin insert (Ch. 324, Stats.end insert 1998), the
24California Infrastructure and Economic Development Bank shall
25make no single loan in excess of 10 percent of the combined
26amount of these appropriations to the bank unless approved by
27unanimous consent of the membership of the Board of Directors
28of the California Infrastructure and Economic Development Bank
29and the Director of Finance provides a 30-day written notice to
30the Chairperson and Vice-Chairperson of the Joint Legislative
31Budget Committee.

32begin insert

begin insertSEC. 4.end insert  

end insert

begin insertArticle 4 (commencing with Section 63042) of Chapter
332 of Division 1 of Title 6.7 of the end insert
begin insertGovernment Codeend insertbegin insert is repealed.end insert

34begin insert

begin insertSEC. 5.end insert  

end insert

begin insertSection 63043 of the end insertbegin insertGovernment Codeend insertbegin insert is amended to
35read:end insert

36

63043.  

Notwithstanding any other provision of this division,
37Article 3 (commencing with Section 63040)begin delete and Article 4
38(commencing with Section 63042),end delete
shall not apply to any conduit
39financing for economic development facilities by the bank directly
40for the benefit of a participating party.

P18   1begin insert

begin insertSEC. 6.end insert  

end insert

begin insertSection 63048.3 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
2to read:end insert

3

63048.3.  

Notwithstanding any other provision of this division,
4Article 3 (commencing with Sectionbegin delete 63040), Article 4
5(commencing with Article 63042),end delete
begin insert 63040)end insert and Article 5
6(commencing with Section 63043) do not apply to any financing
7provided by the bank to, or at the request of, the board in
8connection with the revolving fund.

9begin insert

begin insertSEC. 7.end insert  

end insert

begin insertSection 63048.56 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
10to read:end insert

11

63048.56.  

Notwithstanding any other law, Article 3
12(commencing with Sectionbegin delete 63040), Article 4 (commencing with
13Section 63042),end delete
begin insert 63040)end insert and Article 5 (commencing with Section
1463043) shall not apply to any financing provided by the bank to,
15or at the request of, the department in connection with the revolving
16fund.

17begin insert

begin insertSEC. 8.end insert  

end insert

begin insertSection 63048.7 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
18to read:end insert

19

63048.7.  

Notwithstanding any other provision of this division,
20Article 3 (commencing with Sectionbegin delete 63040), Article 4
21(commencing with Section 63042),end delete
begin insert 63040)end insert and Article 5
22(commencing with Section 63043) do not apply to any bonds issued
23by the special purpose trust established by this article. All matters
24authorized in this article are in addition to powers granted to the
25bank in this division.

26begin insert

begin insertSEC. 9.end insert  

end insert

begin insertSection 63049.2 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
27to read:end insert

28

63049.2.  

Notwithstanding any other provision of this division,
29Article 3 (commencing with Sectionbegin delete 63040), Article 4
30(commencing with Section 63042),end delete
begin insert 63040)end insert and Article 5
31(commencing with Section 63043) do not apply to any bonds issued
32by the special purpose trust established by this article. All matters
33authorized in this article are in addition to powers granted to the
34bank in this division.

35begin insert

begin insertSEC. 10.end insert  

end insert

begin insertSection 63049.62 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
36to read:end insert

37

63049.62.  

Notwithstanding any other provision of this division,
38a financing of the costs of claims of insolvent insurers upon the
39request of the association pursuant to Section 1063.73 of the
40Insurance Code shall be deemed to be in the public interest and
P19   1eligible for financing by the bank, and Article 3 (commencing with
2Section 63040),begin delete Article 4 (commencing with Section 63042),end delete
3 Article 5 (commencing with Section 63043), Article 6
4(commencing with Section 63048), and Article 7 (commencing
5with Section 63049) shall not apply to the financing provided by
6the bank to, or at the request of, the association or the department
7in connection with the fund. Notwithstanding any other provision
8of this division, the bank shall have no authority over any matter
9that is subject to the approval of the Insurance Commissioner under
10Article 14.2 (commencing with Section 1063) of Chapter 1 of Part
112 of Division 1 of the Insurance Code.

12begin insert

begin insertSEC. 11.end insert  

end insert

begin insertSection 63049.64 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
13to read:end insert

14

63049.64.  

(a) The bank may issue bonds pursuant to Chapter
155 (commencing with Section 63070) and may loan the proceeds
16thereof to the association, and deposit the proceeds into a separate
17account in the fund, or use the proceeds to refund bonds previously
18issued under this article. Bond proceeds may also be used to fund
19necessary reserves, capitalized interest, credit enhancement costs,
20or costs of issuance.

21(b) Bonds issued under this article shall not be deemed to
22constitute a debt or liability of the state or of any political
23subdivision thereof, other than the bank, or a pledge of the faith
24and credit of the state or of any political subdivision, but shall be
25payable solely from the fund and other revenues and assets securing
26the bonds. All bonds issued under this article shall contain on the
27face of the bonds a statement to that effect.

28(c) For purposes of this article, the term “project,” as defined
29in subdivisionbegin delete (p)end deletebegin insert (o)end insert of Section 63010, shall include financing of
30the costs of claims of insolvent workers’ compensation insurers,
31in an amount (together with associated costs of financing) that
32may be determined by the association in making a request for
33financing to the bank.

34begin insert

begin insertSEC. 12.end insert  

end insert

begin insertSection 63049.67 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
35to read:end insert

36

63049.67.  

(a) Notwithstanding any other provision of this
37division, a financing of emergency apportionments upon the request
38of a school district pursuant to Article 2.7 (commencing with
39Section 41329.50) of Chapter 3 of Part 24 of Division 3 of Title
402 of the Education Code, is deemed to be in the public interest and
P20   1eligible for financing by the bank. Article 3 (commencing with
2Sectionbegin delete 63040), Article 4 (commencing with Section 63042),end delete
3begin insert 63040)end insert and Article 5 (commencing with Section 63043) do not
4apply to the financing provided by the bank in connection with an
5emergency apportionment.

6(b) The bank may issue bonds pursuant to Chapter 5
7(commencing with Section 63070) and provide the proceeds to a
8school district pursuant to a lease agreement. The proceeds may
9be used as an emergency apportionment, to reimburse the interim
10emergency apportionment from the General Fund authorized
11pursuant to subdivision (b) of Section 41329.52 of the Education
12Code, or to refund bonds previously issued under this section.
13Bond proceeds may also be used to fund necessary reserves,
14capitalized interest, credit enhancement costs, and costs of issuance.

15(c) Bonds issued under this article are not deemed to constitute
16a debt or liability of the state or of any political subdivision of the
17state, other than a limited obligation of the bank, or a pledge of
18the faith and credit of the state or of any political subdivision. All
19bonds issued under this article shall contain on the face of the
20bonds a statement to the same effect.

21(d) Any fund or account established in connection with the
22bonds shall be established outside of the centralized treasury
23system. Notwithstanding any other law, the bank shall select the
24financing team and the trustee for the bonds, and the trustee shall
25be a corporation or banking association authorized to exercise
26corporate trust powers.

27(e) Pursuant to Section 41329.55 of the Education Code, a school
28district other than the Compton Community College District shall
29instruct the Controller to repay the lease from moneys in the State
30School Fund and the Education Protection Account designated for
31apportionment to the school district. Pursuant to Section 41329.55
32of the Education Code, if the school district is the Compton
33Community College District, the Controller shall be instructed to
34repay the lease from moneys in Section B of the State School Fund.
35Any amounts necessary to make this repayment shall be drawn
36from the total statewide funding available for community college
37apportionment consisting of funds in Section B of the State School
38Fund. Thereafter the Controller shall transfer to Section B of the
39State School Fund, either in a single or multiple transfers, an
40amount equal to the total repayment, which amount shall be
P21   1transferred from the amount designated for apportionment to the
2Compton Community College District from the State School Fund.
3If these transfers from the district prove inadequate to repay any
4repayments for any reason, the Compton Community College
5District is required to use any revenue sources available to it for
6transfer and repayment purposes.

7(f) Notwithstanding any other law, as long as any bonds issued
8pursuant to this section are outstanding, the following requirements
9apply:

10(1) The school district for which the bonds were issued is not
11eligible to be a debtor in a case under Chapter 9 of the United
12States Bankruptcy Code, as it may be amended from time to time,
13and no governmental officer or organization is or may be
14empowered to authorize the school district to be a debtor under
15that chapter.

16(2) It is the intent of the Legislature that the Legislature should
17not in the future abolish the Compton Community College District
18or take any action that would prevent the Compton Community
19Collegebegin insert Districtend insert from entering into or performing binding
20agreements or invalidate any prior binding agreements of the
21Compton Community College District, where invalidation may
22have a material adverse effect on the bonds issued pursuant to this
23section.

24(3) The Compton Community College District shall not be
25 reorganized or merged with another community college district
26unless all of the following apply:

27(A) The successor district becomes by operation of law the
28owner of all property previously owned by the Compton
29Community College District.

30(B) Any agreement entered into by the Compton Community
31College District in connection with bonds issued pursuant to this
32section are assumed by the successor district.

33(C) The apportionment authorized by subdivision (e) remains
34in effect.

35(D) Receipt by the bank of an opinion of bond counsel that the
36bonds issued for the Compton Community College District will
37remain tax exempt following the reorganization or merger.

38(g) Nothing in this section limits the authority of the Legislature
39to abolish the Compton Community College District when bonds
40issued for that district are no longer outstanding. Further, the
P22   1Legislature may provide for the redemption or defeasance of the
2bonds at any time so that no bonds are outstanding. If the
3Legislature provides for the redemption or defeasance of the bonds
4issued for the Compton Community College District in order to
5abolish that district, it is the intent of the Legislature that the funds
6required for the redemption or defeasance should be appropriated
7from Section B of the State School Fund.

8(h) The bank may enter into contracts or agreements with banks,
9insurers, or other financial institutions or parties that it determines
10are necessary or desirable to improve the security and marketability
11of, or to manage interest rates or other risks associated with, the
12bonds issued pursuant to this section. The bank may pledge
13apportionments made by the Controller directly to the bond trustee
14pursuant to Section 41329.55 of the Education Code as security
15for repayment of any obligation owed to a bank, insurer, or other
16financial institution pursuant to this subdivision.

17begin insert

begin insertSEC. 13.end insert  

end insert

begin insertSection 63071 of the end insertbegin insertGovernment Codeend insertbegin insert is amended
18to read:end insert

19

63071.  

(a) Notwithstanding any other provision of law, but
20consistent with Sections 1 and 18 of Article XVI of the California
21Constitution, a sponsor may issue bonds for purchase by the bank
22pursuant to a bond purchase agreement. The bank may issue bonds
23or authorize a special purpose trust to issue bonds. These bonds
24may be issued pursuant to the charter of any city or any city and
25county that authorized the issuance of these bonds as a sponsor
26and may also be issued by any sponsor pursuant to the Revenue
27Bond Law of 1941 (Chapter 6 (commencing with Section 54300)
28of Division 2 of Title 5) to pay the costs and expenses pursuant to
29this title, subject to the following conditions:

30(1) With the prior approval of the bank, the sponsor may sell
31these bonds in any manner as it may determine, either by private
32sale or by means of competitive bid.

33(2) Notwithstanding Section 54418, the bonds may be sold at
34a discount at any rate as the bank and sponsor shall determine.

35(3) Notwithstanding Section 54402, the bonds shall bear interest
36at any rate and be payable at any time as the sponsor shall
37determine with the consent of the bank.

38(b) The total amount of bonds issued to finance public
39development facilities that may be outstanding at any one time
40under this chapter shall not exceed five billion dollars
P23   1($5,000,000,000).begin delete The total amount of rate reduction bonds that
2may be outstanding at any one time under this chapter shall not
3exceed ten billion dollars ($10,000,000,000).end delete

4(c) Bonds for which moneys or securities have been deposited
5in trust, in amounts necessary to pay or redeem the principal,
6interest, and any redemption premium thereon, shall be deemed
7not to be outstanding for purposes of this section.

8begin insert

begin insertSEC. 14.end insert  

end insert

begin insertSection 330 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
9

330.  

In order to provide guidance in carrying out this chapter,
10the Legislature finds and declares all of the following:

11(a) It is the intent of the Legislature that a cumulative rate
12reduction of at least 20 percent be achieved not later than April 1,
132002, for residential and small commercial customers, from the
14rates in effect on June 10, 1996. In determining that the April 1,
152002, rate reduction has been met, the commission shall exclude
16the costs of the competitively procured electricity and the costs
17associated with the rate reduction bonds, as defined in Section
18840.

19(b) The people, businesses, and institutions of California spend
20nearly twenty-three billion dollars ($23,000,000,000) annually on
21electricity, so that reductions in the price of electricity would
22significantly benefit the economy of the state and its residents.

23(c) The Public Utilities Commission has opened rulemaking
24and investigation proceedings with regard to restructuring
25California’s electric power industry and reforming utility
26regulation.

27(d) The commission has found, after an extensive public review
28process, that the interests of ratepayers and the state as a whole
29will be best served by moving from the regulatory framework
30existing on January 1, 1997, in which retail electricity service is
31provided principally by electrical corporations subject to an
32obligation to provide ultimate consumers in exclusive service
33territories with reliable electric service at regulated rates, to a
34framework under which competition would be allowed in the
35supply of electric power and customers would be allowed to have
36the right to choose their supplier of electric power.

37(e) Competition in the electric generation market will encourage
38innovation, efficiency, and better service from all market
39participants, and will permit the reduction of costly regulatory
40oversight.

P24   1(f) The delivery of electricity over transmission and distribution
2systems is currently regulated, and will continue to be regulated
3to ensure system safety, reliability, environmental protection, and
4fair access for all market participants.

5(g) Reliable electric service is of utmost importance to the safety,
6health, and welfare of the state’s citizenry and economy. It is the
7intent of the Legislature that electric industry restructuring should
8enhance the reliability of the interconnected regional transmission
9systems, and provide strong coordination and enforceable protocols
10for all users of the power grid.

11(h) It is important that sufficient supplies of electric generation
12will be available to maintain the reliable service to the citizens and
13businesses of the state.

14(i) Reliable electric service depends on conscientious inspection
15and maintenance of transmission and distribution systems. To
16continue and enhance the reliability of the delivery of electricity,
17the Independent System Operator and the commission, respectively,
18should set inspection, maintenance, repair, and replacement
19standards.

20(j) It is the intent of the Legislature that California enter into a
21compact with western region states. That compact should require
22the publicly and investor-owned utilities located in those states,
23that sell energy to California retail customers, to adhere to
24enforceable standards and protocols to protect the reliability of the
25interconnected regional transmission and distribution systems.

26(k) In order to achieve meaningful wholesale and retail
27competition in the electric generation market, it is essential to do
28all of the following:

29(1) Separate monopoly utility transmission functions from
30competitive generation functions, through development of
31independent, third-party control of transmission access and pricing.

32(2) Permit all customers to choose from among competing
33suppliers of electric power.

34(3) Provide customers and suppliers with open,
35nondiscriminatory, and comparable access to transmission and
36distribution services.

37(l) The commission has properly concluded that:

38(1) This competition will best be introduced by the creation of
39an Independent System Operator and an independent Power
40Exchange.

P25   1(2) Generation of electricity should be open to competition.

2(3) There is a need to ensure that no participant in these new
3market institutions has the ability to exercise significant market
4power so that operation of the new market institutions would be
5distorted.

6(4) These new market institutions should commence
7simultaneously with the phase in of customer choice, and the public
8will be best served if these institutions and the nonbypassable
9transition cost recovery mechanism referred to in subdivisions (s)
10to (w), inclusive, are in place simultaneously and no later than
11January 1, 1998.

12(m) It is the intention of the Legislature that California’s publicly
13owned electric utilities and investor-owned electric utilities should
14commit control of their transmission facilities to the Independent
15System Operator. These utilities should jointly advocate to the
16Federal Energy Regulatory Commission a pricing methodology
17for the Independent System Operator that results in an equitable
18return on capital investment in transmission facilities for all
19Independent System Operator participants.

20(n) Opportunities to acquire electric power in the competitive
21market must be available to California consumers as soon as
22practicable, but no later than January 1, 1998, so that all customers
23can share in the benefits of competition.

24(o) Under the existing regulatory framework, California’s
25electrical corporations were granted franchise rights to provide
26electricity to consumers in their service territories.

27(p) Consistent with federal and state policies, California
28electrical corporations invested in power plants and entered into
29contractual obligations in order to provide reliable electrical service
30on a nondiscriminatory basis to all consumers within their service
31territories who requested service.

32(q) The cost of these investments and contractual obligations
33are currently being recovered in electricity rates charged by
34electrical corporations to their consumers.

35(r) Transmission and distribution of electric power remain
36essential services imbued with the public interest that are provided
37over facilities owned and maintained by the state’s electrical
38corporations.

39(s) It is proper to allow electrical corporations an opportunity
40to continue to recover, over a reasonable transition period, those
P26   1costs and categories of costs for generation-related assets and
2 obligations, including costs associated with any subsequent
3renegotiation or buyout of existing generation-related contracts,
4that the commission, prior to December 20, 1995, had authorized
5for collection in rates and that may not be recoverable in market
6prices in a competitive generation market, and appropriate additions
7incurred after December 20, 1995, for capital additions to
8generating facilities existing as of December 20, 1995, that the
9commission determines are reasonable and should be recovered,
10provided that the costs are necessary to maintain those facilities
11through December 31, 2001. In determining the costs to be
12recovered, it is appropriate to net the negative value of above
13market assets against the positive value of below market assets.

14(t) The transition to a competitive generation market should be
15orderly, protect electric system reliability, provide the investors
16in these electrical corporations with a fair opportunity to fully
17recover the costs associated with commission approved
18generation-related assets and obligations, and be completed as
19expeditiously as possible.

20(u) The transition to expanded customer choice, competitive
21markets, and performance based ratemaking as described in
22Decision 95-12-063, as modified by Decision 96-01-009, of the
23Public Utilities Commission, can produce hardships for employees
24who have dedicated their working lives to utility employment. It
25is preferable that any necessary reductions in the utility workforce
26directly caused by electrical restructuring, be accomplished through
27offers of voluntary severance, retraining, early retirement,
28outplacement, and related benefits. Whether workforce reductions
29are voluntary or involuntary, reasonable costs associated with these
30sorts of benefits should be included in the competition transition
31charge.

32(v) Charges associated with the transition should be collected
33over a specific period of time on a nonbypassable basis and in a
34manner that does not result in an increase in rates to customers of
35electrical corporations. In order to insulate the policy of
36nonbypassability against incursions, if exemptions from the
37competition transition charge are granted, a firewall shall be created
38that segregates recovery of the cost of exemptions as follows:

39(1) The cost of the competition transition charge exemptions
40granted to members of the combined class of residential and small
P27   1commercial customers shall be recovered only from those
2customers.

3(2) The cost of the competition transition charge exemptions
4granted to members of the combined class of customers other than
5residential and small commercial customers shall be recovered
6only from those customers. The commission shall retain existing
7cost allocation authority provided that the firewall and rate freeze
8principles are not violated.

9(w) It is the intent of the Legislature to require and enable
10electrical corporations to monetize a portion of the competition
11transition charge for residential and small commercial consumers
12so that these customers will receive rate reductions of no less than
1310 percent for 1998 continuing through 2002. Electrical
14corporations shall, by June 1, 1997, or earlier, secure the means
15to finance the competition transition charge by applying
16concurrently for financing orders from the Public Utilities
17Commission and for rate reduction bonds from the California
18Infrastructure and Economic Development Bank.

19(x) California’s public utility electrical corporations provide
20substantial benefits to all Californians, including employment and
21support of the state’s economy. Restructuring the electric services
22industry pursuant to the act that added this chapter will continue
23these benefits, and will also offer meaningful and immediate rate
24reductions for residential and small commercial customers, and
25facilitate competition in the supply of electric power.

end delete
26begin insert

begin insertSEC. 15.end insert  

end insert

begin insertSection 331 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
27to read:end insert

28

331.  

The definitions set forth in this section shall govern the
29construction of this chapter.

30(a) “Aggregator” means any marketer, broker, public agency,
31city, county, or special district, that combines the loads of multiple
32end-use customers in facilitating the sale and purchase of electric
33energy, transmission, and other services on behalf of these
34customers.

35(b) “Broker” means an entity that arranges the sale and purchase
36of electric energy, transmission, and other services between buyers
37and sellers, but does not take title to any of the power sold.

38(c) “Direct transaction” means a contract between any one or
39more electric generators, marketers, or brokers of electric power
P28   1and one or more retail customers providing for the purchase and
2sale of electric power or any ancillary services.

begin delete

3(d) “Fire wall” means the line of demarcation separating
4residential and small commercial customers from all other
5customers as described in subdivision (e) of Section 367.

end delete
begin delete

6(e)

end delete

7begin insert(d)end insert “Marketer” means any entity that buys electric energy,
8transmission, and other services from traditional utilities and other
9suppliers, and then resells those services at wholesale or to an
10end-use customer.

begin delete

11(f)

end delete

12begin insert(e)end insert “Microcogeneration facility” means a cogeneration facility
13of less than one megawatt.

begin delete

14(g) “Restructuring trusts” means the two tax-exempt public
15benefit trusts established by Decision 96-08-038 of the Public
16Utilities Commission to provide for design and development of
17the hardware and software systems for the Power Exchange and
18the Independent System Operator, respectively, and that may
19undertake other activities, as needed, as ordered by the commission.

end delete
begin delete

20(h)

end delete

21begin insert(f)end insert “Small commercial customer” means a customer that has a
22maximum peak demand of less than 20 kilowatts.

23begin insert

begin insertSEC. 16.end insert  

end insert

begin insertSection 332.1 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
24to read:end insert

25

332.1.  

(a) (1) It is the intent of the Legislature to enact Item
261 (revised) on the commission’s August 21, 2000begin insert,end insert agenda, entitled
27“Opinion Modifying Decision (D.) D.00-06-034 and D.00-08-021
28to Regarding Interim Rate Caps for San Diego Gas and Electric
29Company,” as modified below.

30(2) It is also the intent of the Legislature that to the extent that
31the Federal Energy Regulatory Commission orders refunds to
32electrical corporations pursuant to their findings, the commission
33shall ensure that any refunds are returned to customers.

34(b) The commission shall establish a ceiling of six and
35five-tenths cents ($0.065) per kilowatthour on the energy
36component of electric bills for electricity supplied to residential,
37small commercial, and street lighting customers by the San Diego
38Gas and Electric Company, through December 31, 2002, retroactive
39to June 1, 2000. If the commission finds it in the public interest,
P29   1this ceiling may be extended through December 2003 and may be
2adjusted as provided in subdivision (d).

3(c) The commission shall establish an accounting procedure to
4track and recover reasonable and prudent costs of providing electric
5energy to retail customers unrecovered through retail bills due to
6the application of the ceiling provided for in subdivision (b). The
7accounting procedure shall utilize revenues associated with sales
8of energy from utility-owned or managed generation assets to
9offset an undercollection, if undercollection occurs. The accounting
10procedure shall be reviewed periodically by the commission, but
11not less frequently than semiannually. The commission may utilize
12an existing proceeding to perform the review. The accounting
13procedure and review shall provide a reasonable opportunity for
14San Diego Gas and Electric Company to recover its reasonable
15and prudent costs of service over a reasonable period of time.

16(d) If the commission determines that it is in the public interest
17to do so, the commission, after the date of the completion of the
18proceeding described in subdivision (g), may adjust the ceiling
19from the level specified in subdivision (b), and may adjust the
20frozen rate from the levels specified in subdivision (f), consistent
21with the Legislature’s intent to provide substantial protections for
22customers of the San Diego Gas and Electric Company and their
23interest in just and reasonable rates and adequate service.

24(e) For purposes of this section, “small commercial customer”
25includes, but is not limited to, all San Diego Gas and Electric
26Company accounts on Rate Schedule A of the San Diego Gas and
27Electric Company, all accounts of customers who are “general
28acute care hospitals,” as defined in Section 1250 of the Health and
29Safety Code, all San Diego Gas and Electric Company accounts
30of customers who are public or private schools for pupils in
31kindergarten or any of grades 1 to 12, inclusive, and all accounts
32on Rate Schedule AL-TOU under 100 kilowatts.

33(f) The commission shall establish an initial frozen rate of six
34and five-tenths cents ($0.065) per kilowatthour on the energy
35component of electric bills for electricity supplied to all customers
36by the San Diego Gas and Electric Company not subject to
37subdivision (b), for the time period ending with the end of the rate
38freeze for the Pacific Gas and Electric Company and the Southern
39California Edison Companybegin delete pursuant to Section 368end delete, retroactive
40to February 7, 2001. The commission shall consider the comparable
P30   1energy components of rates for comparable customer classes served
2by the Pacific Gas and Electric Company and the Southern
3California Edison Company and, if it determines it to be in the
4public interest, the commission may adjust this frozen rate, and
5may do so, retroactive to the date that rate increases took effect
6for customers of Pacific Gas and Electric Company and Southern
7California Edison Company pursuant to the commission’s March
827, 2001, decision. The commission shall determine the Fixed
9Department of Water Resources Set-Aside pursuant to Section
10360.5 for customers subject to this section, reflecting a retail rate
11consistent with the rate for the energy component of electric bills
12as determined in this subdivision, in place of the retail rate in effect
13on January 5, 2001. This section shall be construed to modify the
14payment provisions, but may not be construed to modify the
15electric procurement obligations of the Department of Water
16Resources, pursuant to any contract or agreement in accordance
17with Division 27 (commencing with Section 80000) of the Water
18Code, and in effect as of February 7, 2001, between the Department
19of Water Resources and San Diego Gas and Electric Company.

20(g) The commission shall institute a proceeding to examine the
21prudence and reasonableness of the San Diego Gas and Electric
22Company in the procurement of wholesale energy on behalf of its
23customers, for a period beginning, at the latest, on June 1, 2000.
24If the commission finds that San Diego Gas and Electric Company
25acted imprudently or unreasonably, the commission shall issue
26orders that it determines to be appropriate affecting the retail rates
27of San Diego Gas and Electric Company customers including, but
28not limited to, refunds.

29(h) Nothing in this section may be construed to limit the
30authority of the Department of Water Resources pursuant to
31Division 27 (commencing with Section 80000) of the Water Code.

32begin insert

begin insertSEC. 17.end insert  

end insert

begin insertSection 341.5 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
33to read:end insert

34

341.5.  

(a) The Independent System Operatorbegin delete and Power
35Exchangeend delete
bylaws shall contain provisions that identify those
36matters specified inbegin delete subdivision (b) ofend delete Section 339 as matters within
37state jurisdiction. The bylaws shall also contain provisions which
38state that California’s bylaws approval function with respect to
39the matters specified inbegin delete subdivision (b) ofend delete Section 339 shall not
40preclude the Federal Energy Regulatory Commission from taking
P31   1any action necessary to address undue discrimination or other
2violations of the Federal Power Act (16 U.S.C.A. Sec. 791a et
3seq.) or to exercise any other commission responsibility under the
4Federal Power Act. In taking any such action, the Federal Energy
5Regulatory Commission shall give due respect to California’s
6jurisdictional interests in the functions of the Independent System
7Operatorbegin delete and Power Exchangeend delete and to attempt to accommodate
8state interests to the extent those interests are not inconsistent with
9the Federal Energy Regulatory Commission’s statutory
10responsibilities. The bylaws shall state that any future agreement
11regarding the apportionment of the Independent System Operator
12begin delete and Power Exchangeend delete board appointment function among
13participating states associated with the expansion of the
14Independent System Operatorbegin delete and Power Exchangeend delete into multistate
15 entities shall be filed with the Federal Energy Regulatory
16Commission pursuant to Section 205 of the Federal Power Act (16
17U.S.C.A. Sec. 824d).

18(b) Any necessary bylaw changes to implement the provisions
19of Sectionbegin delete 335, 337, 338, 339,end deletebegin insert 339end insert or subdivision (a) of this section,
20or changes required pursuant to an agreement as contemplated by
21subdivision (a) of this section with a participating state for a
22regional organization, shall be effective upon approval of the
23respective governing boardsbegin delete and the Oversight Boardend delete and
24acceptance for filing by the Federal Energy Regulatory
25Commission.

26begin insert

begin insertSEC. 18.end insert  

end insert

begin insertSection 348 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
27to read:end insert

28

348.  

The Independent System Operator shall adopt inspection,
29maintenance, repair, and replacement standards for the transmission
30facilities under itsbegin delete control no later than September 30, 1997.end delete
31begin insert control.end insert The standards, which shall be performance or prescriptive
32standards, or both, as appropriate, for each substantial type of
33transmission equipment or facility, shall provide for high quality,
34safe, and reliable service. In adopting its standards, the Independent
35System Operator shall consider: cost, local geography and weather,
36applicable codes, national electric industry practices, sound
37engineering judgment, and experience. The Independent System
38Operator shall also adopt standards for reliability, and safety during
39periods of emergency and disaster.begin delete The Independent System
40Operator shall report to the Oversight Board, at such times as the
P32   1Oversight Board may specify, on the development and
2implementation of the standards in relation to facilities under the
3operational control of the Independent System Operator.end delete
The
4Independent System Operator shall require each transmission
5facility owner or operator to report annually on its compliance
6with the standards. That report shall be made available to the
7public.

8begin insert

begin insertSEC. 19.end insert  

end insert

begin insertSection 349.5 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
9to read:end insert

10

349.5.  

(a) begin deleteBeginning January 15, 2002, and at end deletebegin insertAt end insertleast once
11begin delete monthly thereafter,end deletebegin insert each month,end insert the Independent System Operator
12shall notify each air pollution control district and air quality
13management district of the name and address of each entity within
14the district’s boundaries within the Independent System Operator’s
15control area with whom the Independent System Operator enters
16into an interruptible service contract or similar arrangement.

17(b) For the purposes of this section, “interruptible service
18contract or similar arrangement” means any arrangement in which
19a nonresidential entity agrees to reduce or consider reducing its
20electrical consumption during periods of peak demand or at the
21request of the Independent System Operator in exchange for
22compensation, or for assurances not to be blacked out or other
23similar nonmonetary assurances.

24(c) The local air pollution control district or air quality
25management district shall maintain in a confidential manner the
26information received pursuant to this section. However, nothing
27in this subdivision shall affect the applicability of Chapter 3.5
28(commencing with Section 6250) of Division 7 of Title 1 of the
29Government Code, or of any other similar open records statute or
30ordinance, to information provided pursuant to this section.

31begin insert

begin insertSEC. 20.end insert  

end insert

begin insertSection 350 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
32

350.  

The Independent System Operator, in consultation with
33the California Energy Resources Conservation and Development
34Commission, the Public Utilities Commission, the Western
35Electricity Coordinating Council, and concerned regulatory
36agencies in other western states, shall within six months after the
37Federal Energy Regulatory Commission approval of the
38Independent System Operator, provide a report to the Legislature
39and to the Oversight Board that does the following:

P33   1(a) Conducts an independent review and assessment of Western
2Electricity Coordinating Council operating reliability criteria.

3(b) Quantifies the economic cost of major transmission outages
4relating to the Pacific Intertie, Southwest Power Link, DC link,
5and other important high voltage lines that carry power both into
6and from California.

7(c) Identifies the range of cost-effective options that would
8prevent or mitigate the consequences of major transmission
9outages.

10(d) Identifies communication protocols that may be needed to
11be established to provide advance warning of incipient problems.

12(e) Identifies the need for additional generation reserves and
13other voltage support equipment, if any, or other resources that
14may be necessary to carry out its functions.

15(f) Identifies transmission capacity additions that may be
16necessary at certain times of the year or under certain conditions.

17(g) Assesses the adequacy of current and prospective
18institutional provisions for the maintenance of reliability.

19(h) Identifies mechanisms to enforce transmission right-of-way
20maintenance.

21(i) Contains recommendations regarding cost-beneficial
22improvements to electric system reliability for the citizens of
23California.

end delete
24begin insert

begin insertSEC. 21.end insert  

end insert

begin insertSection 355 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
25

355.  

The Power Exchange shall provide an efficient competitive
26auction, open on a nondiscriminatory basis to all suppliers, that
27meets the loads of all exchange customers at efficient prices.

end delete
28begin insert

begin insertSEC. 22.end insert  

end insert

begin insertSection 356 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
29

356.  

The Power Exchange governing board may form
30appropriate technical advisory committees comprised of market
31and nonmarket participants to advise the governing board on
32relevant issues.

end delete
33begin insert

begin insertSEC. 23.end insert  

end insert

begin insertSection 359 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
34to read:end insert

35

359.  

(a) It is the intent of the Legislature to provide for the
36evolution of the Independent System Operatorbegin delete and the Power
37Exchangeend delete
into regional organizations to promote the development
38of regional electricity transmission markets in the western states
39and to improve the access of consumers served by the Independent
40System Operatorbegin delete and the Power Exchangeend delete to those markets.

P34   1(b) The preferred means by which the voluntary evolution
2described in subdivision (a) should occur is through the adoption
3of a regional compact or other comparable agreement among
4cooperating party states, the retail customers of which states would
5reside within the geographic territories served by the Independent
6Systembegin delete Operator and the Power Exchange.end deletebegin insert Operator.end insert

7(c) The agreement described in subdivision (b) should provide
8for all of the following:

9(1) An equitable process for the appointment or confirmation
10by party states of members of the governing boards of the
11Independent Systembegin delete Operator and the Power Exchange.end deletebegin insert Operator.end insert

12(2) A respecification of the size, structure, representation,
13eligible membership, nominating procedures, and member terms
14of service of the governing boards of the Independent System
15begin delete Operator and the Power Exchange.end deletebegin insert Operator.end insert

16(3) Mechanisms by which each party state, jointly or separately,
17can oversee effectively the actions of the Independent System
18Operatorbegin delete and the Power Exchangeend delete as those actions relate to the
19assurance of electricity system reliability within the party state
20and to matters that affect electricity sales to the retail customers
21of the party state or otherwise affect the general welfare of the
22electricity consumers and the general public of the party state.

23(4) The adherence by publicly owned and investor-owned
24utilities located in party states to enforceable standards and
25protocols to protect the reliability of the interconnected regional
26transmission and distribution systems.

27begin insert

begin insertSEC. 24.end insert  

end insert

begin insertSection 361 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
28

361.  

The commission shall ensure that any funds secured by
29the restructuring trusts established for the purposes of developing
30the Independent System Operator and the Power Exchange shall
31be placed at the disposal of the Independent System Operator and
32the Power Exchange respectively.

end delete
33begin insert

begin insertSEC. 25.end insert  

end insert

begin insertSection 363 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
34

363.  

(a) In order to ensure the continued safe and reliable
35operation of public utility electric generating facilities, the
36commission shall require in any proceeding under Section 851
37involving the sale, but not spinoff, of a public utility electric
38generating facility, for transactions initiated prior to December 31,
392001, and approved by the commission by December 31, 2002,
40that the selling utility contract with the purchaser of the facility
P35   1for the selling utility, an affiliate, or a successor corporation to
2operate and maintain the facility for at least two years. The
3commission may require these conditions to be met for transactions
4initiated on or after January 1, 2002. The commission shall require
5the contracts to be reasonable for both the seller and the buyer.

6(b) Subdivision (a) shall apply only if the facility is actually
7operated during the two-year period following the sale. Subdivision
8(a) shall not require the purchaser to operate a facility, nor shall it
9preclude a purchaser from temporarily closing the facility to make
10capital improvements.

11(c) For those bayside fossil fueled electric generation and
12associated transmission facilities that an electrical corporation has
13proposed to divest in a public auction and for which the Legislature
14has appropriated state funds in the Budget Act of 1998 to assist
15local governmental entities in acquiring the facilities or to mitigate
16environmental and community issues, and where the local
17governmental entity proposes that the closure of the power plant
18would serve the public interest by mitigating air, water and other
19environmental, health and safety, and community impacts
20associated with the facilities, and where the local governmental
21entity and electrical corporation have engaged in significant
22negotiations with the purpose of shutting down the power plant,
23and where there is an agreement between the electrical corporation
24and the local governmental entity for closure of the facilities or
25for the local governmental entity to acquire the facilities, the
26commission shall approve the closure of these facilities or the
27transfer of these electric generation and associated transmission
28facilities to the local governmental entity and shall consider the
29utility transactions with the community to be just and reasonable
30for its ratepayers. For purposes of calculating the Competition
31Transition Charge, the commission shall not use any inferred
32market value for the facilities predicated on the continued use of
33the plant, the construction of successor facilities or alternative use
34of the site and shall net the costs of the depreciated book value of
35the power plant and the unrecovered costs of decommissioning,
36environmental remediation and site restoration against the net
37proceeds received from the local governmental entity for the
38acquisition or closure of the facilities. Thereafter, any net proceeds
39received from the ultimate disposition, by the electrical corporation,
P36   1of the site shall be credited to recovery of Competition Transition
2Charges.

end delete
3begin insert

begin insertSEC. 26.end insert  

end insert

begin insertSection 365 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
4to read:end insert

5

365.  

Thebegin delete actions of the commission pursuant to this chapter
6shall be consistent with the findings and declarations contained in
7Section 330. In addition, theend delete
commission shall do all of the
8following:

9(a) Facilitate the efforts of the state’s electrical corporations to
10develop and obtain authorization from the Federal Energy
11Regulatory Commission for the creation and operation of an
12Independent Systembegin delete Operator and an independent Power Exchange,end delete
13begin insert Operator,end insert for the determination of which transmission and
14distribution facilities are subject to the exclusive jurisdiction of
15thebegin delete commission, and for approval, to the extent necessary, of the
16cost recovery mechanism established as provided in Sections 367
17to 376, inclusive.end delete
begin insert commission.end insert The commission shall also
18participate fully in all proceedings before the Federal Energy
19Regulatory Commission in connection with the Independent
20System Operatorbegin delete and the independent Power Exchange,end delete and shall
21encourage the Federal Energy Regulatory Commission to adopt
22protocols and procedures that strengthen the reliability of the
23interconnected transmission grid, encourage all publicly owned
24utilities in California to become full participants, and maximize
25enforceability of such protocols and procedures by all market
26participants.

27(b) (1) Authorize direct transactions between electricity
28suppliers and end use customers, subject to implementation ofbegin delete the
29nonbypassable charge referred to in Sections 367 to 376, inclusive.end delete

30begin insert competition transition charges.end insert Direct transactions shall commence
31simultaneously with the start of an Independent System Operator
32begin delete and Power Exchangeend delete referred to in subdivision (a). The
33simultaneous commencement shall occur as soon as practicable,
34but no later than January 1, 1998. The commission shall develop
35a phase-in schedule at the conclusion of which all customers shall
36have the right to engage in direct transactions. Any phase-in of
37customer eligibility for direct transactions ordered by the
38commission shall be equitable to all customer classes and
39accomplished as soon as practicable, consistent with operational
P37   1and other technological considerations, and shall be completed for
2all customers by January 1, 2002.

3(2) Customers shall be eligible for direct access irrespective of
4any direct access phase-in implemented pursuant to this section if
5at least one-half of that customer’s electrical load is supplied by
6energy from a renewable resource provider certified pursuant to
7Section 383, provided however that nothing in this section shall
8provide for direct access for electric consumers served by municipal
9utilities unless so authorized by the governing board of that
10municipal utility.

11begin insert

begin insertSEC. 27.end insert  

end insert

begin insertSection 367 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
12

367.  

The commission shall identify and determine those costs
13and categories of costs for generation-related assets and obligations,
14consisting of generation facilities, generation-related regulatory
15assets, nuclear settlements, and power purchase contracts,
16including, but not limited to, restructurings, renegotiations or
17terminations thereof approved by the commission, that were being
18collected in commission-approved rates on December 20, 1995,
19and that may become uneconomic as a result of a competitive
20generation market, in that these costs may not be recoverable in
21market prices in a competitive market, and appropriate costs
22incurred after December 20, 1995, for capital additions to
23generating facilities existing as of December 20, 1995, that the
24commission determines are reasonable and should be recovered,
25provided that these additions are necessary to maintain the facilities
26through December 31, 2001. These uneconomic costs shall include
27transition costs as defined in subdivision (f) of Section 840, and
28shall be recovered from all customers or in the case of fixed
29transition amounts, from the customers specified in subdivision
30(a) of Section 841, on a nonbypassable basis and shall:

31(a) Be amortized over a reasonable time period, including
32collection on an accelerated basis, consistent with not increasing
33rates for any rate schedule, contract, or tariff option above the
34levels in effect on June 10, 1996; provided that, the recovery shall
35not extend beyond December 31, 2001, except as follows:

36(1) Costs associated with employee-related transition costs as
37set forth in subdivision (b) of Section 375 shall continue until fully
38collected; provided, however, that the cost collection shall not
39extend beyond December 31, 2006.

P38   1(2) Power purchase contract obligations shall continue for the
2duration of the contract. Costs associated with any buy-out,
3buy-down, or renegotiation of the contracts shall continue to be
4collected for the duration of any agreement governing the buy-out,
5buy-down, or renegotiated contract; provided, however, no power
6purchase contract shall be extended as a result of the buy-out,
7buy-down, or renegotiation.

8(3) Costs associated with contracts approved by the commission
9to settle issues associated with the Biennial Resource Plan Update
10may be collected through March 31, 2002; provided that only 80
11percent of the balance of the costs remaining after December 31,
122001, shall be eligible for recovery.

13(4) Nuclear incremental cost incentive plans for the San Onofre
14nuclear generating station shall continue for the full term as
15authorized by the commission in Decision 96-01-011 and Decision
1696-04-059; provided that the recovery shall not extend beyond
17December 31, 2003.

18(5) Costs associated with the exemptions provided in subdivision
19(a) of Section 374 may be collected through March 31, 2002,
20provided that only fifty million dollars ($50,000,000) of the balance
21of the costs remaining after December 31, 2001, shall be eligible
22for recovery.

23(6) Fixed transition amounts, as defined in subdivision (d) of
24Section 840, may be recovered from the customers specified in
25subdivision (a) of Section 841 until all rate reduction bonds
26associated with the fixed transition amounts have been paid in full
27by the financing entity.

28(b) Be based on a calculation mechanism that nets the negative
29value of all above market utility-owned generation-related assets
30against the positive value of all below market utility-owned
31generation related assets. For those assets subject to valuation, the
32valuations used for the calculation of the uneconomic portion of
33the net book value shall be determined not later than December
3431, 2001, and shall be based on appraisal, sale, or other divestiture.
35The commission’s determination of the costs eligible for recovery
36and of the valuation of those assets at the time the assets are
37exposed to market risk or retired, in a proceeding under Section
38455.5, 851, or otherwise, shall be final, and notwithstanding Section
391708 or any other provision of law, may not be rescinded, altered
40or amended.

P39   1(c) Be limited in the case of utility-owned fossil generation to
2the uneconomic portion of the net book value of the fossil capital
3investment existing as of January 1, 1998, and appropriate costs
4incurred after December 20, 1995, for capital additions to
5generating facilities existing as of December 20, 1995, that the
6commission determines are reasonable and should be recovered,
7provided that the additions are necessary to maintain the facilities
8through December 31, 2001. All “going forward costs” of fossil
9plant operation, including operation and maintenance,
10administrative and general, fuel and fuel transportation costs, shall
11be recovered solely from independent Power Exchange revenues
12or from contracts with the Independent System Operator, provided
13that for the purposes of this chapter, the following costs may be
14recoverable pursuant to this section:

15(1) Commission-approved operating costs for particular
16utility-owned fossil powerplants or units, at particular times when
17reactive power/voltage support is not yet procurable at
18market-based rates in locations where it is deemed needed for the
19reactive power/voltage support by the Independent System
20Operator, provided that the units are otherwise authorized to
21recover market-based rates and provided further that for an
22electrical corporation that is also a gas corporation and that serves
23at least four million customers as of December 20, 1995, the
24commission shall allow the electrical corporation to retain any
25earnings from operations of the reactive power/voltage support
26plants or units and shall not require the utility to apply any portions
27to offset recovery of transition costs. Cost recovery under the cost
28recovery mechanism shall end on December 31, 2001.

29(2) An electrical corporation that, as of December 20, 1995,
30served at least four million customers, and that was also a gas
31corporation that served less than four thousand customers, may
32recover, pursuant to this section, 100 percent of the uneconomic
33portion of the fixed costs paid under fuel and fuel transportation
34contracts that were executed prior to December 20, 1995, and were
35subsequently determined to be reasonable by the commission, or
36100 percent of the buy-down or buy-out costs associated with the
37contracts to the extent the costs are determined to be reasonable
38by the commission.

39(d) Be adjusted throughout the period through March 31, 2002,
40to track accrual and recovery of costs provided for in this
P40   1subdivision. Recovery of costs prior to December 31, 2001, shall
2include a return as provided for in Decision 95-12-063, as modified
3by Decision 96-01-009, together with associated taxes.

4(e) (1) Be allocated among the various classes of customers,
5rate schedules, and tariff options to ensure that costs are recovered
6from these classes, rate schedules, contract rates, and tariff options,
7including self-generation deferral, interruptible, and standby rate
8options in substantially the same proportion as similar costs are
9recovered as of June 10, 1996, through the regulated retail rates
10of the relevant electric utility, provided that there shall be a firewall
11segregating the recovery of the costs of competition transition
12charge exemptions such that the costs of competition transition
13charge exemptions granted to members of the combined class of
14residential and small commercial customers shall be recovered
15only from these customers, and the costs of competition transition
16charge exemptions granted to members of the combined class of
17customers, other than residential and small commercial customers,
18shall be recovered only from these customers.

19(2) Individual customers shall not experience rate increases as
20a result of the allocation of transition costs. However, customers
21who elect to purchase energy from suppliers other than the Power
22Exchange through a direct transaction, may incur increases in the
23total price they pay for electricity to the extent the price for the
24energy exceeds the Power Exchange price.

25(3) The commission shall retain existing cost allocation
26authority, provided the firewall and rate freeze principles are not
27violated.

end delete
28begin insert

begin insertSEC. 28.end insert  

end insert

begin insertSection 367.7 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
29

367.7.  

(a) It is the intent of the Legislature in enacting this
30section to ensure that individual customers do not experience rate
31increases as a result of the allocation of transition costs, in
32accordance with paragraph (2) of subdivision (e) of Section 367.

33(b) The commission shall implement a methodology whereby
34the Power Exchange energy credit for a customer with a meter
35installed on or after June 30, 2000, that is capable of recording
36hourly data is calculated based on the actual hourly data for that
37customer. The Power Exchange energy credit for a customer with
38a meter installed before June 30, 2000, that is capable of recording
39hourly data shall, at the election of the customer, on a one-time
40basis before June 30, 2000, be calculated based on either (1) the
P41   1actual hourly data for that customer or (2) the average load profile
2for that customer class. If the customer fails to make an election,
3that customer’s Power Exchange energy credit shall continue to
4be based on the average load profile for that customer class.

5(c) Additional incremental billing costs incurred as a result of
6the methodology implemented by the commission pursuant to
7subdivision (b) may be recoverable through rates for that customer
8class, if the commission finds that the costs are reasonable.

9(d) The methodology implemented by the commission pursuant
10to subdivisions (b) and (c) shall not result in any shifts in cost
11between customer classes and shall be consistent with the firewall
12provision set forth in subdivision (e) of Section 367.

end delete
13begin insert

begin insertSEC. 29.end insert  

end insert

begin insertSection 368 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
14to read:end insert

15

368.  

Each electrical corporation shall propose a cost recovery
16plan to the commission for the recovery of the uneconomic costs
17of an electrical corporation’s generation-related assets and
18obligations identified in Section 367. The commission shall
19begin delete authorize the electrical corporation to recover the costs pursuant
20to the plan if the plan meets the following criteria:end delete
begin insert provide for
21identification and separation of individual rate components such
22as charges for energy, transmission, distribution, public benefit
23programs, and recovery of uneconomic costs. The separation of
24rate components required by this section shall be used to ensure
25that customers of the electrical corporation who purchase
26electricity from suppliers other than the electrical corporation pay
27the same unbundled component charges, other than energy, that
28a bundled service customer pays.end insert

begin delete

29(a) The cost recovery plan shall set rates for each customer class,
30rate schedule, contract, or tariff option, at levels equal to the level
31as shown on electric rate schedules as of June 10, 1996, provided
32that rates for residential and small commercial customers shall be
33reduced so that these customers shall receive rate reductions of no
34less than 10 percent for 1998 continuing through 2002. These rate
35levels for each customer class, rate schedule, contract, or tariff
36option shall remain in effect until the earlier of March 31, 2002,
37or the date on which the commission-authorized costs for utility
38generation-related assets and obligations have been fully recovered.
39The electrical corporation shall be at risk for those costs not
40recovered during that time period. Each utility shall amortize its
P42   1total uneconomic costs, to the extent possible, such that for each
2year during the transition period its recorded rate of return on the
3remaining uneconomic assets does not exceed its authorized rate
4of return for those assets. For purposes of determining the extent
5to which the costs have been recovered, any over-collections
6recorded in Energy Costs Adjustment Clause and Electric Revenue
7Adjustment Mechanism balancing accounts, as of December 31,
81996, shall be credited to the recovery of the costs.

end delete
begin delete

9(b) The cost recovery plan shall provide for identification and
10separation of individual rate components such as charges for
11energy, transmission, distribution, public benefit programs, and
12recovery of uneconomic costs. The separation of rate components
13required by this subdivision shall be used to ensure that customers
14of the electrical corporation who become eligible to purchase
15electricity from suppliers other than the electrical corporation pay
16the same unbundled component charges, other than energy, that a
17bundled service customer pays. No cost shifting among customer
18classes, rate schedules, contract, or tariff options shall result from
19the separation required by this subdivision. Nothing in this
20provision is intended to affect the rates, terms, and conditions or
21to limit the use of any Federal Energy Regulatory
22Commission-approved contract entered into by the electrical
23corporation prior to the effective date of this provision.

end delete
begin delete

24(c) In consideration of the risk that the uneconomic costs
25identified in Section 367 may not be recoverable within the period
26identified in subdivision (a) of Section 367, an electrical
27corporation that, as of December 20, 1995, served more than four
28million customers, and was also a gas corporation that served less
29than four thousand customers, shall have the flexibility to employ
30risk management tools, such as forward hedges, to manage the
31market price volatility associated with unexpected fluctuations in
32natural gas prices, and the out-of-pocket costs of acquiring the risk
33management tools shall be considered reasonable and collectible
34within the transition freeze period. This subdivision applies only
35to the transaction costs associated with the risk management tools
36and shall not include any losses from changes in market prices.

end delete
begin delete

37(d) In order to ensure implementation of the cost recovery plan,
38the limitation on the maximum amount of cost recovery for nuclear
39facilities that may be collected in any year adopted by the
40commission in Decision 96-01-011 and Decision 96-04-059 shall
P43   1be eliminated to allow the maximum opportunity to collect the
2nuclear costs within the transition cap period.

end delete
begin delete

3(e) As to an electrical corporation that is also a gas corporation
4serving more than four million California customers, so long as
5any cost recovery plan adopted in accordance with this section
6satisfies subdivision (a), it shall also provide for annual increases
7in base revenues, effective January 1, 1997, and January 1, 1998,
8equal to the inflation rate for the prior year plus two percentage
9points, as measured by the consumer price index. The increase
10shall do both of the following:

end delete
begin delete

11(1) Remain in effect pending the next general rate case review,
12which shall be filed not later than December 31, 1997, for rates
13that would become effective in January 1999. For purposes of any
14commission-approved performance-based ratemaking mechanism
15or general rate case review, the increases in base revenue authorized
16by this subdivision shall create no presumption that the level of
17base revenue reflecting those increases constitute the appropriate
18starting point for subsequent revenues.

end delete
begin delete

19(2) Be used by the utility for the purposes of enhancing its
20transmission and distribution system safety and reliability,
21including, but not limited to, vegetation management and
22emergency response. To the extent the revenues are not expended
23for system safety and reliability, they shall be credited against
24subsequent safety and reliability base revenue requirements. Any
25excess revenues carried over shall not be used to pay any monetary
26sanctions imposed by the commission.

end delete
begin delete

27(f) The cost recovery plan shall provide the electrical corporation
28with the flexibility to manage the renegotiation, buy-out, or
29buy-down of the electrical corporation’s power purchase
30obligations, consistent with review by the commission to assure
31that the terms provide net benefits to ratepayers and are otherwise
32reasonable in protecting the interests of both ratepayers and
33shareholders.

end delete
begin delete

34(g) An example of a plan authorized by this section is the
35document entitled “Restructuring Rate Settlement” transmitted to
36the commission by Pacific Gas and Electric Company on June 12,
371996.

end delete
38begin insert

begin insertSEC. 30.end insert  

end insert

begin insertSection 368.5 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
39

368.5.  

(a) Notwithstanding any other provision of law, upon
40the termination of the 10-percent rate reduction for residential and
P44   1small commercial customers set forth in subdivision (a) of Section
2368, the commission may not subject those residential and small
3commercial customers to any rate increases or future rate
4obligations solely as a result of the termination of the 10-percent
5rate reduction.

6(b) The provisions of subdivision (a) do not affect the authority
7of the commission to raise rates for reasons other than the
8termination of the 10-percent rate reduction set forth in subdivision
9(a) of Section 368.

10(c) Nothing in this section shall further extend the authority to
11impose fixed transition amounts, as defined in subdivision (d) of
12Section 840, or further authorize or extend rate reduction bonds,
13as defined in subdivision (e) of Section 840.

end delete
14begin insert

begin insertSEC. 31.end insert  

end insert

begin insertSection 369 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
15to read:end insert

16

369.  

begin deleteThe commission shall establish an effective mechanism
17that ensures recovery of transition costs referred to in Sections
18367, 368, 375, and 376, and end delete
begin insertCompetition transition charges, end insertsubject
19to the conditions in Sections 371 to 374, inclusive,begin delete fromend deletebegin insert the
20recovery of which was authorized by the commission prior to
21January 1, 2015, shall continue to apply toend insert
all existing and future
22consumers in the service territory in which the utility provided
23electricity services as of December 20, 1995; provided, that the
24costs shall not be recoverable for new customer load or incremental
25load of an existing customer where the load is being met through
26a direct transaction and the transaction does not otherwise require
27the use of transmission or distribution facilities owned by the
28utility. However, the obligation to pay the competition transition
29charges cannot be avoided by the formation of a local publicly
30owned electrical corporation on or after December 20, 1995, or
31by annexation of any portion of an electrical corporation’s service
32area by an existing local publicly owned electric utility.

33This section shall not apply to service taken under tariffs,
34contracts, or rate schedules that are on file, accepted, or approved
35by the Federal Energy Regulatory Commission, unless otherwise
36authorized by the Federal Energy Regulatory Commission.

37begin insert

begin insertSEC. 32.end insert  

end insert

begin insertSection 370 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
38to read:end insert

39

370.  

The commission shall require, as a prerequisite for any
40consumer in California to engage in direct transactions permitted
P45   1in Section 365, that beginning with the commencement of these
2direct transactions, the consumer shall have an obligation to pay
3begin delete the costs provided in Sections 367, 368, 375, and 376,end deletebegin insert competition
4transition charges,end insert
and subject to the conditions in Sections 371
5to 374, inclusive, directly to the electrical corporation providing
6electricity service in the area in which the consumer is located.
7This obligation shall be set forth in the applicable rate schedule,
8contract, or tariff option under which the customer is receiving
9service from the electrical corporation. To the extent the consumer
10does not use the electrical corporation’s facilities for direct
11transaction, the obligation to pay shall be confirmed in writing,
12and the customer shall be advised by any electricity marketer
13engaged in the transaction of the requirement that the customer
14execute a confirmation. The requirement for marketers to inform
15customers of the written requirement shall cease on January 1,
162002.

17begin insert

begin insertSEC. 33.end insert  

end insert

begin insertSection 371 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
18to read:end insert

19

371.  

(a) Except as provided in Sections 372 and 374,begin delete the
20uneconomic costs provided in Sections 367, 368, 375, and 376end delete

21begin insert competition transition chargesend insert shall be applied to each customer
22based on the amount of electricity purchased by the customer from
23an electrical corporation or alternate supplier of electricity, subject
24to changes in usage occurring in the normal course of business.

25(b) Changes in usage occurring in the normal course of business
26are those resulting from changes in business cycles, termination
27of operations, departure from the utility service territory, weather,
28reduced production, modifications to production equipment or
29operations, changes in production or manufacturing processes,
30fuel switching, including installation of fuel cells pending a
31contrary determination by thebegin delete California Energy Resources
32Conservation and Development Commission in Section 383,end delete

33begin insert Energy Commission,end insert enhancement or increased efficiency of
34equipment or performance of existing self-cogeneration equipment,
35replacement of existing cogeneration equipment with new power
36generation equipment of similar size as described in paragraph (1)
37of subdivision (a) of Section 372, installation of demand-side
38management equipment or facilities, energy conservation efforts,
39or other similar factors.

P46   1(c) Nothing in this section shall be interpreted to exempt or alter
2the obligation of a customer to comply with Chapter 5
3(commencing with Section 119075) of Part 15 of Division 104 of
4the Health and Safety Code. Nothing in this section shall be
5construed as a limitation on the ability of residential customers to
6alter their pattern of electricity purchases by activities on the
7customer side of the meter.

8begin insert

begin insertSEC. 34.end insert  

end insert

begin insertSection 372 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
9to read:end insert

10

372.  

(a) It is the policy of the state to encourage and support
11the development of cogeneration as an efficient, environmentally
12beneficial, competitive energy resource that will enhance the
13reliability of local generation supply, and promote local business
14growth. Subject to the specific conditions provided in this section,
15the commission shall determine the applicability to customers of
16begin delete uneconomic costs as specified in Sections 367, 368, 375, and 376.end delete
17begin insert competition transition charges.end insert Consistent with this state policy,
18the commission shall provide that these costs shall not apply to
19any of the following:

20(1) To load served onsite or under an over the fence arrangement
21by a nonmobile self-cogeneration or cogeneration facility that was
22operational on or before December 20, 1995, or by increases in
23the capacity of a facility to the extent that the increased capacity
24was constructed by an entity holding an ownership interest in or
25operating the facility and does not exceed 120 percent of the
26installed capacity as of December 20, 1995, provided that prior to
27June 30, 2000, the costs shall apply to over the fence arrangements
28entered into after December 20, 1995, between unaffiliated parties.
29For the purposes of this subdivision, “affiliated” means any person
30or entity that directly, or indirectly through one or more
31intermediaries, controls, is controlled by, or is under common
32control with another specified entity. “Control” means either of
33the following:

34(A) The possession, directly or indirectly, of the power to direct
35or to cause the direction of the management or policies of a person
36or entity, whether through an ownership, beneficial, contractual,
37or equitable interest.

38(B) Direct or indirect ownership of at least 25 percent of an
39entity, whether through an ownership, beneficial, or equitable
40interest.

P47   1(2) To load served by onsite or under an over the fence
2arrangement by a nonmobile self-cogeneration or cogeneration
3facility for which the customer was committed to construction as
4of December 20, 1995, provided that the facility was substantially
5operational on or before January 1, 1998, or by increases in the
6capacity of a facility to the extent that the increased capacity was
7constructed by an entity holding an ownership interest in or
8operating the facility and does not exceed 120 percent of the
9installed capacity as of January 1, 1998, provided that prior to June
1030, 2000, the costs shall apply to over the fence arrangements
11entered into after December 20, 1995, between unaffiliated parties.

12(3) To load served by existing, new, or portable emergency
13generation equipment used to serve the customer’s load
14requirements during periods when utility service is unavailable,
15provided the emergency generation is not operated in parallel with
16the integrated electric grid, except on a momentary parallel basis.

17(4) After June 30, 2000, to any load served onsite or under an
18over the fence arrangement by any nonmobile self-cogeneration
19or cogeneration facility.

20(b) Further, consistent with state policy, with respect to
21self-cogeneration or cogeneration deferral agreements, the
22commission shall do the following:

23(1) Provide that a utility shall execute a final self-cogeneration
24or cogeneration deferral agreement with any customer that, on or
25before December 20, 1995, had executed a letter of intent (or
26similar documentation) to enter into the agreement with the utility,
27provided that the final agreement shall be consistent with the terms
28and conditions set forth in the letter of intent and the commission
29shall review and approve the final agreement.

30(2) Provide that a customer that holds a self-cogeneration or
31cogeneration deferral agreement that was in place on or before
32December 20, 1995, or that was executed pursuant to paragraph
33(1) in the event the agreement expires, or is terminated, may do
34any of the following:

35(A) Continue through December 31, 2001, to receive utility
36service at the rate and under terms and conditions applicable to
37the customer under the deferral agreement that, as executed,
38includes an allocation of uneconomic costs consistent with
39subdivision (e) of Section 367.

P48   1(B) Engage in a direct transaction for the purchase of electricity
2and pay uneconomic costs consistent with Sectionsbegin delete 367, 368, 375,end delete
3begin insert 367end insert and 376.

4(C) Construct a self-cogeneration or cogeneration facility of
5approximately the same capacity as the facility previously deferred,
6provided that the costs provided in Sectionsbegin delete 367, 368, 375,end deletebegin insert 367end insert
7 and 376 shall apply consistent with subdivision (e) of Section 367,
8unless otherwise authorized by the commission pursuant to
9subdivision (c).

10(3) Subject to the firewall described in subdivision (e) of Section
11367, provide that the ratemaking treatment for self-cogeneration
12or cogeneration deferral agreements executed prior to December
1320, 1995, or executed pursuant to paragraph (1) shall be consistent
14with the ratemaking treatment for the contracts approved before
15January 1995.

16(c) The commission shall authorize, within 60 days of the receipt
17of a joint application from the serving utility and one or more
18interested parties, applicability conditions as follows:

19(1) begin deleteThe costs identified in Sections 367, 368, 375, and 376 end delete
20begin insertCompetition transition charges end insertshall not, prior to June 30, 2000,
21apply to load served onsite by a nonmobile self-cogeneration or
22cogeneration facility that became operational on or after December
2320, 1995.

24(2) begin deleteThe costs identified in Sections 367, 368, 375, and 376 end delete
25begin insertCompetition transition charges end insertshall not, prior to June 30, 2000,
26apply to any load served under over the fence arrangements entered
27into after December 20, 1995, between unaffiliated entities.

28(d) For the purposes of this subdivision, all onsite or over the
29fence arrangements shall be consistent with Section 218 as it
30existed on December 20, 1995.

31(e) To facilitate the development of new microcogeneration
32applications, electrical corporations may apply to the commission
33for a financing order to finance the transition costs to be recovered
34from customers employing the applications.

35(f) To encourage the continued development, installation, and
36interconnection of clean and efficient self-generation and
37cogeneration resources, to improve system reliability for consumers
38by retaining existing generation and encouraging new generation
39to connect to the electric grid, and to increase self-sufficiency of
P49   1consumers of electricity through the deployment of self-generation
2and cogeneration, both of the following shall occur:

3(1) The commissionbegin delete and the Electricity Oversight Boardend delete shall
4determine if any policy or action undertaken by the Independent
5System Operator, directly or indirectly, unreasonably discourages
6the connection of existing self-generation or cogeneration or new
7self-generation or cogeneration to the grid.

8(2) If the commissionbegin delete and the Electricity Oversight Board findend delete
9begin insert findsend insert that any policy or action of the Independent System Operator
10unreasonably discourages the connection of existing self-generation
11or cogeneration or new self-generation or cogeneration to the grid,
12the commissionbegin delete and the Electricity Oversight Boardend delete shall undertake
13all necessary efforts to revise, mitigate, or eliminate that policy or
14action of the Independent System Operator.

15begin insert

begin insertSEC. 35.end insert  

end insert

begin insertSection 373 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
16

373.  

(a) Electrical corporations may apply to the commission
17for an order determining that the costs identified in Sections 367,
18368, 375, and 376 not be collected from a particular class of
19customer or category of electricity consumption.

20(b) Subject to the fire wall specified in subdivision (e) of Section
21367, the provisions of this section and Sections 372 and 374 shall
22apply in the event the commission authorizes a nonbypassable
23charge prior to the implementation of an Independent System
24Operator and Power Exchange referred to in subdivision (a) of
25Section 365.

end delete
26begin insert

begin insertSEC. 36.end insert  

end insert

begin insertSection 374 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
27to read:end insert

28

374.  

(a) begin deleteIn recognition of statutory authority and past
29investments existing as of December 20, 1995, and subject to the
30firewall specified in subdivision (e) of Section 367, the obligation
31to pay the uneconomic costs identified in Sections 367, 368, 375,
32and 376 end delete
begin insertCompetition transition charges end insertshall not apply to the
33following:

34(1) One hundred ten megawatts of load served by irrigation
35districts, as hereafter allocated by this paragraph:

36(A) The 110 megawatts of load shall be allocated among the
37service territories of the three largest electrical corporations in the
38ratio of the number of irrigation districts in the service territory of
39each utility to the total number of irrigation districts in the service
40territories of all three utilities.

P50   1(B) The total amount of load allocated to each utility service
2area shall be phased in over five years beginning January 1, 1997,
3so that one-fifth of the allocation is allocated in each of the five
4years. Any allocation that remains unused at the end of any year
5shall be carried over to the succeeding year and added to the
6allocation for that year.

7(C) The load allocated to each utility service territory pursuant
8to subparagraph (A) shall be further allocated among the respective
9irrigation districts within that service territory by thebegin delete California
10Energy Resources Conservation and Developmentend delete
begin insert Energyend insert
11 Commission. An individual irrigation district requesting an
12allocation shall submit to the commission by January 31, 1997,
13detailed plans that show the load that it serves or will serve and
14for which it intends to utilize the allocation within the timeframe
15requested. These plans shall include specific information on the
16irrigation districts’ organization for electric distribution, contracts,
17financing and engineering plans for capital facilities, as well as
18detailed information about the loads to be served, and shall not be
19less than eight megawatts or more than 40 megawatts, provided,
20however, that any portion of the 110 megawatts that remains
21unallocated may be reallocated to projects without regard to the
2240 megawatts limitation. In making an allocation among irrigation
23districts, the Energybegin delete Resources Conservation and Developmentend delete
24 Commission shall assess the viability of each submission and
25whether it can be accomplished in the timeframe proposed. The
26Energybegin delete Resources Conservation and Developmentend delete Commission
27shall have the discretion to allocate the load covered by this section
28in a manner that best ensures its usage within the allocation period.

29(D) At least 50 percent of each year’s allocation to a district
30shall be applied to that portion of load that is used to power pumps
31for agricultural purposes.

32(E) Any load pursuant to this subdivision shall be served by
33distribution facilities owned by, or leased to, the district in question.

34(F) Any load allocated pursuant to paragraph (1) shall be located
35within the boundaries of the affected irrigation district, or within
36the boundaries specified in an applicable service territory boundary
37agreement between an electrical corporation and the affected
38irrigation district; additionally, the provisions of subparagraph (C)
39of paragraph (1) shall be applicable to any load within the Counties
P51   1of Stanislaus or San Joaquin, or both, served by any irrigation
2district that is currently serving or will be serving retail customers.

3(2) Seventy-five megawatts of load served by the Merced
4Irrigation District hereafter prescribed in this paragraph:

5(A) The total allocation provided by this paragraph shall be
6phased in over five years beginning January 1, 1997, so that
7one-fifth of the allocation is received in each of the five years. Any
8allocation that remains unused at the end of any year shall be
9carried over to the succeeding year and added to the allocation for
10that year.

11(B) Any load to which the provision of this paragraph is
12applicable shall be served by distribution facilities owned by, or
13leased to, Merced Irrigation District.

14(C) A load to which the provisions of this paragraph are
15applicable shall be located within the boundaries of Merced
16Irrigation District as those boundaries existed on December 20,
171995, together with the territory of Castle Air Force Base that was
18located outside of the district on that date.

19(D) The total allocation provided by this paragraph shall be
20phased in over five years beginning January 1, 1997, with the
21exception of load already being served by the district as of June
221, 1996, which shall be deducted from the total allocation and shall
23not be subject tobegin delete the costs provided in Sections 367, 368, 375, and
24376.end delete
begin insert competition transition charges.end insert

25(3) To loads served by irrigation districts, water districts, water
26storage districts, municipal utility districts, and other water agencies
27that, on December 20, 1995, were members of the Southern San
28Joaquin Valley Power Authority, or the Eastside Power Authority,
29provided, however, that this paragraph shall be applicable only to
30that portion of each district or agency’s load that is used to power
31pumps that are owned by that district or agency as of December
3220, 1995, or replacements thereof, and is being used to pump water
33for district purposes. The rates applicable to these districts and
34agencies shall be adjusted as of January 1, 1997.

35(4) The provisions of this subdivision shall no longer be
36operative after March 31, 2002.

37(5) The provisions of paragraph (1) shall not be applicable to
38any irrigation district, water district, or water agency described in
39paragraph (2) or (3).

P52   1(6) Transmission services provided to any irrigation district
2described in paragraph (1) or (2) shall be provided pursuant to
3otherwise applicable tariffs.

4(7) Nothing in this chapter shall be deemed to grant the
5commission any jurisdiction over irrigation districts not already
6granted to the commission by existing law.

7(b) To give the full effect to the legislative intent in enacting
8Section 701.8,begin delete the costs provided in Sections 367, 368, 375, and
9376end delete
begin insert competition transition chargesend insert shall not apply to the load
10served by preference power purchased from a federal power
11marketing agency, or its successor, pursuant to Section 701.8 as
12it existed on January 1, 1996, provided that the power is used solely
13for the customer’s own systems load and not for sale. The costs
14of this provision shall be borne by all ratepayers in the affected
15service territory, notwithstanding the firewall established in
16subdivision (e) of Section 367.

17(c) To give effect to an existing relationship, the obligation to
18pay begin delete the uneconomic costs specified in Sections 367, 368, 375, and
19376end delete
begin insert competition transition chargesend insert shall not apply to that portion
20of the load of the University of California campus situated in Yolo
21County that was being served as of May 31, 1996, by preference
22power purchased from a federal marketing agency, or its successor,
23provided that the power is used solely for the facility load of that
24campus and not, directly or indirectly, for sale.

25begin insert

begin insertSEC. 37.end insert  

end insert

begin insertSection 374.5 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
26

374.5.  

Any electrical corporation serving agricultural customers
27that have multiple electric meters shall conduct research based on
28a statistically valid sample of those customers and meters to
29determine the typical simultaneous peak load of those customers.
30The results of the research shall be reported to the customers and
31the commission not later than July 1, 2001. The commission shall
32consider the research results in setting future electric distribution
33rates for those customers.

end delete
34begin insert

begin insertSEC. 38.end insert  

end insert

begin insertSection 375 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
35

375.  

(a) In order to mitigate potential negative impacts on
36utility personnel directly affected by electric industry restructuring,
37as described in Decision 95-12-063, as modified by Decision
3896-01-009, the commission shall allow the recovery of reasonable
39employee related transition costs incurred and projected for
P53   1severance, retraining, early retirement, outplacement and related
2expenses for the employees.

3(b) The costs, including employee related transition costs for
4employees performing services in connection with Section 363,
5shall be added to the amount of uneconomic costs allowed to be
6recovered pursuant to this section and Sections 367, 368, and 376,
7provided recovery of these employee related transition costs shall
8extend beyond December 31, 2001, provided recovery of the costs
9shall not extend beyond December 31, 2006. However, there shall
10be no recovery for employee related transition costs associated
11with officers, senior supervisory employees, and professional
12employees performing predominantly regulatory functions.

end delete
13begin insert

begin insertSEC. 39.end insert  

end insert

begin insertSection 376 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
14

376.  

To the extent that the costs of programs to accommodate
15implementation of direct access, the Power Exchange, and the
16Independent System Operator, that have been funded by an
17electrical corporation and have been found by the commission or
18the Federal Energy Regulatory Commission to be recoverable from
19the utility’s customers, reduce an electrical corporation’s
20opportunity to recover its utility generation-related plant and
21regulatory assets by the end of the year 2001, the electrical
22corporation may recover unrecovered utility generation-related
23plant and regulatory assets after December 31, 2001, in an amount
24equal to the utility’s cost of commission-approved or Federal
25Energy Regulatory Commission approved restructuring-related
26implementation programs. An electrical corporation’s ability to
27collect the amounts from retail customers after the year 2001 shall
28be reduced to the extent the Independent System Operator or the
29Power Exchange reimburses the electrical corporation for the costs
30of any of these programs.

end delete
31begin insert

begin insertSEC. 40.end insert  

end insert

begin insertSection 379 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
32to read:end insert

33

379.  

Nuclear decommissioning costs shall not be part of the
34begin delete costs described in Sections 367, 368, 375, and 376,end deletebegin insert competition
35transition charges,end insert
but shall be recovered as a nonbypassable
36charge until the time as the costs are fully recovered. Recovery of
37decommissioning costs may be accelerated to the extent possible.

38begin insert

begin insertSEC. 41.end insert  

end insert

begin insertSection 390 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
39

390.  

(a) Subject to applicable contractual terms, energy prices
40paid to nonutility power generators by a public utility electrical
P54   1corporation based upon the commission’s prescribed “short run
2avoided cost energy methodology” shall be determined as set forth
3in subdivisions (b) and (c).

4(b) Until the requirements of subdivision (c) have been satisfied,
5short run avoided cost energy payments paid to nonutility power
6generators by an electrical corporation shall be based on a formula
7that reflects a starting energy price, adjusted monthly to reflect
8changes in a starting gas index price in relation to an average of
9current California natural gas border price indices. The starting
10energy price shall be based on 12-month averages of recent,
11pre-January 1, 1996, short-run avoided energy prices paid by each
12public utility electrical corporation to nonutility power generators.
13The starting gas index price shall be established as an average of
14index gas prices for the same annual periods.

15(c) The short-run avoided cost energy payments paid to
16nonutility power generators by electrical corporations shall be
17based on the clearing price paid by the independent Power
18Exchange if (1) the commission has issued an order determining
19that the independent Power Exchange is functioning properly for
20the purposes of determining the short-run avoided cost energy
21payments to be made to nonutility power generators, and either
22 (2) the fossil-fired generation units owned, directly or indirectly,
23by the public utility electrical corporation are authorized to charge
24market-based rates and the “going forward” costs of those units
25are being recovered solely through the clearing prices paid by the
26independent Power Exchange or from contracts with the
27Independent System Operator, whether those contracts are
28market-based or based on operating costs for particular
29utility-owned powerplant units and at particular times when
30reactive power/voltage support is not yet procurable at
31market-based rates at locations where it is needed, and are not
32being recovered directly or indirectly through any other source,
33or (3) the public utility electrical corporation has divested 90
34percent of its gas-fired generation facilities that were operated to
35meet load in 1994 and 1995. However, nonutility power generators
36subject to this section may, upon appropriate notice to the public
37utility electrical corporation, exercise a one-time option to elect
38to thereafter receive energy payments based upon the clearing
39price from the independent Power Exchange.

P55   1(d) If a nonutility power generator is being paid short-run
2avoided costs energy payments by an electrical corporation by a
3firm capacity contract, a forecast as-available capacity contract,
4or a forecast as-delivered capacity contract on the basis of the
5clearing price paid by the independent Power Exchange as
6described in subdivision (c) above, the value of capacity in the
7clearing price, if any, shall not be paid to the nonutility power
8generator. The value of capacity in the clearing price, if any, equals
9the difference between the market clearing customer demand bid
10at the level of generation dispatched by the independent Power
11Exchange and the highest supplier bid dispatched.

12(e) Short-run avoided energy cost payments made pursuant to
13this section are in addition to contractually specified capacity
14payments. Nothing in this section shall be construed to affect,
15modify or amend the terms and conditions of existing nonutility
16power generators’ contracts with respect to the sale of energy or
17capacity or otherwise.

18(f) Nothing in this section shall be construed to limit the level
19of transition cost recovery provided to utilities under electric
20industry restructuring policies established by the commission.

21(g) The term “going forward costs” shall include, but not be
22limited to, all costs associated with fuel transportation and fuel
23supply, administrative and general, and operation and maintenance;
24provided that, for purposes of this section, the following shall not
25be considered “going forward costs”: (1) commission-approved
26capital costs for capital additions to fossil-fueled powerplants,
27provided that such additions are necessary for the continued
28operation of the powerplants utilized to meet load and such
29additions are not undertaken primarily to expand, repower or
30enhance the efficiency of plant operations; or, (2)
31commission-approved operating costs for particular utility-owned
32powerplant units and at particular times when reactive
33power/voltage support is not yet procurable at market-based rates
34in locations where it is needed, provided that the recovery shall
35end on December 31, 2001.

end delete
36begin insert

begin insertSEC. 42.end insert  

end insert

begin insertSection 390.1 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
37

390.1.  

Any nonutility power generator using renewable fuels
38that has entered into a contract with an electrical corporation prior
39to December 31, 2001, specifying fixed energy prices for five years
40of output may negotiate a contract for an additional five years of
P56   1fixed energy payments upon expiration of the initial five-year term,
2at a price to be determined by the commission.

end delete
3begin insert

begin insertSEC. 43.end insert  

end insert

begin insertSection 394.5 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
4to read:end insert

5

394.5.  

(a) Except for an electrical corporation as defined in
6Section 218, or a local publicly owned electric utility offering
7electrical service to residential and small commercial customers
8within its service territory, each electric service provider offering
9electrical service to residential and small commercial customers
10shall, prior to the commencement of service, provide the potential
11customer with a written notice of the service describing the price,
12terms, and conditions of the service. A notice shall include all of
13the following:

14(1) A clear description of the price, terms, and conditions of
15service, including:

16(A) The price of electricity expressed in a format that makes it
17possible for residential and small commercial customers to compare
18and select among similar products and services on a standard basis.
19The commission shall adopt rules to implement this subdivision.
20The commission shall require disclosure of the total price of
21electricity on a cents-per-kilowatthour basis, including the costs
22of all electric services and charges regulated by the commission.
23The commission shall also require estimates of the total monthly
24bill for the electric service at varying consumption levels, including
25the costs of all electric services and charges regulated by the
26commission. In determining these rules, the commission may
27consider alternatives to the cents-per-kilowatthour disclosure if
28other information would provide the customer with sufficient
29information to compare among alternatives on a standard basis.

30(B) Separate disclosure of all recurring and nonrecurring charges
31associated with the sale of electricity.

32(C) If services other than electricity are offered, an itemization
33of the services and the charge or charges associated with each.

34(2) An explanation of the applicability and amount of the
35competition transitionbegin delete charge, as determined pursuant to Sections
36367 to 376, inclusive.end delete
begin insert charges.end insert

37(3) A description of the potential customer’s right to rescind
38the contract without fee or penalty as described in Section 395.

P57   1(4) An explanation of the customer’s financial obligations, as
2well as the procedures regarding past due payments, discontinuance
3of service, billing disputes, and service complaints.

4(5) The electric service provider’s registration number, if
5applicable.

6(6) The right to change service providers upon written notice,
7including disclosure of any fees or penalties assessed by the
8supplier for early termination of a contract.

9(7) A description of the availability of low-income assistance
10programs for qualified customers and how customers can apply
11for these programs.

12(b) The commission may assist electric service providers in
13developing the notice. The commission may suggest inclusion of
14additional information it deems necessary for the consumer
15protection purposes of this section. On at least a semiannual basis,
16electric service providers shall provide the commission with a copy
17of the form of notice included in standard service plans made
18available to residential and small commercial customers.

19(c) An electric service provider offering electric services who
20declines to provide those services to a consumer shall, upon request
21of the consumer, disclose to that consumer the reason for the denial
22in writing within 30 days. At the time service is denied, the electric
23service provider shall disclose to the consumer the right to make
24this request. A consumer shall have at least 30 days from the date
25service is denied to make the request.

26begin insert

begin insertSEC. 44.end insert  

end insert

begin insertSection 395 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
27to read:end insert

28

395.  

(a) In addition to any other right to revoke an offer,
29residential and small commercial customers of electrical service,
30as defined in subdivisionbegin delete (h)end deletebegin insert (g)end insert of Section 331, have the right to
31cancel a contract for electric service until midnight of the third
32business day after the day on which the buyer signs an agreement
33or offer to purchase.

34(b) Cancellation occurs when the buyer gives written notice of
35cancellation to the seller at the address specified in the agreement
36or offer.

37(c) Notice of cancellation, if given by mail, is effective when
38deposited in the mail properly addressed with postage prepaid.

39(d) Notice of cancellation given by the buyer need not take the
40particular form as provided with the contract or offer to purchase
P58   1and, however expressed, is effective if it indicates the intention of
2the buyer not to be bound by the contract.

3begin insert

begin insertSEC. 45.end insert  

end insert

begin insertSection 397 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

begin delete
4

397.  

(a) Notwithstanding subdivision (a) of Section 368, to
5ensure the continued safe and reliable provision of electric service
6during the transition to competition, and to limit the effect of fuel
7price volatility in electric rates paid by California consumers, it is
8in the public interest to allow an electrical corporation which is
9also a gas corporation and served fewer than four million customers
10as of December 20, 1995, to file with the commission a rate cap
11mechanism which shall include a Fuel Price Index Mechanism
12requiring limited adjustments in an electrical corporation’s
13authorized System Average Rate in effect on June 10, 1996, to
14reflect price changes in the fuel market. The commission shall
15authorize an electrical corporation to implement a rate cap
16mechanism which includes a Fuel Price Index Mechanism provided
17the following criteria are met:

18(1) The Fuel Price Index Mechanism shall be based on the
19Southern California Border Index price for natural gas as published
20periodically in Natural Gas Intelligence Magazine. The “Starting
21Point” of the Fuel Price Index Mechanism shall be defined as the
22California Border Index price as published in Natural Gas
23Intelligence for January 1, 1996.

24(2) The Fuel Price Index Mechanism shall include a “deadband”
25defined as a price range for natural gas that is any price up to 10
26percent higher, or lower, than the Starting Point.

27(3) The electrical corporation shall not file for a change in its
28authorized System Average Rate unless the California Border
29Index price, on a 12-month, rolling average basis, is outside the
30deadband. If the published California Border Index is outside of
31the deadband, the electrical corporation shall increase, or decrease,
32its authorized System Average Rate by an amount equal to the
33product of 25 percent multiplied by the percentage by which the
3412-month rolling average natural gas price is higher, or lower, than
35the deadband.

36(4) In no case shall an electrical corporation’s authorized System
37Average Rate under the Fuel Price Index Mechanism exceed the
38average of the authorized system average rates for the two largest
39electrical corporations as of June 10, 1996.

P59   1(5) This section shall become inoperative on December 31,
22001.

end delete
3begin insert

begin insertSEC. 46.end insert  

end insert

begin insertSection 399.2 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
4to read:end insert

5

399.2.  

(a) (1) It is the policy of this state, and the intent of the
6Legislature, to reaffirm that each electrical corporation shall
7continue to operate its electric distribution grid in its service
8territory and shall do so in a safe, reliable, efficient, and
9cost-effective manner.

10(2) In furtherance of this policy, it is the intent of the Legislature
11that each electrical corporation shall continue to be responsible
12for operating its own electric distribution grid including, but not
13limited to, owning, controlling, operating, managing, maintaining,
14planning, engineering, designing, and constructing its own electric
15distribution grid, emergency response and restoration, service
16connections, service turnons and turnoffs, and service inquiries
17relating to the operation of its electric distribution grid, subject to
18the commission’s authority.

19(b) In order to ensure the continued efficient use, and
20cost-effective, safe, and reliable operation of the electric
21distribution grid, each electrical corporation shall continue to
22operate its electric distribution grid in its servicebegin delete territory consistent
23with Section 330.end delete
begin insert territory.end insert

24(c) In carrying out the purposes of this section, each electrical
25corporation shall continue to make reasonable investments in its
26electric distribution grid. Each electrical corporation shall continue
27to have a reasonable opportunity to fully recover from all customers
28of the electrical corporation, in a manner determined by the
29commission pursuant to this code, all of the following:

30(1) Reasonable investments in its electric distribution grid.

31(2) A reasonable return on the investments in its electric
32distribution grid.

33(3) Reasonable costs to operate its electric distribution grid.

34(d) For purposes of this section, the term “electric distribution
35grid” means those facilities owned or operated by an electrical
36corporation that are not under the control of the Independent
37System Operator and that are used to transmit, deliver, or furnish
38electricity for light, heat, or power.

39(e) Nothing in this section shall be construed to alter or to affect
40any of the following:

P60   1(1) Section 216, 218, or 2827.

2(2) The authority of the commission to establish and enforce
3standards and tariff conditions for the interconnection of
4customer-owned facilities to the electric distribution grid.

5(3) The ratemaking authority of the commission under this code.

6(4) The authority of the commission to establish rules governing
7the extension of service to new customers.

8(f) Nothing in this section shall be construed to alter or affect
9any authority or lack of authority of the commission regarding the
10ownership and operation of new electric generation used in whole,
11or in part, for the purpose of maintaining or enhancing the
12reliability of the electric distribution grid.

13(g) Nothing in this section diminishes or expands any existing
14authority of a local governmental entity.

15(h) The commission shall require every electrical corporation
16operating an electric distribution grid to inform all customers who
17request residential service connections via telephone of the
18availability of the California Alternative Rates for Energy (CARE)
19program and how they may qualify for and obtain these services
20and shall accept applications for the CARE program according to
21procedures specified by the commission. Electrical corporations
22shall recover the reasonable costs of implementing this subdivision.

23begin insert

begin insertSEC. 47.end insert  

end insert

begin insertArticle 5.5 (commencing with Section 840) of Chapter
244 of Part 1 of Division 1 of the end insert
begin insertPublic Utilities Codeend insertbegin insert is repealed.end insert

25begin insert

begin insertSEC. 48.end insert  

end insert

begin insertSection 2827 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
26to read:end insert

27

2827.  

(a) The Legislature finds and declares that a program
28to provide net energy metering combined with net surplus
29compensation, co-energy metering, and wind energy co-metering
30for eligible customer-generators is one way to encourage substantial
31private investment in renewable energy resources, stimulate in-state
32economic growth, reduce demand for electricity during peak
33consumption periods, help stabilize California’s energy supply
34infrastructure, enhance the continued diversification of California’s
35energy resource mix, reduce interconnection and administrative
36costs for electricity suppliers, and encourage conservation and
37efficiency.

38(b) As used in this section, the following terms have the
39following meanings:

P61   1(1) “Co-energy metering” means a program that is the same in
2all other respects as a net energy metering program, except that
3the local publicly owned electric utility has elected to apply a
4generation-to-generation energy and time-of-use credit formula
5as provided in subdivision (i).

6(2) “Electrical cooperative” means an electrical cooperative as
7defined in Section 2776.

8(3) “Electric utility” means an electrical corporation, a local
9publicly owned electric utility, or an electrical cooperative, or any
10other entity, except an electric service provider, that offers electrical
11service. This section shall not apply to a local publicly owned
12electric utility that serves more than 750,000 customers and that
13also conveys water to its customers.

14(4) (A) “Eligible customer-generator” means a residential
15customer, small commercial customer as defined in subdivision
16begin delete (h)end deletebegin insert (f)end insert of Section 331, or commercial, industrial, or agricultural
17customer of an electric utility, who uses a renewable electrical
18generation facility, or a combination of those facilities, with a total
19capacity of not more than one megawatt, that is located on the
20customer’s owned, leased, or rented premises, and is interconnected
21and operates in parallel with the electrical grid, and is intended
22primarily to offset part or all of the customer’s own electrical
23requirements.

24(B) (i) Notwithstanding subparagraph (A), “eligible
25customer-generator” includes the Department of Corrections and
26Rehabilitation using a renewable electrical generation technology,
27or a combination of renewable electrical generation technologies,
28with a total capacity of not more than eight megawatts, that is
29located on the department’s owned, leased, or rented premises,
30and is interconnected and operates in parallel with the electrical
31grid, and is intended primarily to offset part or all of the facility’s
32own electrical requirements. The amount of any wind generation
33exported to the electrical grid shall not exceed 1.35 megawatt at
34any time.

35(ii) Notwithstanding any other law, an electrical corporation
36shall be afforded a prudent but necessary time, as determined by
37the executive director of the commission, to study the impacts of
38a request for interconnection of a renewable generator with a
39capacity of greater than one megawatt under this subparagraph. If
40the study reveals the need for upgrades to the transmission or
P62   1distribution system arising solely from the interconnection, the
2electrical corporation shall be afforded the time necessary to
3complete those upgrades before the interconnection and those costs
4shall be borne by the customer-generator. Upgrade projects shall
5comply with applicable state and federal requirements, including
6 requirements of the Federal Energy Regulatory Commission.

7(5) “Large electrical corporation” means an electrical
8corporation with more than 100,000 service connections in
9California.

10(6) “Net energy metering” means measuring the difference
11between the electricity supplied through the electrical grid and the
12electricity generated by an eligible customer-generator and fed
13back to the electrical grid over a 12-month period as described in
14subdivisions (c) and (h).

15(7) “Net surplus customer-generator” means an eligible
16customer-generator that generates more electricity during a
1712-month period than is supplied by the electric utility to the
18eligible customer-generator during the same 12-month period.

19(8) “Net surplus electricity” means all electricity generated by
20an eligible customer-generator measured in kilowatthours over a
2112-month period that exceeds the amount of electricity consumed
22by that eligible customer-generator.

23(9) “Net surplus electricity compensation” means a per
24kilowatthour rate offered by the electric utility to the net surplus
25customer-generator for net surplus electricity that is set by the
26ratemaking authority pursuant to subdivision (h).

27(10) “Ratemaking authority” means, for an electrical
28corporation, the commission, for an electrical cooperative, its
29ratesetting body selected by its shareholders or members, and for
30a local publicly owned electric utility, the local elected body
31responsible for setting the rates of the local publicly owned utility.

32(11) “Renewable electrical generation facility” means a facility
33that generates electricity from a renewable source listed in
34paragraph (1) of subdivision (a) of Section 25741 of the Public
35Resources Code. A small hydroelectric generation facility is not
36an eligible renewable electrical generation facility if it will cause
37an adverse impact on instream beneficial uses or cause a change
38in the volume or timing of streamflow.

39(12) “Wind energy co-metering” means any wind energy project
40greater than 50 kilowatts, but not exceeding one megawatt, where
P63   1the difference between the electricity supplied through the electrical
2grid and the electricity generated by an eligible customer-generator
3and fed back to the electrical grid over a 12-month period is as
4described in subdivision (h). Wind energy co-metering shall be
5accomplished pursuant to Section 2827.8.

6(c) (1) Except as provided in paragraph (4) and in Section
72827.1, every electric utility shall develop a standard contract or
8tariff providing for net energy metering, and shall make this
9standard contract or tariff available to eligible customer-generators,
10upon request, on a first-come-first-served basis until the time that
11the total rated generating capacity used by eligible
12customer-generators exceeds 5 percent of the electric utility’s
13aggregate customer peak demand. Net energy metering shall be
14accomplished using a single meter capable of registering the flow
15of electricity in two directions. An additional meter or meters to
16monitor the flow of electricity in each direction may be installed
17with the consent of the eligible customer-generator, at the expense
18of the electric utility, and the additional metering shall be used
19only to provide the information necessary to accurately bill or
20credit the eligible customer-generator pursuant to subdivision (h),
21or to collect generating system performance information for
22research purposes relative to a renewable electrical generation
23facility. If the existing electrical meter of an eligible
24customer-generator is not capable of measuring the flow of
25electricity in two directions, the eligible customer-generator shall
26be responsible for all expenses involved in purchasing and
27installing a meter that is able to measure electricity flow in two
28directions. If an additional meter or meters are installed, the net
29energy metering calculation shall yield a result identical to that of
30a single meter. An eligible customer-generator that is receiving
31service other than through the standard contract or tariff may elect
32to receive service through the standard contract or tariff until the
33electric utility reaches the generation limit set forth in this
34paragraph. Once the generation limit is reached, only eligible
35customer-generators that had previously elected to receive service
36pursuant to the standard contract or tariff have a right to continue
37to receive service pursuant to the standard contract or tariff.
38Eligibility for net energy metering does not limit an eligible
39customer-generator’s eligibility for any other rebate, incentive, or
40credit provided by the electric utility, or pursuant to any
P64   1governmental program, including rebates and incentives provided
2pursuant to the California Solar Initiative.

3(2) An electrical corporation shall include a provision in the net
4energy metering contract or tariff requiring that any customer with
5an existing electrical generating facility and meter who enters into
6a new net energy metering contract shall provide an inspection
7report to the electrical corporation, unless the electrical generating
8facility and meter have been installed or inspected within the
9previous three years. The inspection report shall be prepared by a
10California licensed contractor who is not the owner or operator of
11the facility and meter. A California licensed electrician shall
12perform the inspection of the electrical portion of the facility and
13meter.

14(3) (A) On an annual basis, every electric utility shall make
15available to the ratemaking authority information on the total rated
16generating capacity used by eligible customer-generators that are
17customers of that provider in the provider’s service area and the
18net surplus electricity purchased by the electric utility pursuant to
19this section.

20(B) An electric service provider operating pursuant to Section
21394 shall make available to the ratemaking authority the
22information required by this paragraph for each eligible
23customer-generator that is their customer for each service area of
24an electrical corporation, local publicly owned electrical utility,
25or electrical cooperative, in which the eligible customer-generator
26has net energy metering.

27(C) The ratemaking authority shall develop a process for making
28the information required by this paragraph available to electric
29utilities, and for using that information to determine when, pursuant
30to paragraphs (1) and (4), an electric utility is not obligated to
31provide net energy metering to additional eligible
32customer-generators in its service area.

33(4) (A) An electric utility that is not a large electrical
34corporation is not obligated to provide net energy metering to
35additional eligible customer-generators in its service area when
36the combined total peak demand of all electricity used by eligible
37customer-generators served by all the electric utilities in that
38service area furnishing net energy metering to eligible
39customer-generators exceeds 5 percent of the aggregate customer
40peak demand of those electric utilities.

P65   1(B)  The commission shall require every large electrical
2corporation to make the standard contract or tariff available to
3eligible customer-generators, continuously and without
4interruption, until such times as the large electrical corporation
5reaches its net energy metering program limit or July 1, 2017,
6whichever is earlier. A large electrical corporation reaches its
7program limit when the combined total peak demand of all
8electricity used by eligible customer-generators served by all the
9electric utilities in the large electrical corporation’s service area
10furnishing net energy metering to eligible customer-generators
11exceeds 5 percent of the aggregate customer peak demand of those
12electric utilities. For purposes of calculating a large electrical
13corporation’s program limit, “aggregate customer peak demand”
14means the highest sum of the noncoincident peak demands of all
15of the large electrical corporation’s customers that occurs in any
16calendar year. To determine the aggregate customer peak demand,
17every large electrical corporation shall use a uniform method
18approved by the commission. The program limit calculated
19pursuant to this paragraph shall not be less than the following:

20(i) For San Diego Gas and Electric Company, when it has made
21607 megawatts of nameplate generating capacity available to
22eligible customer-generators.

23(ii) For Southern California Edison Company, when it has made
242,240 megawatts of nameplate generating capacity available to
25eligible customer-generators.

26(iii) For Pacific Gas and Electric Company, when it has made
272,409 megawatts of nameplate generating capacity available to
28eligible customer-generators.

29(C) Every large electrical corporation shall file a monthly report
30with the commission detailing the progress toward the net energy
31metering program limit established in subparagraph (B). The report
32shall include separate calculations on progress toward the limits
33based on operating solar energy systems, cumulative numbers of
34interconnection requests for net energy metering eligible systems,
35and any other criteria required by the commission.

36(D) Beginning July 1, 2017, or upon reaching the net metering
37program limit of subparagraph (B), whichever is earlier, the
38obligation of a large electrical corporation to provide service
39pursuant to a standard contract or tariff shall be pursuant to Section
402827.1 and applicable state and federal requirements.

P66   1(d) Every electric utility shall make all necessary forms and
2contracts for net energy metering and net surplus electricity
3compensation service available for download from the Internet.

4(e) (1) Every electric utility shall ensure that requests for
5 establishment of net energy metering and net surplus electricity
6compensation are processed in a time period not exceeding that
7for similarly situated customers requesting new electric service,
8but not to exceed 30 working days from the date it receives a
9completed application form for net energy metering service or net
10surplus electricity compensation, including a signed interconnection
11agreement from an eligible customer-generator and the electric
12inspection clearance from the governmental authority having
13jurisdiction.

14(2) Every electric utility shall ensure that requests for an
15interconnection agreement from an eligible customer-generator
16are processed in a time period not to exceed 30 working days from
17the date it receives a completed application form from the eligible
18customer-generator for an interconnection agreement.

19(3) If an electric utility is unable to process a request within the
20allowable timeframe pursuant to paragraph (1) or (2), it shall notify
21the eligible customer-generator and the ratemaking authority of
22the reason for its inability to process the request and the expected
23completion date.

24(f) (1) If a customer participates in direct transactions pursuant
25to paragraph (1) of subdivision (b) of Section 365, or Section 365.1,
26with an electric service provider that does not provide distribution
27service for the direct transactions, the electric utility that provides
28distribution service for the eligible customer-generator is not
29obligated to provide net energy metering or net surplus electricity
30compensation to the customer.

31(2) If a customer participates in direct transactions pursuant to
32paragraph (1) of subdivision (b) of Section 365 or 365.1 with an
33electric service provider, and the customer is an eligible
34 customer-generator, the electric utility that provides distribution
35service for the direct transactions may recover from the customer’s
36electric service provider the incremental costs of metering and
37billing service related to net energy metering and net surplus
38electricity compensation in an amount set by the ratemaking
39authority.

P67   1(g) Except for the time-variant kilowatthour pricing portion of
2any tariff adopted by the commission pursuant to paragraph (4) of
3subdivision (a) of Section 2851, each net energy metering contract
4or tariff shall be identical, with respect to rate structure, all retail
5rate components, and any monthly charges, to the contract or tariff
6to which the same customer would be assigned if the customer did
7not use a renewable electrical generation facility, except that
8eligible customer-generators shall not be assessed standby charges
9on the electrical generating capacity or the kilowatthour production
10of a renewable electrical generation facility. The charges for all
11retail rate components for eligible customer-generators shall be
12based exclusively on the customer-generator’s net kilowatthour
13consumption over a 12-month period, without regard to the eligible
14customer-generator’s choice as to from whom it purchases
15electricity that is not self-generated. Any new or additional demand
16charge, standby charge, customer charge, minimum monthly
17charge, interconnection charge, or any other charge that would
18increase an eligible customer-generator’s costs beyond those of
19other customers who are not eligible customer-generators in the
20rate class to which the eligible customer-generator would otherwise
21be assigned if the customer did not own, lease, rent, or otherwise
22operate a renewable electrical generation facility is contrary to the
23intent of this section, and shall not form a part of net energy
24metering contracts or tariffs.

25(h) For eligible customer-generators, the net energy metering
26calculation shall be made by measuring the difference between
27the electricity supplied to the eligible customer-generator and the
28electricity generated by the eligible customer-generator and fed
29back to the electrical grid over a 12-month period. The following
30rules shall apply to the annualized net metering calculation:

31(1) The eligible residential or small commercial
32customer-generator, at the end of each 12-month period following
33the date of final interconnection of the eligible
34customer-generator’s system with an electric utility, and at each
35anniversary date thereafter, shall be billed for electricity used
36during that 12-month period. The electric utility shall determine
37if the eligible residential or small commercial customer-generator
38was a net consumer or a net surplus customer-generator during
39that period.

P68   1(2) At the end of each 12-month period, where the electricity
2supplied during the period by the electric utility exceeds the
3electricity generated by the eligible residential or small commercial
4customer-generator during that same period, the eligible residential
5or small commercial customer-generator is a net electricity
6consumer and the electric utility shall be owed compensation for
7the eligible customer-generator’s net kilowatthour consumption
8over that 12-month period. The compensation owed for the eligible
9residential or small commercial customer-generator’s consumption
10shall be calculated as follows:

11(A) For all eligible customer-generators taking service under
12contracts or tariffs employing “baseline” and “over baseline” rates,
13any net monthly consumption of electricity shall be calculated
14according to the terms of the contract or tariff to which the same
15customer would be assigned to, or be eligible for, if the customer
16was not an eligible customer-generator. If those same
17 customer-generators are net generators over a billing period, the
18net kilowatthours generated shall be valued at the same price per
19kilowatthour as the electric utility would charge for the baseline
20quantity of electricity during that billing period, and if the number
21of kilowatthours generated exceeds the baseline quantity, the excess
22shall be valued at the same price per kilowatthour as the electric
23utility would charge for electricity over the baseline quantity during
24that billing period.

25(B) For all eligible customer-generators taking service under
26contracts or tariffs employing time-of-use rates, any net monthly
27consumption of electricity shall be calculated according to the
28terms of the contract or tariff to which the same customer would
29be assigned, or be eligible for, if the customer was not an eligible
30customer-generator. When those same customer-generators are
31net generators during any discrete time-of-use period, the net
32 kilowatthours produced shall be valued at the same price per
33kilowatthour as the electric utility would charge for retail
34kilowatthour sales during that same time-of-use period. If the
35eligible customer-generator’s time-of-use electrical meter is unable
36to measure the flow of electricity in two directions, paragraph (1)
37of subdivision (c) shall apply.

38(C) For all eligible residential and small commercial
39customer-generators and for each billing period, the net balance
40of moneys owed to the electric utility for net consumption of
P69   1electricity or credits owed to the eligible customer-generator for
2net generation of electricity shall be carried forward as a monetary
3value until the end of each 12-month period. For all eligible
4commercial, industrial, and agricultural customer-generators, the
5net balance of moneys owed shall be paid in accordance with the
6electric utility’s normal billing cycle, except that if the eligible
7commercial, industrial, or agricultural customer-generator is a net
8electricity producer over a normal billing cycle, any excess
9kilowatthours generated during the billing cycle shall be carried
10over to the following billing period as a monetary value, calculated
11according to the procedures set forth in this section, and appear as
12a credit on the eligible commercial, industrial, or agricultural
13customer-generator’s account, until the end of the annual period
14when paragraph (3) shall apply.

15(3) At the end of each 12-month period, where the electricity
16generated by the eligible customer-generator during the 12-month
17period exceeds the electricity supplied by the electric utility during
18that same period, the eligible customer-generator is a net surplus
19customer-generator and the electric utility, upon an affirmative
20election by the net surplus customer-generator, shall either (A)
21provide net surplus electricity compensation for any net surplus
22electricity generated during the prior 12-month period, or (B) allow
23the net surplus customer-generator to apply the net surplus
24electricity as a credit for kilowatthours subsequently supplied by
25the electric utility to the net surplus customer-generator. For an
26eligible customer-generator that does not affirmatively elect to
27receive service pursuant to net surplus electricity compensation,
28the electric utility shall retain any excess kilowatthours generated
29during the prior 12-month period. The eligible customer-generator
30not affirmatively electing to receive service pursuant to net surplus
31electricity compensation shall not be owed any compensation for
32the net surplus electricity unless the electric utility enters into a
33purchase agreement with the eligible customer-generator for those
34excess kilowatthours. Every electric utility shall provide notice to
35eligible customer-generators that they are eligible to receive net
36surplus electricity compensation for net surplus electricity, that
37they must elect to receive net surplus electricity compensation,
38and that the 12-month period commences when the electric utility
39receives the eligible customer-generator’s election. For an electric
40utility that is an electrical corporation or electrical cooperative,
P70   1the commission may adopt requirements for providing notice and
2the manner by which eligible customer-generators may elect to
3receive net surplus electricity compensation.

4(4) (A) An eligible customer-generator with multiple meters
5may elect to aggregate the electrical load of the meters located on
6the property where the renewable electrical generation facility is
7located and on all property adjacent or contiguous to the property
8on which the renewable electrical generation facility is located, if
9those properties are solely owned, leased, or rented by the eligible
10customer-generator. If the eligible customer-generator elects to
11aggregate the electric load pursuant to this paragraph, the electric
12utility shall use the aggregated load for the purpose of determining
13whether an eligible customer-generator is a net consumer or a net
14surplus customer-generator during a 12-month period.

15(B) If an eligible customer-generator chooses to aggregate
16pursuant to subparagraph (A), the eligible customer-generator shall
17be permanently ineligible to receive net surplus electricity
18compensation, and the electric utility shall retain any kilowatthours
19in excess of the eligible customer-generator’s aggregated electrical
20load generated during the 12-month period.

21(C) If an eligible customer-generator with multiple meters elects
22to aggregate the electrical load of those meters pursuant to
23subparagraph (A), and different rate schedules are applicable to
24service at any of those meters, the electricity generated by the
25renewable electrical generation facility shall be allocated to each
26of the meters in proportion to the electrical load served by those
27meters. For example, if the eligible customer-generator receives
28electric service through three meters, two meters being at an
29agricultural rate that each provide service to 25 percent of the
30customer’s total load, and a third meter, at a commercial rate, that
31provides service to 50 percent of the customer’s total load, then
3250 percent of the electrical generation of the eligible renewable
33generation facility shall be allocated to the third meter that provides
34service at the commercial rate and 25 percent of the generation
35shall be allocated to each of the two meters providing service at
36the agricultural rate. This proportionate allocation shall be
37computed each billing period.

38(D) This paragraph shall not become operative for an electrical
39corporation unless the commission determines that allowing
40eligible customer-generators to aggregate their load from multiple
P71   1meters will not result in an increase in the expected revenue
2obligations of customers who are not eligible customer-generators.
3The commission shall make this determination by September 30,
42013. In making this determination, the commission shall determine
5if there are any public purpose or other noncommodity charges
6that the eligible customer-generators would pay pursuant to the
7net energy metering program as it exists prior to aggregation, that
8the eligible customer-generator would not pay if permitted to
9aggregate the electrical load of multiple meters pursuant to this
10paragraph.

11(E) A local publicly owned electric utility or electrical
12cooperative shall only allow eligible customer-generators to
13aggregate their load if the utility’s ratemaking authority determines
14that allowing eligible customer-generators to aggregate their load
15from multiple meters will not result in an increase in the expected
16revenue obligations of customers that are not eligible
17 customer-generators. The ratemaking authority of a local publicly
18owned electric utility or electrical cooperative shall make this
19determination within 180 days of the first request made by an
20eligible customer-generator to aggregate their load. In making the
21determination, the ratemaking authority shall determine if there
22are any public purpose or other noncommodity charges that the
23eligible customer-generator would pay pursuant to the net energy
24metering or co-energy metering program of the utility as it exists
25prior to aggregation, that the eligible customer-generator would
26not pay if permitted to aggregate the electrical load of multiple
27meters pursuant to this paragraph. If the ratemaking authority
28determines that load aggregation will not cause an incremental
29rate impact on the utility’s customers that are not eligible
30customer-generators, the local publicly owned electric utility or
31electrical cooperative shall permit an eligible customer-generator
32to elect to aggregate the electrical load of multiple meters pursuant
33to this paragraph. The ratemaking authority may reconsider any
34determination made pursuant to this subparagraph in a subsequent
35public proceeding.

36(F) For purposes of this paragraph, parcels that are divided by
37a street, highway, or public thoroughfare are considered contiguous,
38provided they are otherwise contiguous and under the same
39ownership.

P72   1(G) An eligible customer-generator may only elect to aggregate
2the electrical load of multiple meters if the renewable electrical
3generation facility, or a combination of those facilities, has a total
4generating capacity of not more than one megawatt.

5(H) Notwithstanding subdivision (g), an eligible
6customer-generator electing to aggregate the electrical load of
7multiple meters pursuant to this subdivision shall remit service
8charges for the cost of providing billing services to the electric
9utility that provides service to the meters.

10(5) (A) The ratemaking authority shall establish a net surplus
11electricity compensation valuation to compensate the net surplus
12customer-generator for the value of net surplus electricity generated
13by the net surplus customer-generator. The commission shall
14establish the valuation in a ratemaking proceeding. The ratemaking
15authority for a local publicly owned electric utility shall establish
16the valuation in a public proceeding. The net surplus electricity
17compensation valuation shall be established so as to provide the
18net surplus customer-generator just and reasonable compensation
19for the value of net surplus electricity, while leaving other
20ratepayers unaffected. The ratemaking authority shall determine
21whether the compensation will include, where appropriate
22justification exists, either or both of the following components:

23(i) The value of the electricity itself.

24(ii) The value of the renewable attributes of the electricity.

25(B) In establishing the rate pursuant to subparagraph (A), the
26ratemaking authority shall ensure that the rate does not result in a
27shifting of costs between eligible customer-generators and other
28bundled service customers.

29(6) (A) Upon adoption of the net surplus electricity
30compensation rate by the ratemaking authority, any renewable
31energy credit, as defined in Section 399.12, for net surplus
32electricity purchased by the electric utility shall belong to the
33electric utility. Any renewable energy credit associated with
34electricity generated by the eligible customer-generator that is
35utilized by the eligible customer-generator shall remain the property
36of the eligible customer-generator.

37(B) Upon adoption of the net surplus electricity compensation
38rate by the ratemaking authority, the net surplus electricity
39purchased by the electric utility shall count toward the electric
40utility’s renewables portfolio standard annual procurement targets
P73   1for the purposes of paragraph (1) of subdivision (b) of Section
2399.15, or for a local publicly owned electric utility, the renewables
3portfolio standard annual procurement targets established pursuant
4to Section 399.30.

5(7) The electric utility shall provide every eligible residential
6or small commercial customer-generator with net electricity
7consumption and net surplus electricity generation information
8with each regular bill. That information shall include the current
9monetary balance owed the electric utility for net electricity
10consumed, or the net surplus electricity generated, since the last
1112-month period ended. Notwithstanding this subdivision, an
12electric utility shall permit that customer to pay monthly for net
13energy consumed.

14(8) If an eligible residential or small commercial
15customer-generator terminates the customer relationship with the
16electric utility, the electric utility shall reconcile the eligible
17customer-generator’s consumption and production of electricity
18during any part of a 12-month period following the last
19reconciliation, according to the requirements set forth in this
20subdivision, except that those requirements shall apply only to the
21months since the most recent 12-month bill.

22(9) If an electric service provider or electric utility providing
23net energy metering to a residential or small commercial
24customer-generator ceases providing that electric service to that
25customer during any 12-month period, and the customer-generator
26enters into a new net energy metering contract or tariff with a new
27electric service provider or electric utility, the 12-month period,
28with respect to that new electric service provider or electric utility,
29shall commence on the date on which the new electric service
30provider or electric utility first supplies electric service to the
31customer-generator.

32(i) Notwithstanding any other provisions of this section,
33paragraphs (1), (2), and (3) shall apply to an eligible
34customer-generator with a capacity of more than 10 kilowatts, but
35not exceeding one megawatt, that receives electric service from a
36local publicly owned electric utility that has elected to utilize a
37co-energy metering program unless the local publicly owned
38electric utility chooses to provide service for eligible
39customer-generators with a capacity of more than 10 kilowatts in
40accordance with subdivisions (g) and (h):

P74   1(1) The eligible customer-generator shall be required to utilize
2a meter, or multiple meters, capable of separately measuring
3electricity flow in both directions. All meters shall provide
4time-of-use measurements of electricity flow, and the customer
5shall take service on a time-of-use rate schedule. If the existing
6meter of the eligible customer-generator is not a time-of-use meter
7or is not capable of measuring total flow of electricity in both
8directions, the eligible customer-generator shall be responsible for
9all expenses involved in purchasing and installing a meter that is
10both time-of-use and able to measure total electricity flow in both
11directions. This subdivision shall not restrict the ability of an
12eligible customer-generator to utilize any economic incentives
13provided by a governmental agency or an electric utility to reduce
14its costs for purchasing and installing a time-of-use meter.

15(2) The consumption of electricity from the local publicly owned
16electric utility shall result in a cost to the eligible
17customer-generator to be priced in accordance with the standard
18rate charged to the eligible customer-generator in accordance with
19the rate structure to which the customer would be assigned if the
20customer did not use a renewable electrical generation facility.
21The generation of electricity provided to the local publicly owned
22electric utility shall result in a credit to the eligible
23customer-generator and shall be priced in accordance with the
24generation component, established under the applicable structure
25to which the customer would be assigned if the customer did not
26use a renewable electrical generation facility.

27(3) All costs and credits shall be shown on the eligible
28customer-generator’s bill for each billing period. In any months
29in which the eligible customer-generator has been a net consumer
30of electricity calculated on the basis of value determined pursuant
31to paragraph (2), the customer-generator shall owe to the local
32publicly owned electric utility the balance of electricity costs and
33credits during that billing period. In any billing period in which
34the eligible customer-generator has been a net producer of
35electricity calculated on the basis of value determined pursuant to
36paragraph (2), the local publicly owned electric utility shall owe
37to the eligible customer-generator the balance of electricity costs
38and credits during that billing period. Any net credit to the eligible
39customer-generator of electricity costs may be carried forward to
40subsequent billing periods, provided that a local publicly owned
P75   1electric utility may choose to carry the credit over as a kilowatthour
2credit consistent with the provisions of any applicable contract or
3tariff, including any differences attributable to the time of
4generation of the electricity. At the end of each 12-month period,
5the local publicly owned electric utility may reduce any net credit
6due to the eligible customer-generator to zero.

7(j) A renewable electrical generation facility used by an eligible
8customer-generator shall meet all applicable safety and
9performance standards established by the National Electrical Code,
10the Institute of Electrical and Electronics Engineers, and accredited
11testing laboratories, including Underwriters Laboratories
12Incorporated and, where applicable, rules of the commission
13regarding safety and reliability. A customer-generator whose
14renewable electrical generation facility meets those standards and
15rules shall not be required to install additional controls, perform
16or pay for additional tests, or purchase additional liability
17insurance.

18(k) If the commission determines that there are cost or revenue
19obligations for an electrical corporation that may not be recovered
20from customer-generators acting pursuant to this section, those
21obligations shall remain within the customer class from which any
22shortfall occurred and shall not be shifted to any other customer
23class. Net energy metering and co-energy metering customers shall
24not be exempt from the public goods charges imposed pursuant to
25Article 7 (commencing with Section 381), Article 8 (commencing
26with Section 385), or Article 15 (commencing with Section 399)
27of Chapter 2.3 of Part 1.

28(l) A net energy metering, co-energy metering, or wind energy
29co-metering customer shall reimburse the Department of Water
30Resources for all charges that would otherwise be imposed on the
31customer by the commission to recover bond-related costs pursuant
32to an agreement between the commission and the Department of
33Water Resources pursuant to Section 80110 of the Water Code,
34as well as the costs of the department equal to the share of the
35department’s estimated net unavoidable power purchase contract
36costs attributable to the customer. The commission shall
37incorporate the determination into an existing proceeding before
38the commission, and shall ensure that the charges are
39nonbypassable. Until the commission has made a determination
40regarding the nonbypassable charges, net energy metering,
P76   1co-energy metering, and wind energy co-metering shall continue
2under the same rules, procedures, terms, and conditions as were
3applicable on December 31, 2002.

4(m) In implementing the requirements of subdivisions (k) and
5(l), an eligible customer-generator shall not be required to replace
6its existing meter except as set forth in paragraph (1) of subdivision
7(c), nor shall the electric utility require additional measurement of
8usage beyond that which is necessary for customers in the same
9rate class as the eligible customer-generator.

10(n) It is the intent of the Legislature that the Treasurer
11incorporate net energy metering, including net surplus electricity
12compensation, co-energy metering, and wind energy co-metering
13projects undertaken pursuant to this section as sustainable building
14methods or distributive energy technologies for purposes of
15evaluating low-income housing projects.

16begin insert

begin insertSEC. 49.end insert  

end insert

begin insertSection 9600 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
17to read:end insert

18

9600.  

(a) It is the intent of the Legislature that California’s
19local publicly owned electric utilities and electric corporations
20should commit control of their transmission facilities to the
21Independent System Operator as described in Chapter 2.3
22(commencing with Section 330) of Part 1 of Division 1. These
23utilities should jointly advocate to the Federal Energy Regulatory
24Commission a pricing methodology for the Independent System
25Operator that results in an equitable return on capital investment
26in transmission facilities for all Independent System Operator
27participants and is based on the following principles:

28(1) Utility specific access charge rates as proposed in Docket
29No. EC96-19-000 as finally approved by the Federal Energy
30Regulatory Commission reflecting the costs of that utility’s
31transmission facilities shall go into effect on the first day of the
32Independent System Operator operation. The utility specific rates
33shall honor all of the terms and conditions of existing transmission
34service contracts and shall recognize any wheeling revenues of
35existing transmission service arrangements to the transmission
36owner.

37(2) (A) No later than two years after the initial operation of the
38Independent System Operator, the Independent System Operator
39shall recommend for adoption by the Federal Energy Regulatory
40Commission a rate methodology determined by a decision of the
P77   1Independent System Operator governing board, provided that the
2decision shall be based on principles approved by the governing
3board including, but not limited to, an equitable balance of costs
4and benefits, and shall define the transmission facility costs, if
5any, which shall be rolled in to the transmission service rate and
6spread equally among all Independent System Operator
7transmission users, and those transmission facility costs, if any,
8which should be specifically assigned to a specific utility’s service
9area.

10(B) If there is no governing board decision, the rate methodology
11shall be determined following a decision by the alternative dispute
12resolution method set forth in the Independent System Operator
13bylaws.

14(C) If no alternative dispute resolution decision is rendered,
15then a default rate methodology shall be a uniform regional
16transmission access charge and a utility specific local transmission
17access charge, provided that the default rate methodology shall be
18recommended for implementation upon termination of the cost
19recovery planbegin delete set forth in Section 368end delete or no later than two years
20after the initial operation of the Independent System Operator,
21whichever is later. For purposes of this paragraph, regional
22transmission facilities are defined to be transmission facilities
23operating at or above 230 kilovolts plus an appropriate percentage
24of transmission facilities operating below 230 kilovolts; all other
25transmission facilities shall be considered local. The appropriate
26percentage of transmission facilities described above shall be
27consistent with the guidelines in Federal Energy Regulatory
28Commission Order No. 888 and any exception approved by that
29commission.

30(3) If the rate methodology implemented as a result of a decision
31by the Independent System Operator governing board or resulting
32from thebegin delete independent system operatorend deletebegin insert Independent System
33Operatorend insert
alternative dispute resolution process results in rates
34different than those in effect prior to the decision for any
35transmission facility owner, the amount of any differences between
36the new rates and the prior rates shall be recorded in a tracking
37account to be recovered from customers and paid to the appropriate
38transmission owners by the transmission facility owner after
39termination of the cost recovery plan set forth in Section 368. The
40recovery and payments shall be based on an amortization period
P78   1not to exceed three years in the case of the electrical corporations
2or five years in the case of the local publicly owned electric
3utilities.

4(4) The costs of transmission facilities placed in service after
5the date of initial implementation of the Independent System
6Operator shall be recovered using the rate methodology in effect
7at the time the facilities go into operation.

8(5) The electrical corporations and the local publicly owned
9electric utilities shall jointly develop language for implementation
10proposals to the Federal Energy Regulatory Commission based on
11these principles.

12(6) Nothing in this section shall compel any party to violate
13restrictions applicable to facilities financed with tax-exempt bonds
14or contractual restrictions and covenants regarding use of
15transmission facilities existing as of December 20, 1995.

16(b) Following a final Federal Energy Regulatory Commission
17decision approving the Independent System Operator, no California
18electrical corporation or local publicly owned electric utility shall
19be authorized to collect any competition transition charge
20authorized pursuant to this division and Chapter 2.3 (commencing
21with Section 330) of Part 1 of Division 1 unless it commits control
22of its transmission facilities to the Independent System Operator.

23begin insert

begin insertSEC. 50.end insert  

end insert

begin insertSection 9607 of the end insertbegin insertPublic Utilities Codeend insertbegin insert is amended
24to read:end insert

25

9607.  

(a) The intent of this section is to avoid cost-shifting to
26customers of an electrical corporation resulting from the transfer
27of distribution services from an electrical corporation to an
28irrigation district.

29(b) Except as otherwise provided in this section and Section
309608, and notwithstanding any other provision of law, an irrigation
31district that offered electric service to retail customers as of January
321, 1999, may not construct, lease, acquire, install, or operate
33facilities for the distribution or transmission of electricity to retail
34customers located in the service territory of an electrical
35corporation providing electric distribution services, unless the
36district has first applied for and received the approval of the
37commission and implements its service consistent with the
38commission’s order. The commission shall find that service to be
39in the public interest and shall approve the request of a district to
40provide distribution or transmission of electricity to retail customers
P79   1located in the service territory of an electrical corporation providing
2electric distribution service if, after notice and hearing, the
3commission determines all of the following:

4(1) The district will provide universal service to all retail
5customers who request service within the area to be served, at
6published tariff rates and on a just, reasonable, and
7nondiscriminatory basis, comparable to that provided by the current
8retail service provider.

9(2) If the area the district is proposing to serve is either of the
10following:

11(A) Is within the district’s boundaries but less than the entire
12district, the area to be served includes a percentage of residential
13customers and small customers, based on load, comparable to the
14percentage of residential and small customers in the district, based
15on load.

16(B) Includes territory outside the district’s boundaries, in which
17case the territory outside the district’s boundaries must include a
18percentage of residential customers and small customers, based
19on load, comparable to the percentage of residential and small
20customers in the county or counties where service is to be provided,
21based on load.

22(3) Service by the district will be consistent with the intent of
23the state to avoid economic waste caused by duplication of facilities
24as set forth in Section 8101.

25(4) Service by the district will include reasonable mitigation of
26any adverse effects on the reliability of an existing service by the
27electrical corporation.

28(5) The district has established, funded, and is carrying out
29public purpose and low-income programs comparable to those
30provided by the current electric retail service provider.

31(6) That district’s tariffed electric rates, exclusive of commodity
32costs, will be at least 15 percent below the tariffed electric rates,
33exclusive of commodity costs andbegin delete nonbypassable charges under
34Sections 367, 368, 375, 376, and 379,end delete
begin insert competition transition
35chargesend insert
of the electrical corporation for comparable services.

36(7) Service by the district is in the public interest.

37(c) An irrigation district that obtains the approval of the
38commission under this section to serve an area shall prepare an
39annual report available to the public on the total load and number
40of accounts of residential, low-income, agricultural, commercial,
P80   1and industrial customers served by the irrigation district in the
2approved service area.

3(d) The commission shall have jurisdiction to resolve and
4adjudicate complaint cases brought against an irrigation district
5that offered electric service to retail customers as of January 1,
61999, by an interested party where the complaint concerns retail
7electric service outside the boundaries of the district and within
8the service territory of an electrical corporation. Nothing in this
9section grants the commission jurisdiction to adjudicate complaint
10cases involving retail electric service by an irrigation district inside
11its boundaries or inside an irrigation district’s exclusive service
12territory.

13(e) Any project involving electric transmission or distribution
14facilities to be constructed or installed by an irrigation district to
15serve retail customers located in the service territory of an electrical
16corporation providing electric distribution services shall comply
17with the California Environmental Qualitybegin delete Act,end deletebegin insert Actend insert (Division 13
18(commencing with Section 21000)) of the Public Resources Code.
19The county in which the construction or installation is to occur
20shall act as the lead agency. If a project involves the construction
21or installation of electric transmission or distribution facilities in
22more than one county, the county where the majority of the
23 construction is anticipated to occur shall act as the lead agency.

24(f) An irrigation district may not offer service to customers
25outside of its district boundaries before offering service to all
26customers within its district boundaries.

27(g) This section does not apply to electric distribution service
28provided by Modesto Irrigation District to those customers or
29within those areas described in subdivisions (a), (b), and (c) of
30Section 9610.

31(h) The provisions of this section shall not apply to (1) a
32cumulative 90 megawatts of load served by the Merced Irrigation
33District that is located within the boundaries of Merced Irrigation
34District, as those boundaries existed on December 20, 1995,
35together with the territory of Castle Air Force Base which was
36located outside thebegin delete Districtend deletebegin insert districtend insert on that date, or (2) electric load
37served by thebegin delete Districtend deletebegin insert districtend insert which was not previously served by
38an electric corporation that is located within the boundaries of
39Merced Irrigation District, as those boundaries existed on
P81   1December 20, 1995, together with the territory of Castle Air Force
2Base which was located outside thebegin delete Districtend deletebegin insert districtend insert on that date.

3(i) For purposes of this section, a megawatt of load shall be
4calculated in accordance with the methodology established by the
5begin delete California Energy Resource Conservation and Developmentend deletebegin insert Energyend insert
6 Commission in its Docket No. 96-IRR-1890, but the 90 megawatts
7shall not include electrical usage by customers that move to the
8areas described in paragraph (1) after December 31, 2000.

9(j) Subdivision (a) of this section shall not apply to the
10construction, modification, lease, acquisition, installation, or
11operation of facilities for the distribution or transmission of
12electricity to customers electrically connected to a district as of
13December 31, 2000, or to other customers who subsequently locate
14at the same premises.

15(k) In recognition of contractual arrangements and settlements
16existing as of June 1, 2000, this section does not apply to the
17acquisition or operation of the electric distribution facilities that
18are the subject of the Settlement Agreement dated May 1, 2000,
19between Pacific Gas and Electric Company and the San Joaquin
20Irrigation District.

21(l) For purposes of this section, retail customers do not include
22an irrigation district’s own electric load being served of retail by
23an electrical corporation.

24begin insert

begin insertSEC. 51.end insert  

end insert

begin insertSection 31071.5 of the end insertbegin insertStreets and Highways Codeend insert
25begin insert is amended to read:end insert

26

31071.5.  

(a) Bonds issued under this chapter may not be
27deemed to constitute a debt or liability of the state or of any
28political subdivision thereof, other than the bank, or a pledge of
29the faith and credit of the state or of any political subdivision
30thereof, but shall be payable solely from the account, and the assets
31of the account, and the security provided by the account. All bonds
32issued under this chapter shall contain on the face of the bonds a
33statement to this effect.

34(b) Notwithstanding any other provision of law, Article 3
35(commencing with Sectionbegin delete 63040) of, Article 4 (commencing with
3663042) of,end delete
begin insert 63040)end insert and Article 5 (commencing with Section 63043)
37of Chapter 2 of Division 1 of Title 6.7 of the Government Code
38do not apply to any financing provided by the bank to, or at the
39request of, the department in connection with the account.

begin delete
P82   1

SECTION 1.  

Section 30009 is added to the Penal Code, to read:

2

30009.  

(a) In order to reduce the number of firearms possessed
3by prohibited persons listed in the Prohibited Armed Persons File,
4a 30-day amnesty period shall be established, commencing on a
5date to be determined by the Department of Justice but not later
6than January 1, 2015, during which a person prohibited from
7possessing a firearm may surrender his or her firearms to a local
8law enforcement agency without being charged with illegal
9possession of firearms, as provided in subdivision (e). No person
10convicted of a felony shall be permitted to participate in the
11amnesty period.

12(b) The department shall provide written notification of the
13amnesty period to all prohibited persons eligible to participate in
14the amnesty period by first-class mail no later than 60 calendar
15days prior to the commencement of the amnesty period. The
16notification shall specify the firearms possessed by the prohibited
17person and provide instructions for the surrender of the illegal
18firearms.

19(c) For each instance in which a local law enforcement agency
20receives a firearm from a prohibited person during the amnesty
21period described in subdivision (a), the agency shall submit to the
22department the following information:

23(1) The name of the prohibited person who surrendered the
24firearm.

25(2) The person’s date of birth.

26(3) A description of the firearm or firearms surrendered.

27(4) The serial number of the firearm or firearms surrendered.

28(5) Any other information deemed necessary by the department.

29(d) The department shall enter the information received pursuant
30to subdivision (c) in the Prohibited Armed Persons File to create
31a record of each firearm surrendered during the amnesty period.

32(e) A prohibited person who surrenders a firearm pursuant to
33subdivision (a) shall not be charged with illegal possession of
34firearms for any firearm the department has on record as having
35been surrendered pursuant to subdivision (d).

36(f) At the expiration of the 30-day amnesty period described in
37subdivision (a), a person prohibited from possessing a firearm and
38eligible to participate in the amnesty program who still maintains
39possession of his or her firearms shall be subject to a civil fine of
40up to two thousand five hundred dollars ($2,500) per firearm in
P83   1addition to any criminal penalties authorized by law, including,
2but not limited to, penalties described in Chapter 3 (commencing
3with Section 29900) of this code and Sections 8100 and 8103 of
4the Welfare and Institutions Code.

5(g) A prohibited person shall not to be charged with illegal
6possession of a firearm, nor be subject to the fine described in
7subdivision (f), if he or she provides evidence satisfactory to the
8department that he or she lawfully surrendered his or her firearm
9prior to the commencement of the amnesty period.

10(h) Any firearms surrendered to a local law enforcement agency
11pursuant to this section shall be sold or destroyed as provided in
12Section 18005.

13(i) Sections 26500 and 27545, and subdivision (a) of Section
1431615, shall not apply to the surrender of firearms to a local law
15enforcement agency pursuant to this section.

16

SEC. 2.  

If the Commission on State Mandates determines that
17this act contains costs mandated by the state, reimbursement to
18local agencies and school districts for those costs shall be made
19pursuant to Part 7 (commencing with Section 17500) of Division
204 of Title 2 of the Government Code.

end delete


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