BILL NUMBER: SB 38 AMENDED
BILL TEXT
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
INTRODUCED BY Senator De León Padilla
DECEMBER 5, 2012
An act to add Section 30009 to the Penal Code, relating
to firearms. amend Sections 63010, 63025.1, 63041.5,
63043, 63048.3, 63048.56, 63048.7, 63049.2, 63049.62, 63049.64,
63049.67, and 63071 of, and to repeal Article 4 (commencing with
Section 63042) of Chapter 2 of Division 1 of Title 6.7 of, the
Government Code, to amend Sections 331, 332.1, 341.5, 348, 349.5,
359, 365, 368, 369, 370, 371, 372, 374, 379, 394.5, 395, 399.2, 2827,
9600, and 9607 of, to repeal Sections 330, 350, 355, 356, 361, 363,
367, 367.7, 368.5, 373, 374.5, 375, 376, 390, 390.1, and 397 of, and
to repeal Article 5.5 (commencing with Section 840) of Chapter 4 of
Part 1 of Division 1 of, the Public Utilities Code, and to amend
Section 31071.5 of the Streets and Highways Code, relating to
electricity.
LEGISLATIVE COUNSEL'S DIGEST
SB 38, as amended, De León Padilla .
Firearms: prohibited persons. Electrical
restructuring.
The existing restructuring of the electrical industry within the
Public Utilities Act provides for the establishment of an Independent
System Operator and a Power Exchange as nonprofit public benefit
corporations. Existing law requires the Independent System Operator,
within 6 months after receiving approval for its operation by the
Federal Energy Regulatory Commission, to provide a report to the
Legislature and the Electricity Oversight Board containing specified
matter.
This bill would repeal this reporting requirement, and would
abolish the Power Exchange.
Electrical restructuring makes legislative findings and
declarations in order to provide guidance to the Public Utilities
Commission in carrying out restructuring.
This bill repeals those legislative findings and declarations.
Electrical restructuring states the intent of the Legislature that
individual customers not experience rate increases as a result of
the allocation of transition costs, as specified, and requires the
Public Utilities Commission to implement a methodology for
calculating certain Power Exchange energy credits.
This bill would repeal this provision.
Electrical restructuring required the commission to identify and
determine those costs and categories of costs for generation-related
assets and obligations that were being collected in
commission-approved rates on December 20, 1995, that might become
uneconomic as a result of a competitive generation market. Electrical
restructuring requires each electrical corporation to propose a cost
recovery plan to the commission for the recovery of the uneconomic
costs of an electrical corporation's generation-related assets and
obligations, requires that the plan contain specified matter, and
requires that the plan set rates for each customer class, rate
schedule, contract, or tariff option, at levels equal to the level as
shown on electric rate schedules as of June 10, 1996, provided that
rates for residential and small commercial customers be reduced so
that these customers receive rate reductions of no less than 10% for
1998 continuing through 2002. Electrical restructuring prohibits the
commission, upon the termination of the 10% rate reduction for
residential and small commercial customers, from subjecting those
residential and small commercial customers to any rate increase or
future rate obligations solely as a result of the termination of the
10% rate reduction. Electrical restructuring authorizes an electrical
corporation to apply to the commission for a determination that
certain transition costs, as defined, may be recovered through fixed
transition amounts, which constitute transition property, as defined,
and provides, until December 31, 2015, for the issuance of financing
orders by the commission, and provides for the issuance of rate
reduction bonds utilizing the California Infrastructure and Economic
Development Bank, to be repaid out of rates.
This bill would repeal these provisions.
Electrical restructuring requires the commission to establish an
effective mechanism that ensures recovery of specified transition
costs from all existing and future consumers in the service territory
in which the utility provided electricity services as of December
20, 1995, except that the costs shall not be recoverable for new
customer load or incremental load of an existing customer where the
load is being met through a direct transaction and the transaction
does not otherwise require the use of transmission or distribution
facilities owned by the utility.
This bill would provide that competition transition charges that
are authorized by the commission prior to January 1, 2015, continue
to apply to all existing and future consumers in the service
territory in which the utility provided electricity services as of
December 20, 1995, subject to the exception described above.
Electrical restructuring directed the commission to authorize
direct transactions between electricity suppliers and end-use
customers, subject to implementation of nonbypassable charges, as
specified. Other provisions reference these charges as a
nonbypassable charge, while other provisions reference these charges
as an obligation to pay uneconomic costs, as specified.
This bill would replace the various references to the specified
statutory charges with "competition transition charges."
Electrical restructuring requires any electrical corporation
serving agricultural customers with multiple meters to conduct
research based on a statistically valid sample of those customers and
meters to determine the typical simultaneous peak load of those
customers and to report the results to those customers and the
commission by July 1, 2001. Electrical restructuring requires the
commission to consider the research results in setting future
electrical distribution rates for those customers.
This bill would repeal this provision.
Electrical restructuring requires the commission to allow recovery
of reasonable employee related transition costs incurred and
projected for severance, retraining, early retirement, outplacement,
and related expenses for the employees in order to mitigate potential
negative impacts on utility personnel directly affected by
restructuring.
This bill would repeal this provision.
Existing law requires, for an electric generating facility sold by
an electrical corporation in a transaction initiated prior to
December 31, 2001, and approved by the commission by December 31,
2002, that the selling utility contract with the purchaser for the
selling utility, an affiliate, or a successor corporation to operate
and maintain the facility for at least 2 years, and authorizes the
commission to require these conditions for transactions initiated on
or after January 1, 2002.
This bill would repeal this provision.
Existing law, enacted as part of restructuring, prescribes how
energy prices paid to nonutility electrical generators, known as
qualifying facilities under federal law, by an electrical corporation
based on the commission's "short run avoided cost energy methodology"
are to be determined, subject to applicable contractual terms.
Existing law authorizes a nonutility electrical generator using
renewable fuels that entered into a contract with an electrical
corporation prior to December 31, 2001, specifying fixed energy
prices for 5 years of electrical output to negotiate a contract of an
additional 5 years of fixed energy payments upon expiration of the
initial 5-year term, at a price to be determined by the commission.
This bill would repeal this provision.
This bill would repeal a provision authorizing an electrical
corporation that was also a gas corporation that served fewer than
4,000,000 customers as of December 20, 1995, to file a rate cap
mechanism that includes a Fuel Price Index Mechanism, as specified,
which authorization became inoperative on December 31, 2001.
This bill would strike references to these repealed statutes.
Existing law requires the Attorney General to establish and
maintain an online database, known as the Prohibited Armed Persons
File, to cross-reference persons who have ownership or possession of
a firearm and who, subsequent to the date of that ownership or
possession, became a person who is prohibited from owning or
possessing a firearm.
This bill would, no later than January 1, 2015, require the
Department of Justice to establish a 30-day amnesty period during
which a person prohibited from possessing a firearm may surrender his
or her firearms to a local law enforcement agency without being
charged with illegal possession of a firearm, except as specified.
The bill would require the department to provide written notification
of the amnesty period to prohibited persons who are eligible to
participate in the amnesty period, and would require the notification
to include certain information. The bill would require a local law
enforcement agency that receives a firearm from a prohibited person
during the amnesty period to report specified information to the
department and to sell or destroy surrendered firearms, as provided.
The bill would require the department to use the specified
information provided by the local law enforcement agency to create a
record of each surrendered firearm in the Prohibited Armed Persons
File. The bill would also impose a civil fine of up to $2,500 per
firearm on a person prohibited from possessing a firearm and who is
eligible for the amnesty program who still maintains possession of
his or her firearm after the amnesty period. The bill would specify
that a prohibited person shall not be charged with illegal possession
of a firearm, nor be subject to the fine, if he or she provides
evidence satisfactory to the department that he or she lawfully
surrendered his or her firearm prior to the commencement of the
amnesty period. Because this bill would impose additional duties on
local law enforcement agencies, this bill would create a
state-mandated local program.
The California Constitution requires the state to reimburse local
agencies and school districts for certain costs mandated by the
state. Statutory provisions establish procedures for making that
reimbursement.
This bill would provide that, if the Commission on State Mandates
determines that the bill contains costs mandated by the state,
reimbursement for those costs shall be made pursuant to these
statutory provisions.
Vote: majority. Appropriation: no. Fiscal committee: yes.
State-mandated local program: yes no .
THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:
SECTION 1. Section 63010 of the
Government Code is amended to read:
63010. For purposes of this division, the following words and
terms shall have the following meanings unless the context clearly
indicates or requires another or different meaning or intent:
(a) "Act" means the Bergeson-Peace Infrastructure and Economic
Development Bank Act.
(b) "Bank" means the California Infrastructure and Economic
Development Bank.
(c) "Board" or "bank board" means the Board of Directors of the
California Infrastructure and Economic Development Bank.
(d) "Bond purchase agreement" means a contractual agreement
executed between the bank and a sponsor, or a special purpose trust
authorized by the bank or a sponsor, or both, whereby the bank or
special purpose trust authorized by the bank agrees to purchase bonds
of the sponsor for retention or sale.
(e) "Bonds" means bonds, including structured, senior, and
subordinated bonds or other securities; loans; notes, including bond,
revenue, tax , or grant anticipation notes; commercial
paper; floating rate and variable maturity securities; and any other
evidences of indebtedness or ownership,
indebtedness including certificates of participation
or beneficial interest, asset backed certificates, or
lease-purchase or installment purchase agreements,
whether taxable or excludable from gross income for federal income
taxation purposes.
(f) "Cost," as applied to a project or portion thereof financed
under this division, means all or any part of the cost of
construction, renovation, and acquisition of all lands, structures,
real or personal property, rights, rights-of-way, franchises,
licenses, easements, and interests acquired or used for a project;
the cost of demolishing or removing any buildings or structures on
land so acquired, including the cost of acquiring any lands to which
the buildings or structures may be moved; the cost of all machinery,
equipment, and financing charges; interest prior to, during, and for
a period after completion of construction, renovation, or
acquisition, as determined by the bank; provisions for working
capital; reserves for principal and interest and for extensions,
enlargements, additions, replacements, renovations, and improvements;
and the cost of architectural, engineering, financial and legal
services, plans, specifications, estimates, administrative expenses,
and other expenses necessary or incidental to determining the
feasibility of any project or incidental to the construction,
acquisition, or financing of any project, and transition
costs in the case of an electrical corporation.
project.
(g) "Economic development facilities" means real and personal
property, structures, buildings, equipment, and supporting components
thereof that are used to provide industrial, recreational, research,
commercial, utility, or service enterprise facilities, community,
educational, cultural, or social welfare facilities and any parts or
combinations thereof, and all facilities or infrastructure necessary
or desirable in connection therewith, including provision for working
capital, but shall not include any housing.
(h) "Electrical corporation" has the meaning set forth in Section
218 of the Public Utilities Code.
(i) "Executive director" means the Executive Director of the
California Infrastructure and Economic Development Bank appointed
pursuant to Section 63021.
(j) "Financial assistance" in connection with a project, includes,
but is not limited to, any combination of grants, loans, the
proceeds of bonds issued by the bank or special purpose trust,
insurance, guarantees or other credit enhancements or liquidity
facilities, and contributions of money, property, labor, or other
things of value, as may be approved by resolution of the board or the
sponsor, or both; the purchase or retention of bank bonds, the bonds
of a sponsor for their retention or for sale by the bank, or the
issuance of bank bonds or the bonds of a special purpose trust used
to fund the cost of a project for which a sponsor is directly or
indirectly liable, including, but not limited to, bonds, the security
for which is provided in whole or in part pursuant to the powers
granted by Section 63025; bonds for which the bank has provided a
guarantee or enhancement, including, but not limited to, the purchase
of the subordinated bonds of the sponsor, the subordinated bonds of
a special purpose trust, or the retention of the subordinated bonds
of the bank pursuant to Chapter 4 (commencing with Section 63060); or
any other type of assistance deemed appropriate by the bank or the
sponsor, except that no direct loans shall be made to nonpublic
entities other than in connection with the issuance of rate
reduction bonds pursuant to a financing order or in
connection with a financing for an economic
development facility.
For purposes of this subdivision, "grant" does not include grants
made by the bank except when acting as an agent or intermediary for
the distribution or packaging of financing available from federal,
private, or other public sources.
(k) "Financing order" has the meaning set forth in Section 840 of
the Public Utilities Code.
( l )
(k) "Guarantee trust fund" means the California
Infrastructure Guarantee Trust Fund.
(m)
(l) "Infrastructure bank fund" means the California
Infrastructure and Economic Development Bank Fund.
(n)
(m) "Loan agreement" means a contractual agreement
executed between the bank or a special purpose trust and a sponsor
that provides that the bank or special purpose trust will loan funds
to the sponsor and that the sponsor will repay the principal and pay
the interest and redemption premium, if any, on the loan.
(o)
(n) "Participating party" means any person, company,
corporation, association, state or municipal governmental entity,
partnership, firm, or other entity or group of entities, whether
organized for profit or not for profit, engaged in business or
operations within the state and that applies for financing from the
bank in conjunction with a sponsor for the purpose of implementing a
project. However, in the case of a project relating to the
financing of transition costs or the acquisition of transition
property, or both, on the request of an electrical corporation, or in
connection with a financing for an economic development facility, or
for the financing of insurance claims, the participating party shall
be deemed to be the same entity as the sponsor for the financing.
(p)
(o) "Project" means designing, acquiring, planning,
permitting, entitling, constructing, improving, extending, restoring,
financing, and generally developing public development facilities or
economic development facilities within the state or
financing transition costs or the acquisition of transition property,
or both, upon approval of a financing order by the Public Utilities
Commission, as provided in Article 5.5 (commencing with Section 840)
of Chapter 4 of Part 1 of Division 1 of the Public Utilities Code.
state.
(q)
(p) "Public development facilities" means real and
personal property, structures, conveyances, equipment, thoroughfares,
buildings, and supporting components thereof, excluding any housing,
that are directly related to providing the following:
(1) "City streets" including any street, avenue, boulevard, road,
parkway, drive, or other way that is any of the following:
(A) An existing municipal roadway.
(B) Is shown upon a plat approved pursuant to law and includes the
land between the street lines, whether improved or unimproved, and
may comprise pavement, bridges, shoulders, gutters, curbs,
guardrails, sidewalks, parking areas, benches, fountains, plantings,
lighting systems, and other areas within the street lines, as well as
equipment and facilities used in the cleaning, grading, clearance,
maintenance, and upkeep thereof.
(2) "County highways" including any county highway as defined in
Section 25 of the Streets and Highways Code, that includes the land
between the highway lines, whether improved or unimproved, and may
comprise pavement, bridges, shoulders, gutters, curbs, guardrails,
sidewalks, parking areas, benches, fountains, plantings, lighting
systems, and other areas within the street lines, as well as
equipment and facilities used in the cleaning, grading, clearance,
maintenance, and upkeep thereof.
(3) "Drainage, water supply, and flood control" including, but not
limited to, ditches, canals, levees, pumps, dams, conduits, pipes,
storm sewers, and dikes necessary to keep or direct water away from
people, equipment, buildings, and other protected areas as may be
established by lawful authority, as well as the acquisition,
improvement, maintenance, and management of floodplain areas and all
equipment used in the maintenance and operation of the foregoing.
(4) "Educational facilities" including libraries, child care
facilities, including, but not limited to, day care facilities, and
employment training facilities.
(5) "Environmental mitigation measures" including required
construction or modification of public infrastructure and purchase
and installation of pollution control and noise abatement equipment.
(6) "Parks and recreational facilities" including local parks,
recreational property and equipment, parkways and property.
(7) "Port facilities" including docks, harbors, ports of entry,
piers, ships, small boat harbors and marinas, and any other
facilities, additions, or improvements in connection therewith.
(8) "Power and communications" including facilities for the
transmission or distribution of electrical energy, natural gas, and
telephone and telecommunications service.
(9) "Public transit" including air and rail transport of goods,
airports, guideways, vehicles, rights-of-way, passenger stations,
maintenance and storage yards, and related structures, including
public parking facilities, equipment used to provide or enhance
transportation by bus, rail, ferry, or other conveyance, either
publicly or privately owned, that provides to the public general or
special service on a regular and continuing basis.
(10) "Sewage collection and treatment" including pipes, pumps, and
conduits that collect wastewater from residential, manufacturing,
and commercial establishments, the equipment, structures, and
facilities used in treating wastewater to reduce or eliminate
impurities or contaminants, and the facilities used in disposing of,
or transporting, remaining sludge, as well as all equipment used in
the maintenance and operation of the foregoing.
(11) "Solid waste collection and disposal" including vehicles,
vehicle-compatible waste receptacles, transfer stations, recycling
centers, sanitary landfills, and waste conversion facilities
necessary to remove solid waste, except that which is hazardous as
defined by law, from its point of origin.
(12) "Water treatment and distribution" including facilities in
which water is purified and otherwise treated to meet residential,
manufacturing, or commercial purposes and the conduits, pipes, and
pumps that transport it to places of use.
(13) "Defense conversion" including, but not limited to,
facilities necessary for successfully converting military bases
consistent with an adopted base reuse plan.
(14) "Public safety facilities" including, but not limited to,
police stations, fire stations, court buildings, jails, juvenile
halls, and juvenile detention facilities.
(15) "State highways" including any state highway as described in
Chapter 2 (commencing with Section 230) of Division 1 of the Streets
and Highways Code, and the related components necessary for safe
operation of the highway.
(16) (A) Military infrastructure, including, but not limited to,
facilities on or near a military installation, that enhance the
military operations and mission of one or more military installations
in this state. To be eligible for funding, the project shall be
endorsed by the Office of Military and Aerospace Support established
pursuant to Section 13998.2.
(B) For purposes of this subdivision, "military installation"
means any facility under the jurisdiction of the United States
Department of Defense, as defined in paragraph (1) of
subsection (e) of Section 2687 of Title 10 of the United States Code.
(r) "Rate reduction bonds" has the meaning set forth in Section
840 of the Public Utilities Code.
(s)
(q) "Revenues" means all receipts, purchase payments,
loan repayments, lease payments, and all other income or receipts
derived by the bank or a sponsor from the sale, lease, or other
financing arrangement undertaken by the bank, a sponsor or a
participating party, including, but not limited to, all receipts from
a bond purchase agreement, and any income or revenue derived from
the investment of any money in any fund or account of the bank or a
sponsor and any receipts derived from transition property.
sponsor. Revenues shall not include moneys in
the General Fund of the state.
(t)
(r) "Special purpose trust" means a trust, partnership,
limited partnership, association, corporation, nonprofit
corporation, or other entity authorized under the laws of the state
to serve as an instrumentality of the state to accomplish public
purposes and authorized by the bank to acquire, by purchase or
otherwise, for retention or sale, the bonds of a sponsor or of the
bank made or entered into pursuant to this division and to issue
special purpose trust bonds or other obligations secured by these
bonds or other sources of public or private revenues.
Special purpose trust also means any entity authorized by the bank to
acquire transition property or to issue rate reduction bonds, or
both, subject to the approvals by the bank and powers of the bank as
are provided by the bank in its resolution authorizing the entity to
issue rate reduction bonds.
(u)
(s) "Sponsor" means any subdivision of the state or
local government including departments, agencies, commissions,
cities, counties, nonprofit corporations formed on behalf of a
sponsor, special districts, assessment districts, and joint powers
authorities within the state or any combination of these subdivisions
that makes an application to the bank for financial assistance in
connection with a project in a manner prescribed by the bank. This
definition shall not be construed to require that an applicant have
an ownership interest in the project. In addition, an
electrical corporation shall be deemed to be the sponsor as well as
the participating party for any project relating to the financing of
transition costs and the acquisition of transition property on the
request of the electrical corporation and any person,
company, corporation, partnership, firm, or other entity or group
engaged in business or operation within the state that applies for
financing of any economic development facility, shall be deemed to be
the sponsor as well as the participating party for the project
relating to the financing of that economic development facility.
(v)
(t) "State" means the State of California.
(w) "Transition costs" has the meaning set forth in Section 840 of
the Public Utilities Code.
(x) "Transition property" has the meaning set forth in Section 840
of the Public Utilities Code.
SEC. 2. Section 63025.1 of the
Government Code is amended to read:
63025.1. The bank board may do or delegate the following to the
executive director:
(a) Sue and be sued in its own name.
(b) As provided in Chapter 5 (commencing with Section 63070),
issue bonds and authorize special purpose trusts to issue bonds,
including, at the option of the board, bonds bearing interest that is
taxable for the purpose of federal income taxation, or borrow money
to pay all or any part of the cost of any project, or to otherwise
carry out the purposes of this division.
(c) Engage the services of private consultants to render
professional and technical assistance and advice in carrying out the
purposes of this division.
(d) Employ attorneys, financial consultants, and other advisers as
may, in the bank's judgment, be necessary in connection with the
issuance and sale, or authorization of special purpose trusts for the
issuance and sale, of any bonds, notwithstanding Sections 11042 and
11043.
(e) Contract for engineering, architectural, accounting, or other
services of appropriate state agencies as may, in its judgment, be
necessary for the successful development of a project.
(f) Pay the reasonable costs of consulting engineers, architects,
accountants, and construction, land use, recreation, and
environmental experts employed by any sponsor or participating party
if, in the bank's judgment, those services are necessary for the
successful development of a project.
(g) Acquire, take title to, and sell by installment sale or
otherwise, lands, structures, real or personal property, rights,
rights-of-way, franchises, easements, and other interests in lands
that are located within the state, or transition property
as the bank may deem necessary or convenient for the
financing of the project, upon terms and conditions that it considers
to be reasonable.
(h) Receive and accept from any source including, but not limited
to, the federal government, the state, or any agency thereof, loans,
contributions, or grants, in money, property, labor, or other things
of value, for, or in aid of, a project, or any portion thereof.
(i) Make loans to any sponsor or participating party, either
directly or by making a loan to a lending institution, in connection
with the financing of a project in accordance with an agreement
between the bank and the sponsor or a participating party, either as
a sole lender or in participation with other lenders. However, no
loan shall exceed the total cost of the project as determined by the
sponsor or the participating party and approved by the bank.
(j) Make loans to any sponsor or participating party, either
directly or by making a loan to a lending institution, in accordance
with an agreement between the bank and the sponsor or participating
party to refinance indebtedness incurred by the sponsor or
participating party in connection with projects undertaken and
completed prior to any agreement with the bank or expectation that
the bank would provide financing, either as a sole lender or in
participation with other lenders.
(k) Mortgage all or any portion of the bank's interest in a
project and the property on which any project is located, whether
owned or thereafter acquired, including the granting of a security
interest in any property, tangible or intangible.
( l ) Assign or pledge all or any portion of the bank's
interests in transition property and the revenues
therefrom, or assets, things of value, mortgages, deeds of
trust, bonds, bond purchase agreements, loan agreements, indentures
of mortgage or trust, or similar instruments, notes, and security
interests in property, tangible or intangible and the revenues
therefrom, of a sponsor or a participating party to which the bank
has made loans, and the revenues therefrom, including payment or
income from any interest owned or held by the bank, for the benefit
of the holders of bonds.
(m) Make, receive, or serve as a conduit for the making of, or
otherwise provide for, grants, contributions, guarantees, insurance,
credit enhancements or liquidity facilities, or other financial
enhancements to a sponsor or a participating party as financial
assistance for a project.
(n) Lease the project being financed to a sponsor or a
participating party, upon terms and conditions that the bank deems
proper but shall not be leased at a loss; charge and collect rents
therefor; terminate any lease upon the failure of the lessee to
comply with any of the obligations thereof; include in any lease, if
desired, provisions that the lessee shall have options to renew the
lease for a period or periods, and at rents determined by the bank;
purchase any or all of the project; or, upon payment of all the
indebtedness incurred by the bank for the financing of the project,
the bank may convey any or all of the project to the lessee or
lessees.
(o) Charge and equitably apportion among sponsors and
participating parties the bank's administrative costs and expenses
incurred in the exercise of the powers and duties conferred by this
division.
(p) Issue, obtain, or aid in obtaining, from any department or
agency of the United States, from other agencies of the state, or
from any private company, any insurance or guarantee to, or for, the
payment or repayment of interest or principal, or both, or any part
thereof, on any loan, lease, or obligation or any instrument
evidencing or securing the same, made or entered into pursuant to
this division.
(q) Notwithstanding any other provision of this division, enter
into any agreement, contract, or any other instrument with respect to
any insurance or guarantee; accept payment in the manner and form as
provided therein in the event of default by a sponsor or a
participating party; and issue or assign any insurance or guarantee
as security for the bank's bonds.
(r) Enter into any agreement or contract, execute any instrument,
and perform any act or thing necessary or convenient to, directly or
indirectly, secure the bank's bonds, the bonds issued by a special
purpose trust, or a sponsor's obligations to the bank or to a special
purpose trust, including, but not limited to, bonds of a sponsor
purchased by the bank or a special purpose trust for retention or
sale, with funds or moneys that are legally available and that are
due or payable to the sponsor by reason of any grant, allocation,
apportionment or appropriation of the state or agencies thereof, to
the extent that the Controller shall be the custodian at any time of
these funds or moneys, or with funds or moneys that are or will be
legally available to the sponsor, the bank, or the state or any
agencies thereof by reason of any grant, allocation, apportionment,
or appropriation of the federal government or agencies thereof; and
in the event of written notice that the sponsor has not paid or is in
default on its obligations to the bank or a special purpose trust,
direct the Controller to withhold payment of those funds or moneys
from the sponsor over which it is or will be custodian and to pay the
same to the bank or special purpose trust or their assignee, or
direct the state or any agencies thereof to which any grant,
allocation, apportionment , or appropriation of the
federal government or agencies thereof is or will be legally
available to pay the same upon receipt by the bank or special purpose
trust or their assignee, until the default has been cured and the
amounts then due and unpaid have been paid to the bank or special
purpose trust or their assignee, or until arrangements satisfactory
to the bank or special purpose trust have been made to cure the
default.
(s) Enter into any agreement or contract, execute any instrument,
and perform any act or thing necessary, convenient, or appropriate to
carry out any power expressly given to the bank by this division,
including, but not limited to, agreements for the sale of all or any
part, including principal, interest, redemption rights ,
or any other rights or obligations, of bonds of the bank or of a
special purpose trust, liquidity agreements, contracts commonly known
as interest rate swap agreements, forward payment conversion
agreements, futures or contracts providing for payments based on
levels of, or changes in, interest rates or currency exchange rates,
or contracts to exchange cash-flows or a series of payments, or
contracts, including options, puts or calls to hedge payments, rate,
spread, currency exchange, or similar exposure, or any other
financial instrument commonly known as a structured financial
product.
(t) Purchase, with the proceeds of the bank's bonds, transition
property or bonds issued by, or for the benefit of, any sponsor in
connection with a project, pursuant to a bond purchase agreement or
otherwise. Bonds or transition property purchased pursuant to this
division may be held by the bank, pledged or assigned by the bank, or
sold to public or private purchasers at public or negotiated sale,
in whole or in part, separately or together with other bonds issued
by the bank, and notwithstanding any other provision of law, may be
bought by the bank at private sale.
(u) Enter into purchase and sale agreements with all entities,
public and private, including state and local government pension
funds, with respect to the sale or purchase of bonds or
transition property. bonds.
(v) Invest any moneys held in reserve or sinking funds, or any
moneys not required for immediate use or disbursement, in obligations
that are authorized by law for the investment of trust funds in the
custody of the Treasurer.
(w) Authorize a special purpose trust or trusts to purchase or
retain, with the proceeds of the bonds of a special purpose trust,
transition property or bonds issued by, or for the benefit of, any
sponsor in connection with a project or issued by the bank or a
special purpose trust, pursuant to a bond purchase agreement or
otherwise. Bonds or transition property purchased pursuant to this
title may be held by a special purpose entity, pledged or assigned by
a special purpose entity, or sold to public or private purchasers at
public or negotiated sale, in whole or in part, with or without
structuring, subordination , or credit enhancement,
separately or together with other bonds issued by a special purpose
trust, and notwithstanding any other provision of law, may be bought
by the bank or by a special purpose trust at private sale.
(x) Approve the issuance of any bonds, notes, or other evidences
of indebtedness by the Rural Economic Development Infrastructure
Panel, established pursuant to Section 15373.7.
(y) Approve the issuance of rate reduction bonds by an entity
other than the bank or a special purpose trust to acquire transition
property upon approval of the transaction in a financing order by the
Public Utilities Commission, as provided in Article 5.5 (commencing
with Section 840) of Chapter 4 of Part 1 of Division 1 of the Public
Utilities Code.
(z)
(y) Apply for and accept subventions, grants, loans,
advances, and contributions from any source of money, property,
labor, or other things of value. The sources may include bond
proceeds, dedicated taxes, state appropriations, federal
appropriations, federal grant and loan funds, public and private
sector retirement system funds, and proceeds of loans from the Pooled
Money Investment Account.
(aa)
(z) Do all things necessary and convenient to carry out
its purposes and exercise its powers, provided, however, that
nothing herein shall be construed to authorize the bank to engage
directly in the business of a manufacturing, industrial, real estate
development, or nongovernmental service enterprise. Further, the bank
shall not be organized to accept deposits of money for time or
demand deposits or to constitute a bank or trust company.
SEC. 3. Section 63041.5 of the
Government Code is amended to read:
63041.5. (a) It is the intent of the Legislature to provide a
one-time appropriation for financial assistance to local government
to meet capital outlay and infrastructure needs.
(b) From the funds appropriated in Item 2920-111-0001 of the
Budget Act of 1999, the sum of four hundred twenty-five million
dollars ($425,000,000) shall be available for financial assistance,
including, but not limited to, leveraged revolving fund loans, to
local government sponsors for public development facilities, as
specified in subdivision (q) (p) of
Section 63010 of the Government Code.
(c) From the funds appropriated in Item 2920-111-0001 of the
Budget Act of 1999 and in Item 2920-111-0001 of the Budget Act of
1998 (Chapter 324 of the Statutes of (Ch.
324, Stats. 1998), the California Infrastructure and Economic
Development Bank shall make no single loan in excess of 10 percent of
the combined amount of these appropriations to the bank unless
approved by unanimous consent of the membership of the Board of
Directors of the California Infrastructure and Economic Development
Bank and the Director of Finance provides a 30-day written notice to
the Chairperson and Vice-Chairperson of the Joint Legislative Budget
Committee.
SEC. 4. Article 4 (commencing with Section 63042)
of Chapter 2 of Division 1 of Title 6.7 of the Government
Code is repealed.
SEC. 5. Section 63043 of the Government
Code is amended to read:
63043. Notwithstanding any other provision of this division,
Article 3 (commencing with Section 63040) and Article 4
(commencing with Section 63042), shall not apply to any
conduit financing for economic development facilities by the bank
directly for the benefit of a participating party.
SEC. 6. Section 63048.3 of the
Government Code is amended to read:
63048.3. Notwithstanding any other provision of this division,
Article 3 (commencing with Section 63040), Article 4
(commencing with Article 63042), 63040) and
Article 5 (commencing with Section 63043) do not apply to any
financing provided by the bank to, or at the request of, the board in
connection with the revolving fund.
SEC. 7. Section 63048.56 of the
Government Code is amended to read:
63048.56. Notwithstanding any other law, Article 3 (commencing
with Section 63040), Article 4 (commencing with Section
63042), 63040) and Article 5 (commencing with
Section 63043) shall not apply to any financing provided by the bank
to, or at the request of, the department in connection with the
revolving fund.
SEC. 8. Section 63048.7 of the
Government Code is amended to read:
63048.7. Notwithstanding any other provision of this division,
Article 3 (commencing with Section 63040), Article 4
(commencing with Section 63042), 63040) and
Article 5 (commencing with Section 63043) do not apply to any bonds
issued by the special purpose trust established by this article. All
matters authorized in this article are in addition to powers granted
to the bank in this division.
SEC. 9. Section 63049.2 of the
Government Code is amended to read:
63049.2. Notwithstanding any other provision of this division,
Article 3 (commencing with Section 63040), Article 4
(commencing with Section 63042), 63040) and
Article 5 (commencing with Section 63043) do not apply to any bonds
issued by the special purpose trust established by this article. All
matters authorized in this article are in addition to powers granted
to the bank in this division.
SEC. 10. Section 63049.62 of the
Government Code is amended to read:
63049.62. Notwithstanding any other provision of this division, a
financing of the costs of claims of insolvent insurers upon the
request of the association pursuant to Section 1063.73 of the
Insurance Code shall be deemed to be in the public interest and
eligible for financing by the bank, and Article 3 (commencing with
Section 63040), Article 4 (commencing with Section 63042),
Article 5 (commencing with Section 63043), Article 6
(commencing with Section 63048), and Article 7 (commencing with
Section 63049) shall not apply to the financing provided by the bank
to, or at the request of, the association or the department in
connection with the fund. Notwithstanding any other provision of this
division, the bank shall have no authority over any matter that is
subject to the approval of the Insurance Commissioner under Article
14.2 (commencing with Section 1063) of Chapter 1 of Part 2 of
Division 1 of the Insurance Code.
SEC. 11. Section 63049.64 of the
Government Code is amended to read:
63049.64. (a) The bank may issue bonds pursuant to Chapter 5
(commencing with Section 63070) and may loan the proceeds thereof to
the association, and deposit the proceeds into a separate account in
the fund, or use the proceeds to refund bonds previously issued under
this article. Bond proceeds may also be used to fund necessary
reserves, capitalized interest, credit enhancement costs, or costs of
issuance.
(b) Bonds issued under this article shall not be deemed to
constitute a debt or liability of the state or of any political
subdivision thereof, other than the bank, or a pledge of the faith
and credit of the state or of any political subdivision, but shall be
payable solely from the fund and other revenues and assets securing
the bonds. All bonds issued under this article shall contain on the
face of the bonds a statement to that effect.
(c) For purposes of this article, the term "project," as defined
in subdivision (p) (o) of Section
63010, shall include financing of the costs of claims of insolvent
workers' compensation insurers, in an amount (together with
associated costs of financing) that may be determined by the
association in making a request for financing to the bank.
SEC. 12. Section 63049.67 of the
Government Code is amended to read:
63049.67. (a) Notwithstanding any other provision of this
division, a financing of emergency apportionments upon the request of
a school district pursuant to Article 2.7 (commencing with Section
41329.50) of Chapter 3 of Part 24 of Division 3 of Title 2 of the
Education Code, is deemed to be in the public interest and eligible
for financing by the bank. Article 3 (commencing with Section
63040), Article 4 (commencing with Section 63042),
63040) and Article 5 (commencing with Section 63043) do
not apply to the financing provided by the bank in connection with an
emergency apportionment.
(b) The bank may issue bonds pursuant to Chapter 5 (commencing
with Section 63070) and provide the proceeds to a school district
pursuant to a lease agreement. The proceeds may be used as an
emergency apportionment, to reimburse the interim emergency
apportionment from the General Fund authorized pursuant to
subdivision (b) of Section 41329.52 of the Education Code, or to
refund bonds previously issued under this section. Bond proceeds may
also be used to fund necessary reserves, capitalized interest, credit
enhancement costs, and costs of issuance.
(c) Bonds issued under this article are not deemed to constitute a
debt or liability of the state or of any political subdivision of
the state, other than a limited obligation of the bank, or a pledge
of the faith and credit of the state or of any political subdivision.
All bonds issued under this article shall contain on the face of the
bonds a statement to the same effect.
(d) Any fund or account established in connection with the bonds
shall be established outside of the centralized treasury system.
Notwithstanding any other law, the bank shall select the financing
team and the trustee for the bonds, and the trustee shall be a
corporation or banking association authorized to exercise corporate
trust powers.
(e) Pursuant to Section 41329.55 of the Education Code, a school
district other than the Compton Community College District shall
instruct the Controller to repay the lease from moneys in the State
School Fund and the Education Protection Account designated for
apportionment to the school district. Pursuant to Section 41329.55 of
the Education Code, if the school district is the Compton Community
College District, the Controller shall be instructed to repay the
lease from moneys in Section B of the State School Fund. Any amounts
necessary to make this repayment shall be drawn from the total
statewide funding available for community college apportionment
consisting of funds in Section B of the State School Fund. Thereafter
the Controller shall transfer to Section B of the State School Fund,
either in a single or multiple transfers, an amount equal to the
total repayment, which amount shall be transferred from the amount
designated for apportionment to the Compton Community College
District from the State School Fund. If these transfers from the
district prove inadequate to repay any repayments for any reason, the
Compton Community College District is required to use any revenue
sources available to it for transfer and repayment purposes.
(f) Notwithstanding any other law, as long as any bonds issued
pursuant to this section are outstanding, the following requirements
apply:
(1) The school district for which the bonds were issued is not
eligible to be a debtor in a case under Chapter 9 of the United
States Bankruptcy Code, as it may be amended from time to time, and
no governmental officer or organization is or may be empowered to
authorize the school district to be a debtor under that chapter.
(2) It is the intent of the Legislature that the Legislature
should not in the future abolish the Compton Community College
District or take any action that would prevent the Compton Community
College District from entering into or performing binding
agreements or invalidate any prior binding agreements of the Compton
Community College District, where invalidation may have a material
adverse effect on the bonds issued pursuant to this section.
(3) The Compton Community College District shall not be
reorganized or merged with another community college district unless
all of the following apply:
(A) The successor district becomes by operation of law the owner
of all property previously owned by the Compton Community College
District.
(B) Any agreement entered into by the Compton Community College
District in connection with bonds issued pursuant to this section are
assumed by the successor district.
(C) The apportionment authorized by subdivision (e) remains in
effect.
(D) Receipt by the bank of an opinion of bond counsel that the
bonds issued for the Compton Community College District will remain
tax exempt following the reorganization or merger.
(g) Nothing in this section limits the authority of the
Legislature to abolish the Compton Community College District when
bonds issued for that district are no longer outstanding. Further,
the Legislature may provide for the redemption or defeasance of the
bonds at any time so that no bonds are outstanding. If the
Legislature provides for the redemption or defeasance of the bonds
issued for the Compton Community College District in order to abolish
that district, it is the intent of the Legislature that the funds
required for the redemption or defeasance should be appropriated from
Section B of the State School Fund.
(h) The bank may enter into contracts or agreements with banks,
insurers, or other financial institutions or parties that it
determines are necessary or desirable to improve the security and
marketability of, or to manage interest rates or other risks
associated with, the bonds issued pursuant to this section. The bank
may pledge apportionments made by the Controller directly to the bond
trustee pursuant to Section 41329.55 of the Education Code as
security for repayment of any obligation owed to a bank, insurer, or
other financial institution pursuant to this subdivision.
SEC. 13. Section 63071 of the
Government Code is amended to read:
63071. (a) Notwithstanding any other provision of law, but
consistent with Sections 1 and 18 of Article XVI of the California
Constitution, a sponsor may issue bonds for purchase by the bank
pursuant to a bond purchase agreement. The bank may issue bonds or
authorize a special purpose trust to issue bonds. These bonds may be
issued pursuant to the charter of any city or any city and county
that authorized the issuance of these bonds as a sponsor and may also
be issued by any sponsor pursuant to the Revenue Bond Law of 1941
(Chapter 6 (commencing with Section 54300) of Division 2 of Title 5)
to pay the costs and expenses pursuant to this title, subject to the
following conditions:
(1) With the prior approval of the bank, the sponsor may sell
these bonds in any manner as it may determine, either by private sale
or by means of competitive bid.
(2) Notwithstanding Section 54418, the bonds may be sold at a
discount at any rate as the bank and sponsor shall determine.
(3) Notwithstanding Section 54402, the bonds shall bear interest
at any rate and be payable at any time as the sponsor shall determine
with the consent of the bank.
(b) The total amount of bonds issued to finance public development
facilities that may be outstanding at any one time under this
chapter shall not exceed five billion dollars ($5,000,000,000).
The total amount of rate reduction bonds that may be
outstanding at any one time under this chapter shall not exceed ten
billion dollars ($10,000,000,000).
(c) Bonds for which moneys or securities have been deposited in
trust, in amounts necessary to pay or redeem the principal, interest,
and any redemption premium thereon, shall be deemed not to be
outstanding for purposes of this section.
SEC. 14. Section 330 of the Public
Utilities Code is repealed.
330. In order to provide guidance in carrying out this chapter,
the Legislature finds and declares all of the following:
(a) It is the intent of the Legislature that a cumulative rate
reduction of at least 20 percent be achieved not later than April 1,
2002, for residential and small commercial customers, from the rates
in effect on June 10, 1996. In determining that the April 1, 2002,
rate reduction has been met, the commission shall exclude the costs
of the competitively procured electricity and the costs associated
with the rate reduction bonds, as defined in Section 840.
(b) The people, businesses, and institutions of California spend
nearly twenty-three billion dollars ($23,000,000,000) annually on
electricity, so that reductions in the price of electricity would
significantly benefit the economy of the state and its residents.
(c) The Public Utilities Commission has opened rulemaking and
investigation proceedings with regard to restructuring California's
electric power industry and reforming utility regulation.
(d) The commission has found, after an extensive public review
process, that the interests of ratepayers and the state as a whole
will be best served by moving from the regulatory framework existing
on January 1, 1997, in which retail electricity service is provided
principally by electrical corporations subject to an obligation to
provide ultimate consumers in exclusive service territories with
reliable electric service at regulated rates, to a framework under
which competition would be allowed in the supply of electric power
and customers would be allowed to have the right to choose their
supplier of electric power.
(e) Competition in the electric generation market will encourage
innovation, efficiency, and better service from all market
participants, and will permit the reduction of costly regulatory
oversight.
(f) The delivery of electricity over transmission and distribution
systems is currently regulated, and will continue to be regulated to
ensure system safety, reliability, environmental protection, and
fair access for all market participants.
(g) Reliable electric service is of utmost importance to the
safety, health, and welfare of the state's citizenry and economy. It
is the intent of the Legislature that electric industry restructuring
should enhance the reliability of the interconnected regional
transmission systems, and provide strong coordination and enforceable
protocols for all users of the power grid.
(h) It is important that sufficient supplies of electric
generation will be available to maintain the reliable service to the
citizens and businesses of the state.
(i) Reliable electric service depends on conscientious inspection
and maintenance of transmission and distribution systems. To continue
and enhance the reliability of the delivery of electricity, the
Independent System Operator and the commission, respectively, should
set inspection, maintenance, repair, and replacement standards.
(j) It is the intent of the Legislature that California enter into
a compact with western region states. That compact should require
the publicly and investor-owned utilities located in those states,
that sell energy to California retail customers, to adhere to
enforceable standards and protocols to protect the reliability of the
interconnected regional transmission and distribution systems.
(k) In order to achieve meaningful wholesale and retail
competition in the electric generation market, it is essential to do
all of the following:
(1) Separate monopoly utility transmission functions from
competitive generation functions, through development of independent,
third-party control of transmission access and pricing.
(2) Permit all customers to choose from among competing suppliers
of electric power.
(3) Provide customers and suppliers with open, nondiscriminatory,
and comparable access to transmission and distribution services.
( l ) The commission has properly concluded
that:
(1) This competition will best be introduced by the creation of an
Independent System Operator and an independent Power Exchange.
(2) Generation of electricity should be open to competition.
(3) There is a need to ensure that no participant in these new
market institutions has the ability to exercise significant market
power so that operation of the new market institutions would be
distorted.
(4) These new market institutions should commence simultaneously
with the phase in of customer choice, and the public will be best
served if these institutions and the nonbypassable transition cost
recovery mechanism referred to in subdivisions (s) to (w), inclusive,
are in place simultaneously and no later than January 1, 1998.
(m) It is the intention of the Legislature that California's
publicly owned electric utilities and investor-owned electric
utilities should commit control of their transmission facilities to
the Independent System Operator. These utilities should jointly
advocate to the Federal Energy Regulatory Commission a pricing
methodology for the Independent System Operator that results in an
equitable return on capital investment in transmission facilities for
all Independent System Operator participants.
(n) Opportunities to acquire electric power in the competitive
market must be available to California consumers as soon as
practicable, but no later than January 1, 1998, so that all customers
can share in the benefits of competition.
(o) Under the existing regulatory framework, California's
electrical corporations were granted franchise rights to provide
electricity to consumers in their service territories.
(p) Consistent with federal and state policies, California
electrical corporations invested in power plants and entered into
contractual obligations in order to provide reliable electrical
service on a nondiscriminatory basis to all consumers within their
service territories who requested service.
(q) The cost of these investments and contractual obligations are
currently being recovered in electricity rates charged by electrical
corporations to their consumers.
(r) Transmission and distribution of electric power remain
essential services imbued with the public interest that are provided
over facilities owned and maintained by the state's electrical
corporations.
(s) It is proper to allow electrical corporations an opportunity
to continue to recover, over a reasonable transition period, those
costs and categories of costs for generation-related assets and
obligations, including costs associated with any subsequent
renegotiation or buyout of existing generation-related contracts,
that the commission, prior to December 20, 1995, had authorized for
collection in rates and that may not be recoverable in market prices
in a competitive generation market, and appropriate additions
incurred after December 20, 1995, for capital additions to generating
facilities existing as of December 20, 1995, that the commission
determines are reasonable and should be recovered, provided that the
costs are necessary to maintain those facilities through December 31,
2001. In determining the costs to be recovered, it is appropriate to
net the negative value of above market assets against the positive
value of below market assets.
(t) The transition to a competitive generation market should be
orderly, protect electric system reliability, provide the investors
in these electrical corporations with a fair opportunity to fully
recover the costs associated with commission approved
generation-related assets and obligations, and be completed as
expeditiously as possible.
(u) The transition to expanded customer choice, competitive
markets, and performance based ratemaking as described in Decision
95-12-063, as modified by Decision 96-01-009, of the Public Utilities
Commission, can produce hardships for employees who have dedicated
their working lives to utility employment. It is preferable that any
necessary reductions in the utility workforce directly caused by
electrical restructuring, be accomplished through offers of voluntary
severance, retraining, early retirement, outplacement, and related
benefits. Whether workforce reductions are voluntary or involuntary,
reasonable costs associated with these sorts of benefits should be
included in the competition transition charge.
(v) Charges associated with the transition should be collected
over a specific period of time on a nonbypassable basis and in a
manner that does not result in an increase in rates to customers of
electrical corporations. In order to insulate the policy of
nonbypassability against incursions, if exemptions from the
competition transition charge are granted, a firewall shall be
created that segregates recovery of the cost of exemptions as
follows:
(1) The cost of the competition transition charge exemptions
granted to members of the combined class of residential and small
commercial customers shall be recovered only from those customers.
(2) The cost of the competition transition charge exemptions
granted to members of the combined class of customers other than
residential and small commercial customers shall be recovered only
from those customers. The commission shall retain existing cost
allocation authority provided that the firewall and rate freeze
principles are not violated.
(w) It is the intent of the Legislature to require and enable
electrical corporations to monetize a portion of the competition
transition charge for residential and small commercial consumers so
that these customers will receive rate reductions of no less than 10
percent for 1998 continuing through 2002. Electrical corporations
shall, by June 1, 1997, or earlier, secure the means to finance the
competition transition charge by applying concurrently for financing
orders from the Public Utilities Commission and for rate reduction
bonds from the California Infrastructure and Economic Development
Bank.
(x) California's public utility electrical corporations provide
substantial benefits to all Californians, including employment and
support of the state's economy. Restructuring the electric services
industry pursuant to the act that added this chapter will continue
these benefits, and will also offer meaningful and immediate rate
reductions for residential and small commercial customers, and
facilitate competition in the supply of electric power.
SEC. 15. Section 331 of the Public
Utilities Code is amended to read:
331. The definitions set forth in this section shall govern the
construction of this chapter.
(a) "Aggregator" means any marketer, broker, public agency, city,
county, or special district, that combines the loads of multiple
end-use customers in facilitating the sale and purchase of electric
energy, transmission, and other services on behalf of these
customers.
(b) "Broker" means an entity that arranges the sale and purchase
of electric energy, transmission, and other services between buyers
and sellers, but does not take title to any of the power sold.
(c) "Direct transaction" means a contract between any one or more
electric generators, marketers, or brokers of electric power and one
or more retail customers providing for the purchase and sale of
electric power or any
ancillary services.
(d) "Fire wall" means the line of demarcation separating
residential and small commercial customers from all other customers
as described in subdivision (e) of Section 367.
(e)
(d) "Marketer" means any entity that buys electric
energy, transmission, and other services from traditional utilities
and other suppliers, and then resells those services at wholesale or
to an end-use customer.
(f)
(e) "Microcogeneration facility" means a cogeneration
facility of less than one megawatt.
(g) "Restructuring trusts" means the two tax-exempt public benefit
trusts established by Decision 96-08-038 of the Public Utilities
Commission to provide for design and development of the hardware and
software systems for the Power Exchange and the Independent System
Operator, respectively, and that may undertake other activities, as
needed, as ordered by the commission.
(h)
(f) "Small commercial customer" means a customer that
has a maximum peak demand of less than 20 kilowatts.
SEC. 16. Section 332.1 of the Public
Utilities Code is amended to read:
332.1. (a) (1) It is the intent of the Legislature to enact Item
1 (revised) on the commission's August 21, 2000 , agenda,
entitled "Opinion Modifying Decision (D.) D.00-06-034 and D.00-08-021
to Regarding Interim Rate Caps for San Diego Gas and Electric
Company," as modified below.
(2) It is also the intent of the Legislature that to the extent
that the Federal Energy Regulatory Commission orders refunds to
electrical corporations pursuant to their findings, the commission
shall ensure that any refunds are returned to customers.
(b) The commission shall establish a ceiling of six and
five-tenths cents ($0.065) per kilowatthour on the energy component
of electric bills for electricity supplied to residential, small
commercial, and street lighting customers by the San Diego Gas and
Electric Company, through December 31, 2002, retroactive to June 1,
2000. If the commission finds it in the public interest, this ceiling
may be extended through December 2003 and may be adjusted as
provided in subdivision (d).
(c) The commission shall establish an accounting procedure to
track and recover reasonable and prudent costs of providing electric
energy to retail customers unrecovered through retail bills due to
the application of the ceiling provided for in subdivision (b). The
accounting procedure shall utilize revenues associated with sales of
energy from utility-owned or managed generation assets to offset an
undercollection, if undercollection occurs. The accounting procedure
shall be reviewed periodically by the commission, but not less
frequently than semiannually. The commission may utilize an existing
proceeding to perform the review. The accounting procedure and review
shall provide a reasonable opportunity for San Diego Gas and
Electric Company to recover its reasonable and prudent costs of
service over a reasonable period of time.
(d) If the commission determines that it is in the public interest
to do so, the commission, after the date of the completion of the
proceeding described in subdivision (g), may adjust the ceiling from
the level specified in subdivision (b), and may adjust the frozen
rate from the levels specified in subdivision (f), consistent with
the Legislature's intent to provide substantial protections for
customers of the San Diego Gas and Electric Company and their
interest in just and reasonable rates and adequate service.
(e) For purposes of this section, "small commercial customer"
includes, but is not limited to, all San Diego Gas and Electric
Company accounts on Rate Schedule A of the San Diego Gas and Electric
Company, all accounts of customers who are "general acute care
hospitals," as defined in Section 1250 of the Health and Safety Code,
all San Diego Gas and Electric Company accounts of customers who are
public or private schools for pupils in kindergarten or any of
grades 1 to 12, inclusive, and all accounts on Rate Schedule AL-TOU
under 100 kilowatts.
(f) The commission shall establish an initial frozen rate of six
and five-tenths cents ($0.065) per kilowatthour on the energy
component of electric bills for electricity supplied to all customers
by the San Diego Gas and Electric Company not subject to subdivision
(b), for the time period ending with the end of the rate freeze for
the Pacific Gas and Electric Company and the Southern California
Edison Company pursuant to Section 368 ,
retroactive to February 7, 2001. The commission shall consider the
comparable energy components of rates for comparable customer classes
served by the Pacific Gas and Electric Company and the Southern
California Edison Company and, if it determines it to be in the
public interest, the commission may adjust this frozen rate, and may
do so, retroactive to the date that rate increases took effect for
customers of Pacific Gas and Electric Company and Southern California
Edison Company pursuant to the commission's March 27, 2001,
decision. The commission shall determine the Fixed Department of
Water Resources Set-Aside pursuant to Section 360.5 for customers
subject to this section, reflecting a retail rate consistent with the
rate for the energy component of electric bills as determined in
this subdivision, in place of the retail rate in effect on January 5,
2001. This section shall be construed to modify the payment
provisions, but may not be construed to modify the electric
procurement obligations of the Department of Water Resources,
pursuant to any contract or agreement in accordance with Division 27
(commencing with Section 80000) of the Water Code, and in effect as
of February 7, 2001, between the Department of Water Resources and
San Diego Gas and Electric Company.
(g) The commission shall institute a proceeding to examine the
prudence and reasonableness of the San Diego Gas and Electric Company
in the procurement of wholesale energy on behalf of its customers,
for a period beginning, at the latest, on June 1, 2000. If the
commission finds that San Diego Gas and Electric Company acted
imprudently or unreasonably, the commission shall issue orders that
it determines to be appropriate affecting the retail rates of San
Diego Gas and Electric Company customers including, but not limited
to, refunds.
(h) Nothing in this section may be construed to limit the
authority of the Department of Water Resources pursuant to Division
27 (commencing with Section 80000) of the Water Code.
SEC. 17. Section 341.5 of the Public
Utilities Code is amended to read:
341.5. (a) The Independent System Operator and Power
Exchange bylaws shall contain provisions that identify
those matters specified in subdivision (b) of
Section 339 as matters within state jurisdiction. The bylaws shall
also contain provisions which state that California's bylaws approval
function with respect to the matters specified in
subdivision (b) of Section 339 shall not preclude the
Federal Energy Regulatory Commission from taking any action necessary
to address undue discrimination or other violations of the Federal
Power Act (16 U.S.C.A. Sec. 791a et seq.) or to exercise any other
commission responsibility under the Federal Power Act. In taking any
such action, the Federal Energy Regulatory Commission shall give due
respect to California's jurisdictional interests in the functions of
the Independent System Operator and Power Exchange
and to attempt to accommodate state interests to the extent those
interests are not inconsistent with the Federal Energy Regulatory
Commission's statutory responsibilities. The bylaws shall state that
any future agreement regarding the apportionment of the Independent
System Operator and Power Exchange board
appointment function among participating states associated with the
expansion of the Independent System Operator and Power
Exchange into multistate entities shall be filed with the
Federal Energy Regulatory Commission pursuant to Section 205 of the
Federal Power Act (16 U.S.C.A. Sec. 824d).
(b) Any necessary bylaw changes to implement the provisions of
Section 335, 337, 338, 339, 339 or
subdivision (a) of this section, or changes required pursuant to an
agreement as contemplated by subdivision (a) of this section with a
participating state for a regional organization, shall be effective
upon approval of the respective governing boards and the
Oversight Board and acceptance for filing by the Federal
Energy Regulatory Commission.
SEC. 18. Section 348 of the Public
Utilities Code is amended to read:
348. The Independent System Operator shall adopt inspection,
maintenance, repair, and replacement standards for the transmission
facilities under its control no later than September 30,
1997. control. The standards, which shall be
performance or prescriptive standards, or both, as appropriate, for
each substantial type of transmission equipment or facility, shall
provide for high quality, safe, and reliable service. In adopting its
standards, the Independent System Operator shall consider: cost,
local geography and weather, applicable codes, national electric
industry practices, sound engineering judgment, and experience. The
Independent System Operator shall also adopt standards for
reliability, and safety during periods of emergency and disaster.
The Independent System Operator shall report to the
Oversight Board, at such times as the Oversight Board may specify, on
the development and implementation of the standards in relation to
facilities under the operational control of the Independent System
Operator. The Independent System Operator shall require
each transmission facility owner or operator to report annually on
its compliance with the standards. That report shall be made
available to the public.
SEC. 19. Section 349.5 of the Public
Utilities Code is amended to read:
349.5. (a) Beginning January 15, 2002, and at
At least once monthly thereafter,
each month, the Independent System Operator shall notify each
air pollution control district and air quality management district of
the name and address of each entity within the district's boundaries
within the Independent System Operator's control area with whom the
Independent System Operator enters into an interruptible service
contract or similar arrangement.
(b) For the purposes of this section, "interruptible service
contract or similar arrangement" means any arrangement in which a
nonresidential entity agrees to reduce or consider reducing its
electrical consumption during periods of peak demand or at the
request of the Independent System Operator in exchange for
compensation, or for assurances not to be blacked out or other
similar nonmonetary assurances.
(c) The local air pollution control district or air quality
management district shall maintain in a confidential manner the
information received pursuant to this section. However, nothing in
this subdivision shall affect the applicability of Chapter 3.5
(commencing with Section 6250) of Division 7 of Title 1 of the
Government Code, or of any other similar open records statute or
ordinance, to information provided pursuant to this section.
SEC. 20. Section 350 of the Public
Utilities Code is repealed.
350. The Independent System Operator, in consultation with the
California Energy Resources Conservation and Development Commission,
the Public Utilities Commission, the Western Electricity Coordinating
Council, and concerned regulatory agencies in other western states,
shall within six months after the Federal Energy Regulatory
Commission approval of the Independent System Operator, provide a
report to the Legislature and to the Oversight Board that does the
following:
(a) Conducts an independent review and assessment of Western
Electricity Coordinating Council operating reliability criteria.
(b) Quantifies the economic cost of major transmission outages
relating to the Pacific Intertie, Southwest Power Link, DC link, and
other important high voltage lines that carry power both into and
from California.
(c) Identifies the range of cost-effective options that would
prevent or mitigate the consequences of major transmission outages.
(d) Identifies communication protocols that may be needed to be
established to provide advance warning of incipient problems.
(e) Identifies the need for additional generation reserves and
other voltage support equipment, if any, or other resources that may
be necessary to carry out its functions.
(f) Identifies transmission capacity additions that may be
necessary at certain times of the year or under certain conditions.
(g) Assesses the adequacy of current and prospective institutional
provisions for the maintenance of reliability.
(h) Identifies mechanisms to enforce transmission right-of-way
maintenance.
(i) Contains recommendations regarding cost-beneficial
improvements to electric system reliability for the citizens of
California.
SEC. 21. Section 355 of the Public
Utilities Code is repealed.
355. The Power Exchange shall provide an efficient competitive
auction, open on a nondiscriminatory basis to all suppliers, that
meets the loads of all exchange customers at efficient prices.
SEC. 22. Section 356 of the Public
Utilities Code is repealed.
356. The Power Exchange governing board may form appropriate
technical advisory committees comprised of market and nonmarket
participants to advise the governing board on relevant issues.
SEC. 23. Section 359 of the Public
Utilities Code is amended to read:
359. (a) It is the intent of the Legislature to provide for the
evolution of the Independent System Operator and the Power
Exchange into regional organizations to promote the
development of regional electricity transmission markets in the
western states and to improve the access of consumers served by the
Independent System Operator and the Power Exchange
to those markets.
(b) The preferred means by which the voluntary evolution described
in subdivision (a) should occur is through the adoption of a
regional compact or other comparable agreement among cooperating
party states, the retail customers of which states would reside
within the geographic territories served by the Independent System
Operator and the Power Exchange. Operator.
(c) The agreement described in subdivision (b) should provide for
all of the following:
(1) An equitable process for the appointment or confirmation by
party states of members of the governing boards of the Independent
System Operator and the Power Exchange.
Operator.
(2) A respecification of the size, structure, representation,
eligible membership, nominating procedures, and member terms of
service of the governing boards of the Independent System
Operator and the Power Exchange. Operator.
(3) Mechanisms by which each party state, jointly or separately,
can oversee effectively the actions of the Independent System
Operator and the Power Exchange as those actions
relate to the assurance of electricity system reliability within the
party state and to matters that affect electricity sales to the
retail customers of the party state or otherwise affect the general
welfare of the electricity consumers and the general public of the
party state.
(4) The adherence by publicly owned and investor-owned utilities
located in party states to enforceable standards and protocols to
protect the reliability of the interconnected regional transmission
and distribution systems.
SEC. 24. Section 361 of the Public
Utilities Code is repealed.
361. The commission shall ensure that any funds secured by the
restructuring trusts established for the purposes of developing the
Independent System Operator and the Power Exchange shall be placed at
the disposal of the Independent System Operator and the Power
Exchange respectively.
SEC. 25. Section 363 of the Public
Utilities Code is repealed.
363. (a) In order to ensure the continued safe and reliable
operation of public utility electric generating facilities, the
commission shall require in any proceeding under Section 851
involving the sale, but not spinoff, of a public utility electric
generating facility, for transactions initiated prior to December 31,
2001, and approved by the commission by December 31, 2002, that the
selling utility contract with the purchaser of the facility for the
selling utility, an affiliate, or a successor corporation to operate
and maintain the facility for at least two years. The commission may
require these conditions to be met for transactions initiated on or
after January 1, 2002. The commission shall require the contracts to
be reasonable for both the seller and the buyer.
(b) Subdivision (a) shall apply only if the facility is actually
operated during the two-year period following the sale. Subdivision
(a) shall not require the purchaser to operate a facility, nor shall
it preclude a purchaser from temporarily closing the facility to make
capital improvements.
(c) For those bayside fossil fueled electric generation and
associated transmission facilities that an electrical corporation has
proposed to divest in a public auction and for which the Legislature
has appropriated state funds in the Budget Act of 1998 to assist
local governmental entities in acquiring the facilities or to
mitigate environmental and community issues, and where the local
governmental entity proposes that the closure of the power plant
would serve the public interest by mitigating air, water and other
environmental, health and safety, and community impacts associated
with the facilities, and where the local governmental entity and
electrical corporation have engaged in significant negotiations with
the purpose of shutting down the power plant, and where there is an
agreement between the electrical corporation and the local
governmental entity for closure of the facilities or for the local
governmental entity to acquire the facilities, the commission shall
approve the closure of these facilities or the transfer of these
electric generation and associated transmission facilities to the
local governmental entity and shall consider the utility transactions
with the community to be just and reasonable for its ratepayers. For
purposes of calculating the Competition Transition Charge, the
commission shall not use any inferred market value for the facilities
predicated on the continued use of the plant, the construction of
successor facilities or alternative use of the site and shall net the
costs of the depreciated book value of the power plant and the
unrecovered costs of decommissioning, environmental remediation and
site restoration against the net proceeds received from the local
governmental entity for the acquisition or closure of the facilities.
Thereafter, any net proceeds received from the ultimate disposition,
by the electrical corporation, of the site shall be credited to
recovery of Competition Transition Charges.
SEC. 26. Section 365 of the Public
Utilities Code is amended to read:
365. The actions of the commission pursuant to this
chapter shall be consistent with the findings and declarations
contained in Section 330. In addition, the commission shall
do all of the following:
(a) Facilitate the efforts of the state's electrical corporations
to develop and obtain authorization from the Federal Energy
Regulatory Commission for the creation and operation of an
Independent System Operator and an independent Power
Exchange, Operator, for the determination of
which transmission and distribution facilities are subject to the
exclusive jurisdiction of the commission, and for approval,
to the extent necessary, of the cost recovery mechanism established
as provided in Sections 367 to 376, inclusive.
commission. The commission shall also participate fully in all
proceedings before the Federal Energy Regulatory Commission in
connection with the Independent System Operator and the
independent Power Exchange, and shall encourage the Federal
Energy Regulatory Commission to adopt protocols and procedures that
strengthen the reliability of the interconnected transmission grid,
encourage all publicly owned utilities in California to become full
participants, and maximize enforceability of such protocols and
procedures by all market participants.
(b) (1) Authorize direct transactions between electricity
suppliers and end use customers, subject to implementation of
the nonbypassable charge referred to in Sections 367 to 376,
inclusive. competition transition charges.
Direct transactions shall commence simultaneously with the start of
an Independent System Operator and Power Exchange
referred to in subdivision (a). The simultaneous commencement shall
occur as soon as practicable, but no later than January 1, 1998. The
commission shall develop a phase-in schedule at the conclusion of
which all customers shall have the right to engage in direct
transactions. Any phase-in of customer eligibility for direct
transactions ordered by the commission shall be equitable to all
customer classes and accomplished as soon as practicable, consistent
with operational and other technological considerations, and shall be
completed for all customers by January 1, 2002.
(2) Customers shall be eligible for direct access irrespective of
any direct access phase-in implemented pursuant to this section if at
least one-half of that customer's electrical load is supplied by
energy from a renewable resource provider certified pursuant to
Section 383, provided however that nothing in this section shall
provide for direct access for electric consumers served by municipal
utilities unless so authorized by the governing board of that
municipal utility.
SEC. 27. Section 367 of the Public
Utilities Code is repealed.
367. The commission shall identify and determine those costs and
categories of costs for generation-related assets and obligations,
consisting of generation facilities, generation-related regulatory
assets, nuclear settlements, and power purchase contracts, including,
but not limited to, restructurings, renegotiations or terminations
thereof approved by the commission, that were being collected in
commission-approved rates on December 20, 1995, and that may become
uneconomic as a result of a competitive generation market, in that
these costs may not be recoverable in market prices in a competitive
market, and appropriate costs incurred after December 20, 1995, for
capital additions to generating facilities existing as of December
20, 1995, that the commission determines are reasonable and should be
recovered, provided that these additions are necessary to maintain
the facilities through December 31, 2001. These uneconomic costs
shall include transition costs as defined in subdivision (f) of
Section 840, and shall be recovered from all customers or in the case
of fixed transition amounts, from the customers specified in
subdivision (a) of Section 841, on a nonbypassable basis and shall:
(a) Be amortized over a reasonable time period, including
collection on an accelerated basis, consistent with not increasing
rates for any rate schedule, contract, or tariff option above the
levels in effect on June 10, 1996; provided that, the recovery shall
not extend beyond December 31, 2001, except as follows:
(1) Costs associated with employee-related transition costs as set
forth in subdivision (b) of Section 375 shall continue until fully
collected; provided, however, that the cost collection shall not
extend beyond December 31, 2006.
(2) Power purchase contract obligations shall continue for the
duration of the contract. Costs associated with any buy-out,
buy-down, or renegotiation of the contracts shall continue to be
collected for the duration of any agreement governing the buy-out,
buy-down, or renegotiated contract; provided, however, no power
purchase contract shall be extended as a result of the buy-out,
buy-down, or renegotiation.
(3) Costs associated with contracts approved by the commission to
settle issues associated with the Biennial Resource Plan Update may
be collected through March 31, 2002; provided that only 80 percent of
the balance of the costs remaining after December 31, 2001, shall be
eligible for recovery.
(4) Nuclear incremental cost incentive plans for the San Onofre
nuclear generating station shall continue for the full term as
authorized by the commission in Decision 96-01-011 and Decision
96-04-059; provided that the recovery shall not extend beyond
December 31, 2003.
(5) Costs associated with the exemptions provided in subdivision
(a) of Section 374 may be collected through March 31, 2002, provided
that only fifty million dollars ($50,000,000) of the balance of the
costs remaining after December 31, 2001, shall be eligible for
recovery.
(6) Fixed transition amounts, as defined in subdivision (d) of
Section 840, may be recovered from the customers specified in
subdivision (a) of Section 841 until all rate reduction bonds
associated with the fixed transition
amounts have been paid in full by the financing
entity.
(b) Be based on a calculation mechanism that nets the negative
value of all above market utility-owned generation-related assets
against the positive value of all below market utility-owned
generation related assets. For those assets subject to valuation, the
valuations used for the calculation of the uneconomic portion of the
net book value shall be determined not later than December 31, 2001,
and shall be based on appraisal, sale, or other divestiture. The
commission's determination of the costs eligible for recovery and of
the valuation of those assets at the time the assets are exposed to
market risk or retired, in a proceeding under Section 455.5, 851, or
otherwise, shall be final, and notwithstanding Section 1708 or any
other provision of law, may not be rescinded, altered or amended.
(c) Be limited in the case of utility-owned fossil generation to
the uneconomic portion of the net book value of the fossil capital
investment existing as of January 1, 1998, and appropriate costs
incurred after December 20, 1995, for capital additions to generating
facilities existing as of December 20, 1995, that the commission
determines are reasonable and should be recovered, provided that the
additions are necessary to maintain the facilities through December
31, 2001. All "going forward costs" of fossil plant operation,
including operation and maintenance, administrative and general, fuel
and fuel transportation costs, shall be recovered solely from
independent Power Exchange revenues or from contracts with the
Independent System Operator, provided that for the purposes of this
chapter, the following costs may be recoverable pursuant to this
section:
(1) Commission-approved operating costs for particular
utility-owned fossil powerplants or units, at particular times when
reactive power/voltage support is not yet procurable at market-based
rates in locations where it is deemed needed for the reactive
power/voltage support by the Independent System Operator, provided
that the units are otherwise authorized to recover market-based rates
and provided further that for an electrical corporation that is also
a gas corporation and that serves at least four million customers as
of December 20, 1995, the commission shall allow the electrical
corporation to retain any earnings from operations of the reactive
power/voltage support plants or units and shall not require the
utility to apply any portions to offset recovery of transition costs.
Cost recovery under the cost recovery mechanism shall end on
December 31, 2001.
(2) An electrical corporation that, as of December 20, 1995,
served at least four million customers, and that was also a gas
corporation that served less than four thousand customers, may
recover, pursuant to this section, 100 percent of the uneconomic
portion of the fixed costs paid under fuel and fuel transportation
contracts that were executed prior to December 20, 1995, and were
subsequently determined to be reasonable by the commission, or 100
percent of the buy-down or buy-out costs associated with the
contracts to the extent the costs are determined to be reasonable by
the commission.
(d) Be adjusted throughout the period through March 31, 2002, to
track accrual and recovery of costs provided for in this subdivision.
Recovery of costs prior to December 31, 2001, shall include a return
as provided for in Decision 95-12-063, as modified by Decision
96-01-009, together with associated taxes.
(e) (1) Be allocated among the various classes of customers, rate
schedules, and tariff options to ensure that costs are recovered from
these classes, rate schedules, contract rates, and tariff options,
including self-generation deferral, interruptible, and standby rate
options in substantially the same proportion as similar costs are
recovered as of June 10, 1996, through the regulated retail rates of
the relevant electric utility, provided that there shall be a
firewall segregating the recovery of the costs of competition
transition charge exemptions such that the costs of competition
transition charge exemptions granted to members of the combined class
of residential and small commercial customers shall be recovered
only from these customers, and the costs of competition transition
charge exemptions granted to members of the combined class of
customers, other than residential and small commercial customers,
shall be recovered only from these customers.
(2) Individual customers shall not experience rate increases as a
result of the allocation of transition costs. However, customers who
elect to purchase energy from suppliers other than the Power Exchange
through a direct transaction, may incur increases in the total price
they pay for electricity to the extent the price for the energy
exceeds the Power Exchange price.
(3) The commission shall retain existing cost allocation
authority, provided the firewall and rate freeze principles are not
violated.
SEC. 28. Section 367.7 of the Public
Utilities Code is repealed.
367.7. (a) It is the intent of the Legislature in enacting this
section to ensure that individual customers do not experience rate
increases as a result of the allocation of transition costs, in
accordance with paragraph (2) of subdivision (e) of Section 367.
(b) The commission shall implement a methodology whereby the Power
Exchange energy credit for a customer with a meter installed on or
after June 30, 2000, that is capable of recording hourly data is
calculated based on the actual hourly data for that customer. The
Power Exchange energy credit for a customer with a meter installed
before June 30, 2000, that is capable of recording hourly data shall,
at the election of the customer, on a one-time basis before June 30,
2000, be calculated based on either (1) the actual hourly data for
that customer or (2) the average load profile for that customer
class. If the customer fails to make an election, that customer's
Power Exchange energy credit shall continue to be based on the
average load profile for that customer class.
(c) Additional incremental billing costs incurred as a result of
the methodology implemented by the commission pursuant to subdivision
(b) may be recoverable through rates for that customer class, if the
commission finds that the costs are reasonable.
(d) The methodology implemented by the commission pursuant to
subdivisions (b) and (c) shall not result in any shifts in cost
between customer classes and shall be consistent with the firewall
provision set forth in subdivision (e) of Section 367.
SEC. 29. Section 368 of the Public
Utilities Code is amended to read:
368. Each electrical corporation shall propose a cost recovery
plan to the commission for the recovery of the uneconomic costs of an
electrical corporation's generation-related assets and obligations
identified in Section 367. The commission shall authorize
the electrical corporation to recover the costs pursuant to the plan
if the plan meets the following criteria: provide for
identification and separation of individual rate components such as
charges for energy, transmission, distribution, public benefit
programs, and recovery of uneconomic costs. The separation of rate
components required by this section shall be used to ensure that
customers of the electrical corporation who purchase
electricity fr om suppliers other than the electrical
corporation pay the same unbundled component charges, other than
energy, that a bundled service customer pays.
(a) The cost recovery plan shall set rates for each customer
class, rate schedule, contract, or tariff option, at levels equal to
the level as shown on electric rate schedules as of June 10, 1996,
provided that rates for residential and small commercial customers
shall be reduced so that these customers shall receive rate
reductions of no less than 10 percent for 1998 continuing through
2002. These rate levels for each customer class, rate schedule,
contract, or tariff option shall remain in effect until the earlier
of March 31, 2002, or the date on which the commission-authorized
costs for utility generation-related assets and obligations have been
fully recovered. The electrical corporation shall be at risk for
those costs not recovered during that time period. Each utility shall
amortize its total uneconomic costs, to the extent possible, such
that for each year during the transition period its recorded rate of
return on the remaining uneconomic assets does not exceed its
authorized rate of return for those assets. For purposes of
determining the extent to which the costs have been recovered, any
over-collections recorded in Energy Costs Adjustment Clause and
Electric Revenue Adjustment Mechanism balancing accounts, as of
December 31, 1996, shall be credited to the recovery of the costs.
(b) The cost recovery plan shall provide for identification and
separation of individual rate components such as charges for energy,
transmission, distribution, public benefit programs, and recovery of
uneconomic costs. The separation of rate components required by this
subdivision shall be used to ensure that customers of the electrical
corporation who become eligible to purchase electricity from
suppliers other than the electrical corporation pay the same
unbundled component charges, other than energy, that a bundled
service customer pays. No cost shifting among customer classes, rate
schedules, contract, or tariff options shall result from the
separation required by this subdivision. Nothing in this provision is
intended to affect the rates, terms, and conditions or to limit the
use of any Federal Energy Regulatory Commission-approved contract
entered into by the electrical corporation prior to the effective
date of this provision.
(c) In consideration of the risk that the uneconomic costs
identified in Section 367 may not be recoverable within the period
identified in subdivision (a) of Section 367, an electrical
corporation that, as of December 20, 1995, served more than four
million customers, and was also a gas corporation that served less
than four thousand customers, shall have the flexibility to employ
risk management tools, such as forward hedges, to manage the market
price volatility associated with unexpected fluctuations in natural
gas prices, and the out-of-pocket costs of acquiring the risk
management tools shall be considered reasonable and collectible
within the transition freeze period. This subdivision applies only to
the transaction costs associated with the risk management tools and
shall not include any losses from changes in market prices.
(d) In order to ensure implementation of the cost recovery plan,
the limitation on the maximum amount of cost recovery for nuclear
facilities that may be collected in any year adopted by the
commission in Decision 96-01-011 and Decision 96-04-059 shall be
eliminated to allow the maximum opportunity to collect the nuclear
costs within the transition cap period.
(e) As to an electrical corporation that is also a gas corporation
serving more than four million California customers, so long as any
cost recovery plan adopted in accordance with this section satisfies
subdivision (a), it shall also provide for annual increases in base
revenues, effective January 1, 1997, and January 1, 1998, equal to
the inflation rate for the prior year plus two percentage points, as
measured by the consumer price index. The increase shall do both of
the following:
(1) Remain in effect pending the next general rate case review,
which shall be filed not later than December 31, 1997, for rates that
would become effective in January 1999. For purposes of any
commission-approved performance-based ratemaking mechanism or general
rate case review, the increases in base revenue authorized by this
subdivision shall create no presumption that the level of base
revenue reflecting those increases constitute the appropriate
starting point for subsequent revenues.
(2) Be used by the utility for the purposes of enhancing its
transmission and distribution system safety and reliability,
including, but not limited to, vegetation management and emergency
response. To the extent the revenues are not expended for system
safety and reliability, they shall be credited against subsequent
safety and reliability base revenue requirements. Any excess revenues
carried over shall not be used to pay any monetary sanctions imposed
by the commission.
(f) The cost recovery plan shall provide the electrical
corporation with the flexibility to manage the renegotiation,
buy-out, or buy-down of the electrical corporation's power purchase
obligations, consistent with review by the commission to assure that
the terms provide net benefits to ratepayers and are otherwise
reasonable in protecting the interests of both ratepayers and
shareholders.
(g) An example of a plan authorized by this section is the
document entitled "Restructuring Rate Settlement" transmitted to the
commission by Pacific Gas and Electric Company on June 12, 1996.
SEC. 30. Section 368.5 of the Public
Utilities Code is repealed.
368.5. (a) Notwithstanding any other provision of law, upon the
termination of the 10-percent rate reduction for residential and
small commercial customers set forth in subdivision (a) of Section
368, the commission may not subject those residential and small
commercial customers to any rate increases or future rate obligations
solely as a result of the termination of the 10-percent rate
reduction.
(b) The provisions of subdivision (a) do not affect the authority
of the commission to raise rates for reasons other than the
termination of the 10-percent rate reduction set forth in subdivision
(a) of Section 368.
(c) Nothing in this section shall further extend the authority to
impose fixed transition amounts, as defined in subdivision (d) of
Section 840, or further authorize or extend rate reduction bonds, as
defined in subdivision (e) of Section 840.
SEC. 31. Section 369 of the Public
Utilities Code is amended to read:
369. The commission shall establish an effective
mechanism that ensures recovery of transition costs referred to in
Sections 367, 368, 375, and 376, and Competition
transition charges, subject to the conditions in Sections 371
to 374, inclusive, from the recovery of which
was authorized by the commission prior to January 1, 2015, shall
continue to apply to all existing and future consumers in the
service territory in which the utility provided electricity services
as of December 20, 1995; provided, that the costs shall not be
recoverable for new customer load or incremental load of an existing
customer where the load is being met through a direct transaction and
the transaction does not otherwise require the use of transmission
or distribution facilities owned by the utility. However, the
obligation to pay the competition transition charges cannot be
avoided by the formation of a local publicly owned electrical
corporation on or after December 20, 1995, or by annexation of any
portion of an electrical corporation's service area by an existing
local publicly owned electric utility.
This section shall not apply to service taken under tariffs,
contracts, or rate schedules that are on file, accepted, or approved
by the Federal Energy Regulatory Commission, unless otherwise
authorized by the Federal Energy Regulatory Commission.
SEC. 32. Section 370 of the Public
Utilities Code is amended to read:
370. The commission shall require, as a prerequisite for any
consumer in California to engage in direct transactions permitted in
Section 365, that beginning with the commencement of these direct
transactions, the consumer shall have an obligation to pay
the costs provided in Sections 367, 368, 375, and 376,
competition transition charges, and subject to the conditions
in Sections 371 to 374, inclusive, directly to the electrical
corporation providing electricity service in the area in which the
consumer is located. This obligation shall be set forth in the
applicable rate schedule, contract, or tariff option under which the
customer is receiving service from the electrical corporation. To the
extent the consumer does not use the electrical corporation's
facilities for direct transaction, the obligation to pay shall be
confirmed in writing, and the customer shall be advised by any
electricity marketer engaged in the transaction of the requirement
that the customer execute a confirmation. The requirement for
marketers to inform customers of the written requirement shall cease
on January 1, 2002.
SEC. 33. Section 371 of the Public
Utilities Code is amended to read:
371. (a) Except as provided in Sections 372 and 374, the
uneconomic costs provided in Sections 367, 368, 375, and 376
competition transition charges shall be applied
to each customer based on the amount of electricity purchased by the
customer from an electrical corporation or alternate supplier of
electricity, subject to changes in usage occurring in the normal
course of business.
(b) Changes in usage occurring in the normal course of business
are those resulting from changes in business cycles, termination of
operations, departure from the utility service territory, weather,
reduced production, modifications to production equipment or
operations, changes in production or manufacturing processes, fuel
switching, including installation of fuel cells pending a contrary
determination by the California Energy Resources
Conservation and Development Commission in Section 383,
Energy Commission, enhancement or increased efficiency of
equipment or performance of existing self-cogeneration equipment,
replacement of existing cogeneration equipment with new power
generation equipment of similar size as described in paragraph (1) of
subdivision (a) of Section 372, installation of demand-side
management equipment or facilities, energy conservation efforts, or
other similar factors.
(c) Nothing in this section shall be interpreted to exempt or
alter the obligation of a customer to comply with Chapter 5
(commencing with Section 119075) of Part 15 of Division 104 of the
Health and Safety Code. Nothing in this section shall be construed as
a limitation on the ability of residential customers to alter their
pattern of electricity purchases by activities on the customer side
of the meter.
SEC. 34. Section 372 of the Public
Utilities Code is amended to read:
372. (a) It is the policy of the state to encourage and support
the development of cogeneration as an efficient, environmentally
beneficial, competitive energy resource that will enhance the
reliability of local generation supply, and promote local business
growth. Subject to the specific conditions provided in this section,
the commission shall determine the applicability to customers of
uneconomic costs as specified in Sections 367, 368, 375, and
376. competition transition charges. Consistent
with this state policy, the commission shall provide that these
costs shall not apply to any of the following:
(1) To load served onsite or under an over the fence arrangement
by a nonmobile self-cogeneration or cogeneration facility that was
operational on or before December 20, 1995, or by increases in the
capacity of a facility to the extent that the increased capacity was
constructed by an entity holding an ownership interest in or
operating the facility and does not exceed 120 percent of the
installed capacity as of December 20, 1995, provided that prior to
June 30, 2000, the costs shall apply to over the fence arrangements
entered into after December 20, 1995, between unaffiliated parties.
For the purposes of this subdivision, "affiliated" means any person
or entity that directly, or indirectly through one or more
intermediaries, controls, is controlled by, or is under common
control with another specified entity. "Control" means either of the
following:
(A) The possession, directly or indirectly, of the power to direct
or to cause the direction of the management or policies of a person
or entity, whether through an ownership, beneficial, contractual, or
equitable interest.
(B) Direct or indirect ownership of at least 25 percent of an
entity, whether through an ownership, beneficial, or equitable
interest.
(2) To load served by onsite or under an over the fence
arrangement by a nonmobile self-cogeneration or cogeneration facility
for which the customer was committed to construction as of December
20, 1995, provided that the facility was substantially operational on
or before January 1, 1998, or by increases in the capacity of a
facility to the extent that the increased capacity was constructed by
an entity holding an ownership interest in or operating the facility
and does not exceed 120 percent of the installed capacity as of
January 1, 1998, provided that prior to June 30, 2000, the costs
shall apply to over the fence arrangements entered into after
December 20, 1995, between unaffiliated parties.
(3) To load served by existing, new, or portable emergency
generation equipment used to serve the customer's load requirements
during periods when utility service is unavailable, provided the
emergency generation is not operated in parallel with the integrated
electric grid, except on a momentary parallel basis.
(4) After June 30, 2000, to any load served onsite or under an
over the fence arrangement by any nonmobile self-cogeneration or
cogeneration facility.
(b) Further, consistent with state policy, with respect to
self-cogeneration or cogeneration deferral agreements, the commission
shall do the following:
(1) Provide that a utility shall execute a final self-cogeneration
or cogeneration deferral agreement with any customer that, on or
before December 20, 1995, had executed a letter of intent (or similar
documentation) to enter into the agreement with the utility,
provided that the final agreement shall be consistent with the terms
and conditions set forth in the letter of intent and the commission
shall review and approve the final agreement.
(2) Provide that a customer that holds a self-cogeneration or
cogeneration deferral agreement that was in place on or before
December 20, 1995, or that was executed pursuant to paragraph (1) in
the event the agreement expires, or is terminated, may do any of the
following:
(A) Continue through December 31, 2001, to receive utility service
at the rate and under terms and conditions applicable to the
customer under the deferral agreement that, as executed, includes an
allocation of uneconomic costs consistent with subdivision (e) of
Section 367.
(B) Engage in a direct transaction for the purchase of electricity
and pay uneconomic costs consistent with Sections 367, 368,
375, 367 and 376.
(C) Construct a self-cogeneration or cogeneration facility of
approximately the same capacity as the facility previously deferred,
provided that the costs provided in Sections 367, 368, 375,
367 and 376 shall apply consistent with
subdivision (e) of Section 367, unless otherwise authorized by the
commission pursuant to subdivision (c).
(3) Subject to the firewall described in subdivision (e) of
Section 367, provide that the ratemaking treatment for
self-cogeneration or cogeneration deferral agreements executed prior
to December 20, 1995, or executed pursuant to paragraph (1) shall be
consistent with the ratemaking treatment for the contracts approved
before January 1995.
(c) The commission shall authorize, within 60 days of the receipt
of a joint application from the serving utility and one or more
interested parties, applicability conditions as follows:
(1) The costs identified in Sections 367, 368, 375, and
376 Competition transition charges
shall not, prior to June 30, 2000, apply to load served onsite by a
nonmobile self-cogeneration or cogeneration facility that became
operational on or after December 20, 1995.
(2) The costs identified in Sections 367, 368, 375, and
376 Competition transition charges shall not,
prior to June 30, 2000, apply to any load served under over the fence
arrangements entered into after December 20, 1995, between
unaffiliated entities.
(d) For the purposes of this subdivision, all onsite or over the
fence arrangements shall be consistent with Section 218 as it existed
on December 20, 1995.
(e) To
facilitate the development of new microcogeneration applications,
electrical corporations may apply to the commission for a financing
order to finance the transition costs to be recovered from customers
employing the applications.
(f) To encourage the continued development, installation, and
interconnection of clean and efficient self-generation and
cogeneration resources, to improve system reliability for consumers
by retaining existing generation and encouraging new generation to
connect to the electric grid, and to increase self-sufficiency of
consumers of electricity through the deployment of self-generation
and cogeneration, both of the following shall occur:
(1) The commission and the Electricity Oversight Board
shall determine if any policy or action undertaken by the
Independent System Operator, directly or indirectly, unreasonably
discourages the connection of existing self-generation or
cogeneration or new self-generation or cogeneration to the grid.
(2) If the commission and the Electricity Oversight Board
find finds that any policy or action of the
Independent System Operator unreasonably discourages the connection
of existing self-generation or cogeneration or new self-generation or
cogeneration to the grid, the commission and the
Electricity Oversight Board shall undertake all necessary
efforts to revise, mitigate, or eliminate that policy or action of
the Independent System Operator.
SEC. 35. Section 373 of the Public
Utilities Code is repealed.
373. (a) Electrical corporations may apply to the commission for
an order determining that the costs identified in Sections 367, 368,
375, and 376 not be collected from a particular class of customer or
category of electricity consumption.
(b) Subject to the fire wall specified in subdivision (e) of
Section 367, the provisions of this section and Sections 372 and 374
shall apply in the event the commission authorizes a nonbypassable
charge prior to the implementation of an Independent System Operator
and Power Exchange referred to in subdivision (a) of Section 365.
SEC. 36. Section 374 of the Public
Utilities Code is amended to read:
374. (a) In recognition of statutory authority and past
investments existing as of December 20, 1995, and subject to the
firewall specified in subdivision (e) of Section 367, the obligation
to pay the uneconomic costs identified in Sections 367, 368, 375, and
376 Competition transition charges shall not
apply to the following:
(1) One hundred ten megawatts of load served by irrigation
districts, as hereafter allocated by this paragraph:
(A) The 110 megawatts of load shall be allocated among the service
territories of the three largest electrical corporations in the
ratio of the number of irrigation districts in the service territory
of each utility to the total number of irrigation districts in the
service territories of all three utilities.
(B) The total amount of load allocated to each utility service
area shall be phased in over five years beginning January 1, 1997, so
that one-fifth of the allocation is allocated in each of the five
years. Any allocation that remains unused at the end of any year
shall be carried over to the succeeding year and added to the
allocation for that year.
(C) The load allocated to each utility service territory pursuant
to subparagraph (A) shall be further allocated among the respective
irrigation districts within that service territory by the
California Energy Resources Conservation and Development
Energy Commission. An individual irrigation district
requesting an allocation shall submit to the commission by January
31, 1997, detailed plans that show the load that it serves or will
serve and for which it intends to utilize the allocation within the
timeframe requested. These plans shall include specific information
on the irrigation districts' organization for electric distribution,
contracts, financing and engineering plans for capital facilities, as
well as detailed information about the loads to be served, and shall
not be less than eight megawatts or more than 40 megawatts,
provided, however, that any portion of the 110 megawatts that remains
unallocated may be reallocated to projects without regard to the 40
megawatts limitation. In making an allocation among irrigation
districts, the Energy Resources Conservation and Development
Commission shall assess the viability of each submission
and whether it can be accomplished in the timeframe proposed. The
Energy Resources Conservation and Development
Commission shall have the discretion to allocate the load covered by
this section in a manner that best ensures its usage within the
allocation period.
(D) At least 50 percent of each year's allocation to a district
shall be applied to that portion of load that is used to power pumps
for agricultural purposes.
(E) Any load pursuant to this subdivision shall be served by
distribution facilities owned by, or leased to, the district in
question.
(F) Any load allocated pursuant to paragraph (1) shall be located
within the boundaries of the affected irrigation district, or within
the boundaries specified in an applicable service territory boundary
agreement between an electrical corporation and the affected
irrigation district; additionally, the provisions of subparagraph (C)
of paragraph (1) shall be applicable to any load within the Counties
of Stanislaus or San Joaquin, or both, served by any irrigation
district that is currently serving or will be serving retail
customers.
(2) Seventy-five megawatts of load served by the Merced Irrigation
District hereafter prescribed in this paragraph:
(A) The total allocation provided by this paragraph shall be
phased in over five years beginning January 1, 1997, so that
one-fifth of the allocation is received in each of the five years.
Any allocation that remains unused at the end of any year shall be
carried over to the succeeding year and added to the allocation for
that year.
(B) Any load to which the provision of this paragraph is
applicable shall be served by distribution facilities owned by, or
leased to, Merced Irrigation District.
(C) A load to which the provisions of this paragraph are
applicable shall be located within the boundaries of Merced
Irrigation District as those boundaries existed on December 20, 1995,
together with the territory of Castle Air Force Base that was
located outside of the district on that date.
(D) The total allocation provided by this paragraph shall be
phased in over five years beginning January 1, 1997, with the
exception of load already being served by the district as of June 1,
1996, which shall be deducted from the total allocation and shall not
be subject to the costs provided in Sections 367, 368, 375,
and 376. competition transition charges.
(3) To loads served by irrigation districts, water districts,
water storage districts, municipal utility districts, and other water
agencies that, on December 20, 1995, were members of the Southern
San Joaquin Valley Power Authority, or the Eastside Power Authority,
provided, however, that this paragraph shall be applicable only to
that portion of each district or agency's load that is used to power
pumps that are owned by that district or agency as of December 20,
1995, or replacements thereof, and is being used to pump water for
district purposes. The rates applicable to these districts and
agencies shall be adjusted as of January 1, 1997.
(4) The provisions of this subdivision shall no longer be
operative after March 31, 2002.
(5) The provisions of paragraph (1) shall not be applicable to any
irrigation district, water district, or water agency described in
paragraph (2) or (3).
(6) Transmission services provided to any irrigation district
described in paragraph (1) or (2) shall be provided pursuant to
otherwise applicable tariffs.
(7) Nothing in this chapter shall be deemed to grant the
commission any jurisdiction over irrigation districts not already
granted to the commission by existing law.
(b) To give the full effect to the legislative intent in enacting
Section 701.8, the costs provided in Sections 367, 368, 375,
and 376 competition transition charges shall
not apply to the load served by preference power purchased from a
federal power marketing agency, or its successor, pursuant to Section
701.8 as it existed on January 1, 1996, provided that the power is
used solely for the customer's own systems load and not for sale. The
costs of this provision shall be borne by all ratepayers in the
affected service territory, notwithstanding the firewall established
in subdivision (e) of Section 367.
(c) To give effect to an existing relationship, the obligation to
pay the uneconomic costs specified in Sections 367, 368,
375, and 376 competition transition charges shall
not apply to that portion of the load of the University of
California campus situated in Yolo County that was being served as of
May 31, 1996, by preference power purchased from a federal marketing
agency, or its successor, provided that the power is used solely for
the facility load of that campus and not, directly or indirectly,
for sale.
SEC. 37. Section 374.5 of the Public
Utilities Code is repealed.
374.5. Any electrical corporation serving agricultural customers
that have multiple electric meters shall conduct research based on a
statistically valid sample of those customers and meters to determine
the typical simultaneous peak load of those customers. The results
of the research shall be reported to the customers and the commission
not later than July 1, 2001. The commission shall consider the
research results in setting future electric distribution rates for
those customers.
SEC. 38. Section 375 of the Public
Utilities Code is repealed.
375. (a) In order to mitigate potential negative impacts on
utility personnel directly affected by electric industry
restructuring, as described in Decision 95-12-063, as modified by
Decision 96-01-009, the commission shall allow the recovery of
reasonable employee related transition costs incurred and projected
for severance, retraining, early retirement, outplacement and related
expenses for the employees.
(b) The costs, including employee related transition costs for
employees performing services in connection with Section 363, shall
be added to the amount of uneconomic costs allowed to be recovered
pursuant to this section and Sections 367, 368, and 376, provided
recovery of these employee related transition costs shall extend
beyond December 31, 2001, provided recovery of the costs shall not
extend beyond December 31, 2006. However, there shall be no recovery
for employee related transition costs associated with officers,
senior supervisory employees, and professional employees performing
predominantly regulatory functions.
SEC. 39. Section 376 of the Public
Utilities Code is repealed.
376. To the extent that the costs of programs to accommodate
implementation of direct access, the Power Exchange, and the
Independent System Operator, that have been funded by an electrical
corporation and have been found by the commission or the Federal
Energy Regulatory Commission to be recoverable from the utility's
customers, reduce an electrical corporation's opportunity to recover
its utility generation-related plant and regulatory assets by the end
of the year 2001, the electrical corporation may recover unrecovered
utility generation-related plant and regulatory assets after
December 31, 2001, in an amount equal to the utility's cost of
commission-approved or Federal Energy Regulatory Commission approved
restructuring-related implementation programs. An electrical
corporation's ability to collect the amounts from retail customers
after the year 2001 shall be reduced to the extent the Independent
System Operator or the Power Exchange reimburses the electrical
corporation for the costs of any of these programs.
SEC. 40. Section 379 of the Public
Utilities Code is amended to read:
379. Nuclear decommissioning costs shall not be part of the
costs described in Sections 367, 368, 375, and 376,
competition transition charges, but shall be
recovered as a nonbypassable charge until the time as the costs are
fully recovered. Recovery of decommissioning costs may be accelerated
to the extent possible.
SEC. 41. Section 390 of the Public
Utilities Code is repealed.
390. (a) Subject to applicable contractual terms, energy prices
paid to nonutility power generators by a public utility electrical
corporation based upon the commission's prescribed "short run avoided
cost energy methodology" shall be determined as set forth in
subdivisions (b) and (c).
(b) Until the requirements of subdivision (c) have been satisfied,
short run avoided cost energy payments paid to nonutility power
generators by an electrical corporation shall be based on a formula
that reflects a starting energy price, adjusted monthly to reflect
changes in a starting gas index price in relation to an average of
current California natural gas border price indices. The starting
energy price shall be based on 12-month averages of recent,
pre-January 1, 1996, short-run avoided energy prices paid by each
public utility electrical corporation to nonutility power generators.
The starting gas index price shall be established as an average of
index gas prices for the same annual periods.
(c) The short-run avoided cost energy payments paid to nonutility
power generators by electrical corporations shall be based on the
clearing price paid by the independent Power Exchange if (1) the
commission has issued an order determining that the independent Power
Exchange is functioning properly for the purposes of determining the
short-run avoided cost energy payments to be made to nonutility
power generators, and either (2) the fossil-fired generation units
owned, directly or indirectly, by the public utility electrical
corporation are authorized to charge market-based rates and the
"going forward" costs of those units are being recovered solely
through the clearing prices paid by the independent Power Exchange or
from contracts with the Independent System Operator, whether those
contracts are market-based or based on operating costs for particular
utility-owned powerplant units and at particular times when reactive
power/voltage support is not yet procurable at market-based rates at
locations where it is needed, and are not being recovered directly
or indirectly through any other source, or (3) the public utility
electrical corporation has divested 90 percent of its gas-fired
generation facilities that were operated to meet load in 1994 and
1995. However, nonutility power generators subject to this section
may, upon appropriate notice to the public utility electrical
corporation, exercise a one-time option to elect to thereafter
receive energy payments based upon the clearing price from the
independent Power Exchange.
(d) If a nonutility power generator is being paid short-run
avoided costs energy payments by an electrical corporation by a firm
capacity contract, a forecast as-available capacity contract, or a
forecast as-delivered capacity contract on the basis of the clearing
price paid by the independent Power Exchange as described in
subdivision (c) above, the value of capacity in the clearing price,
if any, shall not be paid to the nonutility power generator. The
value of capacity in the clearing price, if any, equals the
difference between the market clearing customer demand bid at the
level of generation dispatched by the independent Power Exchange and
the highest supplier bid dispatched.
(e) Short-run avoided energy cost payments made pursuant to this
section are in addition to contractually specified capacity payments.
Nothing in this section shall be construed to affect, modify or
amend the terms and conditions of existing nonutility power
generators' contracts with respect to the sale of energy or capacity
or otherwise.
(f) Nothing in this section shall be construed to limit the level
of transition cost recovery provided to utilities under electric
industry restructuring policies established by the commission.
(g) The term "going forward costs" shall include, but not be
limited to, all costs associated with fuel transportation and fuel
supply, administrative and general, and operation and maintenance;
provided that, for purposes of this section, the following shall not
be considered "going forward costs": (1) commission-approved capital
costs for capital additions to fossil-fueled powerplants, provided
that such additions are necessary for the continued operation of the
powerplants utilized to meet load and such additions are not
undertaken primarily to expand, repower or enhance the efficiency of
plant operations; or, (2) commission-approved operating costs for
particular utility-owned powerplant units and at particular times
when reactive power/voltage support is not yet procurable at
market-based rates in locations where it is needed, provided that the
recovery shall end on December 31, 2001.
SEC. 42. Section 390.1 of the Public
Utilities Code is repealed.
390.1. Any nonutility power generator using renewable fuels that
has entered into a contract with an electrical corporation prior to
December 31, 2001, specifying fixed energy prices for five years of
output may negotiate a contract for an additional five years of fixed
energy payments upon expiration of the initial five-year term, at a
price to be determined by the commission.
SEC. 43. Section 394.5 of the Public
Utilities Code is amended to read:
394.5. (a) Except for an electrical corporation as defined in
Section 218, or a local publicly owned electric utility offering
electrical service to residential and small commercial customers
within its service territory, each electric service provider offering
electrical service to residential and small commercial customers
shall, prior to the commencement of service, provide the potential
customer with a written notice of the service describing the price,
terms, and conditions of the service. A notice shall include all of
the following:
(1) A clear description of the price, terms, and conditions of
service, including:
(A) The price of electricity expressed in a format that makes it
possible for residential and small commercial customers to compare
and select among similar products and services on a standard basis.
The commission shall adopt rules to implement this subdivision. The
commission shall require disclosure of the total price of electricity
on a cents-per-kilowatthour basis, including the costs of all
electric services and charges regulated by the commission. The
commission shall also require estimates of the total monthly bill for
the electric service at varying consumption levels, including the
costs of all electric services and charges regulated by the
commission. In determining these rules, the commission may consider
alternatives to the cents-per-kilowatthour disclosure if other
information would provide the customer with sufficient information to
compare among alternatives on a standard basis.
(B) Separate disclosure of all recurring and nonrecurring charges
associated with the sale of electricity.
(C) If services other than electricity are offered, an itemization
of the services and the charge or charges associated with each.
(2) An explanation of the applicability and amount of the
competition transition charge, as determined pursuant to
Sections 367 to 376, inclusive. charges.
(3) A description of the potential customer's right to rescind the
contract without fee or penalty as described in Section 395.
(4) An explanation of the customer's financial obligations, as
well as the procedures regarding past due payments, discontinuance of
service, billing disputes, and service complaints.
(5) The electric service provider's registration number, if
applicable.
(6) The right to change service providers upon written notice,
including disclosure of any fees or penalties assessed by the
supplier for early termination of a contract.
(7) A description of the availability of low-income assistance
programs for qualified customers and how customers can apply for
these programs.
(b) The commission may assist electric service providers in
developing the notice. The commission may suggest inclusion of
additional information it deems necessary for the consumer protection
purposes of this section. On at least a semiannual basis, electric
service providers shall provide the commission with a copy of the
form of notice included in standard service plans made available to
residential and small commercial customers.
(c) An electric service provider offering electric services who
declines to provide those services to a consumer shall, upon request
of the consumer, disclose to that consumer the reason for the denial
in writing within 30 days. At the time service is denied, the
electric service provider shall disclose to the consumer the right to
make this request. A consumer shall have at least 30 days from the
date service is denied to make the request.
SEC. 44. Section 395 of the Public
Utilities Code is amended to read:
395. (a) In addition to any other right to revoke an offer,
residential and small commercial customers of electrical service, as
defined in subdivision (h) (g) of
Section 331, have the right to cancel a contract for electric service
until midnight of the third business day after the day on which the
buyer signs an agreement or offer to purchase.
(b) Cancellation occurs when the buyer gives written notice of
cancellation to the seller at the address specified in the agreement
or offer.
(c) Notice of cancellation, if given by mail, is effective when
deposited in the mail properly addressed with postage prepaid.
(d) Notice of cancellation given by the buyer need not take the
particular form as provided with the contract or offer to purchase
and, however expressed, is effective if it indicates the intention of
the buyer not to be bound by the contract.
SEC. 45. Section 397 of the Public
Utilities Code is repealed.
397. (a) Notwithstanding subdivision (a) of Section 368, to
ensure the continued safe and reliable provision of electric service
during the transition to competition, and to limit the effect of fuel
price volatility in electric rates paid by California consumers, it
is in the public interest to allow an electrical corporation which is
also a gas corporation and served fewer than four million customers
as of December 20, 1995, to file with the commission a rate cap
mechanism which shall include a Fuel Price Index Mechanism requiring
limited adjustments in an electrical corporation's authorized System
Average Rate in effect on June 10, 1996, to reflect price changes in
the fuel market. The commission shall authorize an electrical
corporation to implement a rate cap mechanism which includes a Fuel
Price Index Mechanism provided the following criteria are met:
(1) The Fuel Price Index Mechanism shall be based on the Southern
California Border Index price for natural gas as published
periodically in Natural Gas Intelligence Magazine. The "Starting
Point" of the Fuel Price Index Mechanism shall be defined as the
California Border Index price as published in Natural Gas
Intelligence for January 1, 1996.
(2) The Fuel Price Index Mechanism shall include a "deadband"
defined as a price range for natural gas that is any price up to 10
percent higher, or lower, than the Starting Point.
(3) The electrical corporation shall not file for a change in its
authorized System Average Rate unless the California Border Index
price, on a 12-month, rolling average basis, is outside the deadband.
If the published California Border Index is outside of the deadband,
the electrical corporation shall increase, or decrease, its
authorized System Average Rate by an amount equal to the product of
25 percent multiplied by the percentage by which the 12-month rolling
average natural gas price is higher, or lower, than the deadband.
(4) In no case shall an electrical corporation's authorized System
Average Rate under the Fuel Price Index Mechanism exceed the average
of the authorized system average rates for the two largest
electrical corporations as of June 10, 1996.
(5) This section shall become inoperative on December 31, 2001.
SEC. 46. Section 399.2 of the Public
Utilities Code is amended to read:
399.2. (a) (1) It is the policy of this state, and the intent of
the Legislature, to reaffirm that each electrical corporation shall
continue to operate its electric distribution grid in its service
territory and shall do so in a safe, reliable, efficient, and
cost-effective manner.
(2) In furtherance of
this policy, it is the intent of the Legislature that each electrical
corporation shall continue to be responsible for operating its own
electric distribution grid including, but not limited to, owning,
controlling, operating, managing, maintaining, planning, engineering,
designing, and constructing its own electric distribution grid,
emergency response and restoration, service connections, service
turnons and turnoffs, and service inquiries relating to the operation
of its electric distribution grid, subject to the commission's
authority.
(b) In order to ensure the continued efficient use, and
cost-effective, safe, and reliable operation of the electric
distribution grid, each electrical corporation shall continue to
operate its electric distribution grid in its service
territory consistent with Section 330. territory.
(c) In carrying out the purposes of this section, each electrical
corporation shall continue to make reasonable investments in its
electric distribution grid. Each electrical corporation shall
continue to have a reasonable opportunity to fully recover from all
customers of the electrical corporation, in a manner determined by
the commission pursuant to this code, all of the following:
(1) Reasonable investments in its electric distribution grid.
(2) A reasonable return on the investments in its electric
distribution grid.
(3) Reasonable costs to operate its electric distribution grid.
(d) For purposes of this section, the term "electric distribution
grid" means those facilities owned or operated by an electrical
corporation that are not under the control of the Independent System
Operator and that are used to transmit, deliver, or furnish
electricity for light, heat, or power.
(e) Nothing in this section shall be construed to alter or to
affect any of the following:
(1) Section 216, 218, or 2827.
(2) The authority of the commission to establish and enforce
standards and tariff conditions for the interconnection of
customer-owned facilities to the electric distribution grid.
(3) The ratemaking authority of the commission under this code.
(4) The authority of the commission to establish rules governing
the extension of service to new customers.
(f) Nothing in this section shall be construed to alter or affect
any authority or lack of authority of the commission regarding the
ownership and operation of new electric generation used in whole, or
in part, for the purpose of maintaining or enhancing the reliability
of the electric distribution grid.
(g) Nothing in this section diminishes or expands any existing
authority of a local governmental entity.
(h) The commission shall require every electrical corporation
operating an electric distribution grid to inform all customers who
request residential service connections via telephone of the
availability of the California Alternative Rates for Energy (CARE)
program and how they may qualify for and obtain these services and
shall accept applications for the CARE program according to
procedures specified by the commission. Electrical corporations shall
recover the reasonable costs of implementing this subdivision.
SEC. 47. Article 5.5 (commencing with Section 840)
of Chapter 4 of Part 1 of Division 1 of the Public
Utilities Code is repealed.
SEC. 48. Section 2827 of the Public
Utilities Code is amended to read:
2827. (a) The Legislature finds and declares that a program to
provide net energy metering combined with net surplus compensation,
co-energy metering, and wind energy co-metering for eligible
customer-generators is one way to encourage substantial private
investment in renewable energy resources, stimulate in-state economic
growth, reduce demand for electricity during peak consumption
periods, help stabilize California's energy supply infrastructure,
enhance the continued diversification of California's energy resource
mix, reduce interconnection and administrative costs for electricity
suppliers, and encourage conservation and efficiency.
(b) As used in this section, the following terms have the
following meanings:
(1) "Co-energy metering" means a program that is the same in all
other respects as a net energy metering program, except that the
local publicly owned electric utility has elected to apply a
generation-to-generation energy and time-of-use credit formula as
provided in subdivision (i).
(2) "Electrical cooperative" means an electrical cooperative as
defined in Section 2776.
(3) "Electric utility" means an electrical corporation, a local
publicly owned electric utility, or an electrical cooperative, or any
other entity, except an electric service provider, that offers
electrical service. This section shall not apply to a local publicly
owned electric utility that serves more than 750,000 customers and
that also conveys water to its customers.
(4) (A) "Eligible customer-generator" means a residential
customer, small commercial customer as defined in subdivision
(h) (f) of Section 331, or commercial,
industrial, or agricultural customer of an electric utility, who uses
a renewable electrical generation facility, or a combination of
those facilities, with a total capacity of not more than one
megawatt, that is located on the customer's owned, leased, or rented
premises, and is interconnected and operates in parallel with the
electrical grid, and is intended primarily to offset part or all of
the customer's own electrical requirements.
(B) (i) Notwithstanding subparagraph (A), "eligible
customer-generator" includes the Department of Corrections and
Rehabilitation using a renewable electrical generation technology, or
a combination of renewable electrical generation technologies, with
a total capacity of not more than eight megawatts, that is located on
the department's owned, leased, or rented premises, and is
interconnected and operates in parallel with the electrical grid, and
is intended primarily to offset part or all of the facility's own
electrical requirements. The amount of any wind generation exported
to the electrical grid shall not exceed 1.35 megawatt at any time.
(ii) Notwithstanding any other law, an electrical corporation
shall be afforded a prudent but necessary time, as determined by the
executive director of the commission, to study the impacts of a
request for interconnection of a renewable generator with a capacity
of greater than one megawatt under this subparagraph. If the study
reveals the need for upgrades to the transmission or distribution
system arising solely from the interconnection, the electrical
corporation shall be afforded the time necessary to complete those
upgrades before the interconnection and those costs shall be borne by
the customer-generator. Upgrade projects shall comply with
applicable state and federal requirements, including requirements of
the Federal Energy Regulatory Commission.
(5) "Large electrical corporation" means an electrical corporation
with more than 100,000 service connections in California.
(6) "Net energy metering" means measuring the difference between
the electricity supplied through the electrical grid and the
electricity generated by an eligible customer-generator and fed back
to the electrical grid over a 12-month period as described in
subdivisions (c) and (h).
(7) "Net surplus customer-generator" means an eligible
customer-generator that generates more electricity during a 12-month
period than is supplied by the electric utility to the eligible
customer-generator during the same 12-month period.
(8) "Net surplus electricity" means all electricity generated by
an eligible customer-generator measured in kilowatthours over a
12-month period that exceeds the amount of electricity consumed by
that eligible customer-generator.
(9) "Net surplus electricity compensation" means a per
kilowatthour rate offered by the electric utility to the net surplus
customer-generator for net surplus electricity that is set by the
ratemaking authority pursuant to subdivision (h).
(10) "Ratemaking authority" means, for an electrical corporation,
the commission, for an electrical cooperative, its ratesetting body
selected by its shareholders or members, and for a local publicly
owned electric utility, the local elected body responsible for
setting the rates of the local publicly owned utility.
(11) "Renewable electrical generation facility" means a facility
that generates electricity from a renewable source listed in
paragraph (1) of subdivision (a) of Section 25741 of the Public
Resources Code. A small hydroelectric generation facility is not an
eligible renewable electrical generation facility if it will cause an
adverse impact on instream beneficial uses or cause a change in the
volume or timing of streamflow.
(12) "Wind energy co-metering" means any wind energy project
greater than 50 kilowatts, but not exceeding one megawatt, where the
difference between the electricity supplied through the electrical
grid and the electricity generated by an eligible customer-generator
and fed back to the electrical grid over a 12-month period is as
described in subdivision (h). Wind energy co-metering shall be
accomplished pursuant to Section 2827.8.
(c) (1) Except as provided in paragraph (4) and in Section 2827.1,
every electric utility shall develop a standard contract or tariff
providing for net energy metering, and shall make this standard
contract or tariff available to eligible customer-generators, upon
request, on a first-come-first-served basis until the time that the
total rated generating capacity used by eligible customer-generators
exceeds 5 percent of the electric utility's aggregate customer peak
demand. Net energy metering shall be accomplished using a single
meter capable of registering the flow of electricity in two
directions. An additional meter or meters to monitor the flow of
electricity in each direction may be installed with the consent of
the eligible customer-generator, at the expense of the electric
utility, and the additional metering shall be used only to provide
the information necessary to accurately bill or credit the eligible
customer-generator pursuant to subdivision (h), or to collect
generating system performance information for research purposes
relative to a renewable electrical generation facility. If the
existing electrical meter of an eligible customer-generator is not
capable of measuring the flow of electricity in two directions, the
eligible customer-generator shall be responsible for all expenses
involved in purchasing and installing a meter that is able to measure
electricity flow in two directions. If an additional meter or meters
are installed, the net energy metering calculation shall yield a
result identical to that of a single meter. An eligible
customer-generator that is receiving service other than through the
standard contract or tariff may elect to receive service through the
standard contract or tariff until the electric utility reaches the
generation limit set forth in this paragraph. Once the generation
limit is reached, only eligible customer-generators that had
previously elected to receive service pursuant to the standard
contract or tariff have a right to continue to receive service
pursuant to the standard contract or tariff. Eligibility for net
energy metering does not limit an eligible customer-generator's
eligibility for any other rebate, incentive, or credit provided by
the electric utility, or pursuant to any governmental program,
including rebates and incentives provided pursuant to the California
Solar Initiative.
(2) An electrical corporation shall include a provision in the net
energy metering contract or tariff requiring that any customer with
an existing electrical generating facility and meter who enters into
a new net energy metering contract shall provide an inspection report
to the electrical corporation, unless the electrical generating
facility and meter have been installed or inspected within the
previous three years. The inspection report shall be prepared by a
California licensed contractor who is not the owner or operator of
the facility and meter. A California licensed electrician shall
perform the inspection of the electrical portion of the facility and
meter.
(3) (A) On an annual basis, every electric utility shall make
available to the ratemaking authority information on the total rated
generating capacity used by eligible customer-generators that are
customers of that provider in the provider's service area and the net
surplus electricity purchased by the electric utility pursuant to
this section.
(B) An electric service provider operating pursuant to Section 394
shall make available to the ratemaking authority the information
required by this paragraph for each eligible customer-generator that
is their customer for each service area of an electrical corporation,
local publicly owned electrical utility, or electrical cooperative,
in which the eligible customer-generator has net energy metering.
(C) The ratemaking authority shall develop a process for making
the information required by this paragraph available to electric
utilities, and for using that information to determine when, pursuant
to paragraphs (1) and (4), an electric utility is not obligated to
provide net energy metering to additional eligible
customer-generators in its service area.
(4) (A) An electric utility that is not a large electrical
corporation is not obligated to provide net energy metering to
additional eligible customer-generators in its service area when the
combined total peak demand of all electricity used by eligible
customer-generators served by all the electric utilities in that
service area furnishing net energy metering to eligible
customer-generators exceeds 5 percent of the aggregate customer peak
demand of those electric utilities.
(B) The commission shall require every large electrical
corporation to make the standard contract or tariff available to
eligible customer-generators, continuously and without interruption,
until such times as the large electrical corporation reaches its net
energy metering program limit or July 1, 2017, whichever is earlier.
A large electrical corporation reaches its program limit when the
combined total peak demand of all electricity used by eligible
customer-generators served by all the electric utilities in the large
electrical corporation's service area furnishing net energy metering
to eligible customer-generators exceeds 5 percent of the aggregate
customer peak demand of those electric utilities. For purposes of
calculating a large electrical corporation's program limit,
"aggregate customer peak demand" means the highest sum of the
noncoincident peak demands of all of the large electrical corporation'
s customers that occurs in any calendar year. To determine the
aggregate customer peak demand, every large electrical corporation
shall use a uniform method approved by the commission. The program
limit calculated pursuant to this paragraph shall not be less than
the following:
(i) For San Diego Gas and Electric Company, when it has made 607
megawatts of nameplate generating capacity available to eligible
customer-generators.
(ii) For Southern California Edison Company, when it has made
2,240 megawatts of nameplate generating capacity available to
eligible customer-generators.
(iii) For Pacific Gas and Electric Company, when it has made 2,409
megawatts of nameplate generating capacity available to eligible
customer-generators.
(C) Every large electrical corporation shall file a monthly report
with the commission detailing the progress toward the net energy
metering program limit established in subparagraph (B). The report
shall include separate calculations on progress toward the limits
based on operating solar energy systems, cumulative numbers of
interconnection requests for net energy metering eligible systems,
and any other criteria required by the commission.
(D) Beginning July 1, 2017, or upon reaching the net metering
program limit of subparagraph (B), whichever is earlier, the
obligation of a large electrical corporation to provide service
pursuant to a standard contract or tariff shall be pursuant to
Section 2827.1 and applicable state and federal requirements.
(d) Every electric utility shall make all necessary forms and
contracts for net energy metering and net surplus electricity
compensation service available for download from the Internet.
(e) (1) Every electric utility shall ensure that requests for
establishment of net energy metering and net surplus electricity
compensation are processed in a time period not exceeding that for
similarly situated customers requesting new electric service, but not
to exceed 30 working days from the date it receives a completed
application form for net energy metering service or net surplus
electricity compensation, including a signed interconnection
agreement from an eligible customer-generator and the electric
inspection clearance from the governmental authority having
jurisdiction.
(2) Every electric utility shall ensure that requests for an
interconnection agreement from an eligible customer-generator are
processed in a time period not to exceed 30 working days from the
date it receives a completed application form from the eligible
customer-generator for an interconnection agreement.
(3) If an electric utility is unable to process a request within
the allowable timeframe pursuant to paragraph (1) or (2), it shall
notify the eligible customer-generator and the ratemaking authority
of the reason for its inability to process the request and the
expected completion date.
(f) (1) If a customer participates in direct transactions pursuant
to paragraph (1) of subdivision (b) of Section 365, or Section
365.1, with an electric service provider that does not provide
distribution service for the direct transactions, the electric
utility that provides distribution service for the eligible
customer-generator is not obligated to provide net energy metering or
net surplus electricity compensation to the customer.
(2) If a customer participates in direct transactions pursuant to
paragraph (1) of subdivision (b) of Section 365 or 365.1 with an
electric service provider, and the customer is an eligible
customer-generator, the electric utility that provides distribution
service for the direct transactions may recover from the customer's
electric service provider the incremental costs of metering and
billing service related to net energy metering and net surplus
electricity compensation in an amount set by the ratemaking
authority.
(g) Except for the time-variant kilowatthour pricing portion of
any tariff adopted by the commission pursuant to paragraph (4) of
subdivision (a) of Section 2851, each net energy metering contract or
tariff shall be identical, with respect to rate structure, all
retail rate components, and any monthly charges, to the contract or
tariff to which the same customer would be assigned if the customer
did not use a renewable electrical generation facility, except that
eligible customer-generators shall not be assessed standby charges on
the electrical generating capacity or the kilowatthour production of
a renewable electrical generation facility. The charges for all
retail rate components for eligible customer-generators shall be
based exclusively on the customer-generator's net kilowatthour
consumption over a 12-month period, without regard to the eligible
customer-generator's choice as to from whom it purchases electricity
that is not self-generated. Any new or additional demand charge,
standby charge, customer charge, minimum monthly charge,
interconnection charge, or any other charge that would increase an
eligible customer-generator's costs beyond those of other customers
who are not eligible customer-generators in the rate class to which
the eligible customer-generator would otherwise be assigned if the
customer did not own, lease, rent, or otherwise operate a renewable
electrical generation facility is contrary to the intent of this
section, and shall not form a part of net energy metering contracts
or tariffs.
(h) For eligible customer-generators, the net energy metering
calculation shall be made by measuring the difference between the
electricity supplied to the eligible customer-generator and the
electricity generated by the eligible customer-generator and fed back
to the electrical grid over a 12-month period. The following rules
shall apply to the annualized net metering calculation:
(1) The eligible residential or small commercial
customer-generator, at the end of each 12-month period following the
date of final interconnection of the eligible customer-generator's
system with an electric utility, and at each anniversary date
thereafter, shall be billed for electricity used during that 12-month
period. The electric utility shall determine if the eligible
residential or small commercial customer-generator was a net consumer
or a net surplus customer-generator during that period.
(2) At the end of each 12-month period, where the electricity
supplied during the period by the electric utility exceeds the
electricity generated by the eligible residential or small commercial
customer-generator during that same period, the eligible residential
or small commercial customer-generator is a net electricity consumer
and the electric utility shall be owed compensation for the eligible
customer-generator's net kilowatthour consumption over that 12-month
period. The compensation owed for the eligible residential or small
commercial customer-generator's consumption shall be calculated as
follows:
(A) For all eligible customer-generators taking service under
contracts or tariffs employing "baseline" and "over baseline" rates,
any net monthly consumption of electricity shall be calculated
according to the terms of the contract or tariff to which the same
customer would be assigned to, or be eligible for, if the customer
was not an eligible customer-generator. If those same
customer-generators are net generators over a billing period, the net
kilowatthours generated shall be valued at the same price per
kilowatthour as the electric utility would charge for the baseline
quantity of electricity during that billing period, and if the number
of kilowatthours generated exceeds the baseline quantity, the excess
shall be valued at the same price per kilowatthour as the electric
utility would charge for electricity over the baseline quantity
during that billing period.
(B) For all eligible customer-generators taking service under
contracts or tariffs employing time-of-use rates, any net monthly
consumption of electricity shall be calculated according to the terms
of the contract or tariff to which the same customer would be
assigned, or be eligible for, if the customer was not an eligible
customer-generator. When those same customer-generators are net
generators during any discrete time-of-use period, the net
kilowatthours produced shall be valued at the same price per
kilowatthour as the electric utility would charge for retail
kilowatthour sales during that same time-of-use period. If the
eligible customer-generator's time-of-use electrical meter is unable
to measure the flow of electricity in two directions, paragraph (1)
of subdivision (c) shall apply.
(C) For all eligible residential and small commercial
customer-generators and for each billing period, the net balance of
moneys owed to the electric utility for net consumption of
electricity or credits owed to the eligible customer-generator for
net generation of electricity shall be carried forward as a monetary
value until the end of each 12-month period. For all eligible
commercial, industrial, and agricultural customer-generators, the net
balance of moneys owed shall be paid in accordance with the electric
utility's normal billing cycle, except that if the eligible
commercial, industrial, or agricultural customer-generator is a net
electricity producer over a normal billing cycle, any excess
kilowatthours generated during the billing cycle shall be carried
over to the following billing period as a monetary value, calculated
according to the procedures set forth in this section, and appear as
a credit on the eligible commercial, industrial, or agricultural
customer-generator's account, until the end of the annual period when
paragraph (3) shall apply.
(3) At the end of each 12-month period, where the electricity
generated by the eligible customer-generator during the 12-month
period exceeds the electricity supplied by the electric utility
during that same period, the eligible customer-generator is a net
surplus customer-generator and the electric utility, upon an
affirmative election by the net surplus customer-generator, shall
either (A) provide net surplus electricity compensation for any net
surplus electricity generated during the prior 12-month period, or
(B) allow the net surplus customer-generator to apply the net surplus
electricity as a credit for kilowatthours subsequently supplied by
the electric utility to the net surplus customer-generator. For an
eligible customer-generator that does not affirmatively elect to
receive service pursuant to net surplus electricity compensation, the
electric utility shall retain any excess kilowatthours generated
during the prior 12-month period. The eligible customer-generator not
affirmatively electing to receive service pursuant to net surplus
electricity compensation shall not be owed any compensation for the
net surplus electricity unless the electric utility enters into a
purchase agreement with the eligible customer-generator for those
excess kilowatthours. Every electric utility shall provide notice to
eligible customer-generators that they are eligible to receive net
surplus electricity compensation for net surplus electricity, that
they must elect to receive net surplus electricity compensation, and
that the 12-month period commences when the electric utility receives
the eligible customer-generator's election. For an electric utility
that is an electrical corporation or electrical cooperative, the
commission may adopt requirements for providing notice and the manner
by which eligible customer-generators may elect to receive net
surplus electricity compensation.
(4) (A) An eligible customer-generator with multiple meters may
elect to aggregate the electrical load of the meters located on the
property where the renewable electrical generation facility is
located and on all property adjacent or contiguous to the property on
which the renewable electrical generation facility is located, if
those properties are solely owned, leased, or rented by the eligible
customer-generator. If the eligible customer-
generator elects to aggregate the electric load
pursuant to this paragraph, the electric utility shall use the
aggregated load for the purpose of determining whether an eligible
customer-generator is a net consumer or a net surplus
customer-generator during a 12-month period.
(B) If an eligible customer-generator chooses to aggregate
pursuant to subparagraph (A), the eligible customer-generator shall
be permanently ineligible to receive net surplus electricity
compensation, and the electric utility shall retain any kilowatthours
in excess of the eligible customer-generator's aggregated electrical
load generated during the 12-month period.
(C) If an eligible customer-generator with multiple meters elects
to aggregate the electrical load of those meters pursuant to
subparagraph (A), and different rate schedules are applicable to
service at any of those meters, the electricity generated by the
renewable electrical generation facility shall be allocated to each
of the meters in proportion to the electrical load served by those
meters. For example, if the eligible customer-generator receives
electric service through three meters, two meters being at an
agricultural rate that each provide service to 25 percent of the
customer's total load, and a third meter, at a commercial rate, that
provides service to 50 percent of the customer's total load, then 50
percent of the electrical generation of the eligible renewable
generation facility shall be allocated to the third meter that
provides service at the commercial rate and 25 percent of the
generation shall be allocated to each of the two meters providing
service at the agricultural rate. This proportionate allocation shall
be computed each billing period.
(D) This paragraph shall not become operative for an electrical
corporation unless the commission determines that allowing eligible
customer-generators to aggregate their load from multiple meters will
not result in an increase in the expected revenue obligations of
customers who are not eligible customer-generators. The commission
shall make this determination by September 30, 2013. In making this
determination, the commission shall determine if there are any public
purpose or other noncommodity charges that the eligible
customer-generators would pay pursuant to the net energy metering
program as it exists prior to aggregation, that the eligible
customer-generator would not pay if permitted to aggregate the
electrical load of multiple meters pursuant to this paragraph.
(E) A local publicly owned electric utility or electrical
cooperative shall only allow eligible customer-generators to
aggregate their load if the utility's ratemaking authority determines
that allowing eligible customer-generators to aggregate their load
from multiple meters will not result in an increase in the expected
revenue obligations of customers that are not eligible
customer-generators. The ratemaking authority of a local publicly
owned electric utility or electrical cooperative shall make this
determination within 180 days of the first request made by an
eligible customer-generator to aggregate their load. In making the
determination, the ratemaking authority shall determine if there are
any public purpose or other noncommodity charges that the eligible
customer-generator would pay pursuant to the net energy metering or
co-energy metering program of the utility as it exists prior to
aggregation, that the eligible customer-generator would not pay if
permitted to aggregate the electrical load of multiple meters
pursuant to this paragraph. If the ratemaking authority determines
that load aggregation will not cause an incremental rate impact on
the utility's customers that are not eligible customer-generators,
the local publicly owned electric utility or electrical cooperative
shall permit an eligible customer-generator to elect to aggregate the
electrical load of multiple meters pursuant to this paragraph. The
ratemaking authority may reconsider any determination made pursuant
to this subparagraph in a subsequent public proceeding.
(F) For purposes of this paragraph, parcels that are divided by a
street, highway, or public thoroughfare are considered contiguous,
provided they are otherwise contiguous and under the same ownership.
(G) An eligible customer-generator may only elect to aggregate the
electrical load of multiple meters if the renewable electrical
generation facility, or a combination of those facilities, has a
total generating capacity of not more than one megawatt.
(H) Notwithstanding subdivision (g), an eligible
customer-generator electing to aggregate the electrical load of
multiple meters pursuant to this subdivision shall remit service
charges for the cost of providing billing services to the electric
utility that provides service to the meters.
(5) (A) The ratemaking authority shall establish a net surplus
electricity compensation valuation to compensate the net surplus
customer-generator for the value of net surplus electricity generated
by the net surplus customer-generator. The commission shall
establish the valuation in a ratemaking proceeding. The ratemaking
authority for a local publicly owned electric utility shall establish
the valuation in a public proceeding. The net surplus electricity
compensation valuation shall be established so as to provide the net
surplus customer-generator just and reasonable compensation for the
value of net surplus electricity, while leaving other ratepayers
unaffected. The ratemaking authority shall determine whether the
compensation will include, where appropriate justification exists,
either or both of the following components:
(i) The value of the electricity itself.
(ii) The value of the renewable attributes of the electricity.
(B) In establishing the rate pursuant to subparagraph (A), the
ratemaking authority shall ensure that the rate does not result in a
shifting of costs between eligible customer-generators and other
bundled service customers.
(6) (A) Upon adoption of the net surplus electricity compensation
rate by the ratemaking authority, any renewable energy credit, as
defined in Section 399.12, for net surplus electricity purchased by
the electric utility shall belong to the electric utility. Any
renewable energy credit associated with electricity generated by the
eligible customer-generator that is utilized by the eligible
customer-generator shall remain the property of the eligible
customer-generator.
(B) Upon adoption of the net surplus electricity compensation rate
by the ratemaking authority, the net surplus electricity purchased
by the electric utility shall count toward the electric utility's
renewables portfolio standard annual procurement targets for the
purposes of paragraph (1) of subdivision (b) of Section 399.15, or
for a local publicly owned electric utility, the renewables portfolio
standard annual procurement targets established pursuant to Section
399.30.
(7) The electric utility shall provide every eligible residential
or small commercial customer-generator with net electricity
consumption and net surplus electricity generation information with
each regular bill. That information shall include the current
monetary balance owed the electric utility for net electricity
consumed, or the net surplus electricity generated, since the last
12-month period ended. Notwithstanding this subdivision, an electric
utility shall permit that customer to pay monthly for net energy
consumed.
(8) If an eligible residential or small commercial
customer-generator terminates the customer relationship with the
electric utility, the electric utility shall reconcile the eligible
customer-generator's consumption and production of electricity during
any part of a 12-month period following the last reconciliation,
according to the requirements set forth in this subdivision, except
that those requirements shall apply only to the months since the most
recent 12-month bill.
(9) If an electric service provider or electric utility providing
net energy metering to a residential or small commercial
customer-generator ceases providing that electric service to that
customer during any 12-month period, and the customer-generator
enters into a new net energy metering contract or tariff with a new
electric service provider or electric utility, the 12-month period,
with respect to that new electric service provider or electric
utility, shall commence on the date on which the new electric service
provider or electric utility first supplies electric service to the
customer-generator.
(i) Notwithstanding any other provisions of this section,
paragraphs (1), (2), and (3) shall apply to an eligible
customer-generator with a capacity of more than 10 kilowatts, but not
exceeding one megawatt, that receives electric service from a local
publicly owned electric utility that has elected to utilize a
co-energy metering program unless the local publicly owned electric
utility chooses to provide service for eligible customer-generators
with a capacity of more than 10 kilowatts in accordance with
subdivisions (g) and (h):
(1) The eligible customer-generator shall be required to utilize a
meter, or multiple meters, capable of separately measuring
electricity flow in both directions. All meters shall provide
time-of-use measurements of electricity flow, and the customer shall
take service on a time-of-use rate schedule. If the existing meter of
the eligible customer-generator is not a time-of-use meter or is not
capable of measuring total flow of electricity in both directions,
the eligible customer-generator shall be responsible for all expenses
involved in purchasing and installing a meter that is both
time-of-use and able to measure total electricity flow in both
directions. This subdivision shall not restrict the ability of an
eligible customer-generator to utilize any economic incentives
provided by a governmental agency or an electric utility to reduce
its costs for purchasing and installing a time-of-use meter.
(2) The consumption of electricity from the local publicly owned
electric utility shall result in a cost to the eligible
customer-generator to be priced in accordance with the standard rate
charged to the eligible customer-generator in accordance with the
rate structure to which the customer would be assigned if the
customer did not use a renewable electrical generation facility. The
generation of electricity provided to the local publicly owned
electric utility shall result in a credit to the eligible
customer-generator and shall be priced in accordance with the
generation component, established under the applicable structure to
which the customer would be assigned if the customer did not use a
renewable electrical generation facility.
(3) All costs and credits shall be shown on the eligible
customer-generator's bill for each billing period. In any months in
which the eligible customer-generator has been a net consumer of
electricity calculated on the basis of value determined pursuant to
paragraph (2), the customer-generator shall owe to the local publicly
owned electric utility the balance of electricity costs and credits
during that billing period. In any billing period in which the
eligible customer-generator has been a net producer of electricity
calculated on the basis of value determined pursuant to paragraph
(2), the local publicly owned electric utility shall owe to the
eligible customer-generator the balance of electricity costs and
credits during that billing period. Any net credit to the eligible
customer-generator of electricity costs may be carried forward to
subsequent billing periods, provided that a local publicly owned
electric utility may choose to carry the credit over as a
kilowatthour credit consistent with the provisions of any applicable
contract or tariff, including any differences attributable to the
time of generation of the electricity. At the end of each 12-month
period, the local publicly owned electric utility may reduce any net
credit due to the eligible customer-generator to zero.
(j) A renewable electrical generation facility used by an eligible
customer-generator shall meet all applicable safety and performance
standards established by the National Electrical Code, the Institute
of Electrical and Electronics Engineers, and accredited testing
laboratories, including Underwriters Laboratories Incorporated and,
where applicable, rules of the commission regarding safety and
reliability. A customer-generator whose renewable electrical
generation facility meets those standards and rules shall not be
required to install additional controls, perform or pay for
additional tests, or purchase additional liability insurance.
(k) If the commission determines that there are cost or revenue
obligations for an electrical corporation that may not be recovered
from customer-generators acting pursuant to this section, those
obligations shall remain within the customer class from which any
shortfall occurred and shall not be shifted to any other customer
class. Net energy metering and co-energy metering customers shall not
be exempt from the public goods charges imposed pursuant to Article
7 (commencing with Section 381), Article 8 (commencing with Section
385), or Article 15 (commencing with Section 399) of Chapter 2.3 of
Part 1.
(l) A net energy metering, co-energy metering, or wind energy
co-metering customer shall reimburse the Department of Water
Resources for all charges that would otherwise be imposed on the
customer by the commission to recover bond-related costs pursuant to
an agreement between the commission and the Department of Water
Resources pursuant to Section 80110 of the Water Code, as well as the
costs of the department equal to the share of the department's
estimated net unavoidable power purchase contract costs attributable
to the customer. The commission shall incorporate the determination
into an existing proceeding before the commission, and shall ensure
that the charges are nonbypassable. Until the commission has made a
determination regarding the nonbypassable charges, net energy
metering, co-energy metering, and wind energy co-metering shall
continue under the same rules, procedures, terms, and conditions as
were applicable on December 31, 2002.
(m) In implementing the requirements of subdivisions (k) and (
l ), an eligible customer-generator shall not be required
to replace its existing meter except as set forth in paragraph (1) of
subdivision (c), nor shall the electric utility require additional
measurement of usage beyond that which is necessary for customers in
the same rate class as the eligible customer-generator.
(n) It is the intent of the Legislature that the Treasurer
incorporate net energy metering, including net surplus electricity
compensation, co-energy metering, and wind energy co-metering
projects undertaken pursuant to this section as sustainable building
methods or distributive energy technologies for purposes of
evaluating low-income housing projects.
SEC. 49. Section 9600 of the Public
Utilities Code is amended to read:
9600. (a) It is the intent of the Legislature that California's
local publicly owned electric utilities and electric corporations
should commit control of their transmission facilities to the
Independent System Operator as described in Chapter 2.3 (commencing
with Section 330) of Part 1 of Division 1. These utilities should
jointly advocate to the Federal Energy Regulatory Commission a
pricing methodology for the Independent System Operator that results
in an equitable return on capital investment in transmission
facilities for all Independent System Operator participants and is
based on the following principles:
(1) Utility specific access charge rates as proposed in Docket No.
EC96-19-000 as finally approved by the Federal Energy Regulatory
Commission reflecting the costs of that utility's transmission
facilities shall go into effect on the first day of the Independent
System Operator operation. The utility specific rates shall honor all
of the terms and conditions of existing transmission service
contracts and shall recognize any wheeling revenues of existing
transmission service arrangements to the transmission owner.
(2) (A) No later than two years after the initial operation of the
Independent System Operator, the Independent System Operator shall
recommend for adoption by the Federal Energy Regulatory Commission a
rate methodology determined by a decision of the Independent System
Operator governing board, provided that the decision shall be based
on principles approved by the governing board including, but not
limited to, an equitable balance of costs and benefits, and shall
define the transmission facility costs, if any, which shall be rolled
in to the transmission service rate and spread equally among all
Independent System Operator transmission users, and those
transmission facility costs, if any, which should be specifically
assigned to a specific utility's service area.
(B) If there is no governing board decision, the rate methodology
shall be determined following a decision by the alternative dispute
resolution method set forth in the Independent System Operator
bylaws.
(C) If no alternative dispute resolution decision is rendered,
then a default rate methodology shall be a uniform regional
transmission access charge and a utility specific local transmission
access charge, provided that the default rate methodology shall be
recommended for implementation upon termination of the cost recovery
plan set forth in Section 368 or no later than two
years after the initial operation of the Independent System
Operator, whichever is later. For purposes of this paragraph,
regional transmission facilities are defined to be transmission
facilities operating at or above 230 kilovolts plus an appropriate
percentage of transmission facilities operating below 230 kilovolts;
all other transmission facilities shall be considered local. The
appropriate percentage of transmission facilities described above
shall be consistent with the guidelines in Federal Energy Regulatory
Commission Order No. 888 and any exception approved by that
commission.
(3) If the rate methodology implemented as a result of a decision
by the Independent System Operator governing board or resulting from
the independent system operator Independent
System Operator alternative dispute resolution process results
in rates different than those in effect prior to the decision for any
transmission facility owner, the amount of any differences between
the new rates and the prior rates shall be recorded in a tracking
account to be recovered from customers and paid to the appropriate
transmission owners by the transmission facility owner after
termination of the cost recovery plan set forth in Section 368. The
recovery and payments shall be based on an amortization period not to
exceed three years in the case of the electrical corporations or
five years in the case of the local publicly owned electric
utilities.
(4) The costs of transmission facilities placed in service after
the date of initial implementation of the Independent System Operator
shall be recovered using the rate methodology in effect at the time
the facilities go into operation.
(5) The electrical corporations and the local publicly owned
electric utilities shall jointly develop language for implementation
proposals to the Federal Energy Regulatory Commission based on these
principles.
(6) Nothing in this section shall compel any party to violate
restrictions applicable to facilities financed with tax-exempt bonds
or contractual restrictions and covenants regarding use of
transmission facilities existing as of December 20, 1995.
(b) Following a final Federal Energy Regulatory Commission
decision approving the Independent System Operator, no California
electrical corporation or local publicly owned electric utility shall
be authorized to collect any competition transition charge
authorized pursuant to this division and Chapter 2.3 (commencing with
Section 330) of Part 1 of Division 1 unless it commits control of
its transmission facilities to the Independent System Operator.
SEC. 50. Section 9607 of the Public
Utilities Code is amended to read:
9607. (a) The intent of this section is to avoid cost-shifting to
customers of an electrical corporation resulting from the transfer
of distribution services from an electrical corporation to an
irrigation district.
(b) Except as otherwise provided in this section and Section 9608,
and notwithstanding any other provision of law, an irrigation
district that offered electric service to retail customers as of
January 1, 1999, may not construct, lease, acquire, install, or
operate facilities for the distribution or transmission of
electricity to retail customers located in the service territory of
an electrical corporation providing electric distribution services,
unless the district has first applied for and received the approval
of the commission and implements its service consistent with the
commission's order. The commission shall find that service to be in
the public interest and shall approve the request of a district to
provide distribution or transmission of electricity to retail
customers located in the service territory of an electrical
corporation providing electric distribution service if, after notice
and hearing, the commission determines all of the following:
(1) The district will provide universal service to all retail
customers who request service within the area to be served, at
published tariff rates and on a just, reasonable, and
nondiscriminatory basis, comparable to that provided by the current
retail service provider.
(2) If the area the district is proposing to serve is either of
the following:
(A) Is within the district's boundaries but less than the entire
district, the area to be served includes a percentage of residential
customers and small customers, based on load, comparable to the
percentage of residential and small customers in the district, based
on load.
(B) Includes territory outside the district's boundaries, in which
case the territory outside the district's boundaries must include a
percentage of residential customers and small customers, based on
load, comparable to the percentage of residential and small customers
in the county or counties where service is to be provided, based on
load.
(3) Service by the district will be consistent with the intent of
the state to avoid economic waste caused by duplication of facilities
as set forth in Section 8101.
(4) Service by the district will include reasonable mitigation of
any adverse effects on the reliability of an existing service by the
electrical corporation.
(5) The district has established, funded, and is carrying out
public purpose and low-income programs comparable to those provided
by the current electric retail service provider.
(6) That district's tariffed electric rates, exclusive of
commodity costs, will be at least 15 percent below the tariffed
electric rates, exclusive of commodity costs and
nonbypassable charges under Sections 367, 368, 375, 376, and 379,
competition transition charges of the electrical
corporation for comparable services.
(7) Service by the district is in the public interest.
(c) An irrigation district that obtains the approval of the
commission under this section to serve an area shall prepare an
annual report available to the public on the total load and number of
accounts of residential, low-income, agricultural, commercial, and
industrial customers served by the irrigation district in the
approved service area.
(d) The commission shall have jurisdiction to resolve and
adjudicate complaint cases brought against an irrigation district
that offered electric service to retail customers as of January 1,
1999, by an interested party where the complaint concerns retail
electric service outside the boundaries of the district and within
the service territory of an electrical corporation. Nothing in this
section grants the commission jurisdiction to adjudicate complaint
cases involving retail electric service by an irrigation district
inside its boundaries or inside an irrigation district's exclusive
service territory.
(e) Any project involving electric transmission or distribution
facilities to be constructed or installed by an irrigation district
to serve retail customers located in the service territory of an
electrical corporation providing electric distribution services shall
comply with the California Environmental Quality Act,
Act (Division 13 (commencing with Section
21000)) of the Public Resources Code. The county in which the
construction or installation is to occur shall act as the lead
agency. If a project involves the construction or installation of
electric transmission or distribution facilities in more than one
county, the county where the majority of the construction is
anticipated to occur shall act as the lead agency.
(f) An irrigation district may not offer service to customers
outside of its district boundaries before offering service to all
customers within its district boundaries.
(g) This section does not apply to electric distribution service
provided by Modesto Irrigation District to those customers or within
those areas described in subdivisions (a), (b), and (c) of Section
9610.
(h) The provisions of this section shall not apply to (1) a
cumulative 90 megawatts of load served by the Merced Irrigation
District that is located within the boundaries of Merced Irrigation
District, as those boundaries existed on December 20, 1995, together
with the territory of Castle Air Force Base which was located outside
the District district on that date, or
(2) electric load served by the District
district which was not previously served by an
electric corporation that is located within the boundaries of Merced
Irrigation District, as those boundaries existed on December 20,
1995, together with the territory of Castle Air Force Base which was
located outside the District district
on that date.
(i) For purposes of this section, a megawatt of load shall be
calculated in accordance with the methodology established by the
California Energy Resource Conservation and Development
Energy Commission in its Docket No. 96-IRR-1890,
but the 90 megawatts shall not include electrical usage by customers
that move to the areas described in paragraph (1) after December 31,
2000.
(j) Subdivision (a) of this section shall not apply to the
construction, modification, lease, acquisition, installation, or
operation of facilities for the distribution or transmission of
electricity to customers
electrically connected to a district as of December 31, 2000,
or to other customers who subsequently locate at the same premises.
(k) In recognition of contractual arrangements and settlements
existing as of June 1, 2000, this section does not apply to the
acquisition or operation of the electric distribution facilities that
are the subject of the Settlement Agreement dated May 1, 2000,
between Pacific Gas and Electric Company and the San Joaquin
Irrigation District.
( l ) For purposes of this section, retail customers do
not include an irrigation district's own electric load being served
of retail by an electrical corporation.
SEC. 51. Section 31071.5 of the Streets
and Highways Code is amended to read:
31071.5. (a) Bonds issued under this chapter may not be deemed to
constitute a debt or liability of the state or of any political
subdivision thereof, other than the bank, or a pledge of the faith
and credit of the state or of any political subdivision thereof, but
shall be payable solely from the account, and the assets of the
account, and the security provided by the account. All bonds issued
under this chapter shall contain on the face of the bonds a statement
to this effect.
(b) Notwithstanding any other provision of law, Article 3
(commencing with Section 63040) of, Article 4 (commencing
with 63042) of, 63040) and Article 5 (commencing
with Section 63043) of Chapter 2 of Division 1 of Title 6.7 of the
Government Code do not apply to any financing provided by the bank
to, or at the request of, the department in connection with the
account.
SECTION 1. Section 30009 is added to the Penal
Code, to read:
30009. (a) In order to reduce the number of firearms possessed by
prohibited persons listed in the Prohibited Armed Persons File, a
30-day amnesty period shall be established, commencing on a date to
be determined by the Department of Justice but not later than January
1, 2015, during which a person prohibited from possessing a firearm
may surrender his or her firearms to a local law enforcement agency
without being charged with illegal possession of firearms, as
provided in subdivision (e). No person convicted of a felony shall be
permitted to participate in the amnesty period.
(b) The department shall provide written notification of the
amnesty period to all prohibited persons eligible to participate in
the amnesty period by first-class mail no later than 60 calendar days
prior to the commencement of the amnesty period. The notification
shall specify the firearms possessed by the prohibited person and
provide instructions for the surrender of the illegal firearms.
(c) For each instance in which a local law enforcement agency
receives a firearm from a prohibited person during the amnesty period
described in subdivision (a), the agency shall submit to the
department the following information:
(1) The name of the prohibited person who surrendered the firearm.
(2) The person's date of birth.
(3) A description of the firearm or firearms surrendered.
(4) The serial number of the firearm or firearms surrendered.
(5) Any other information deemed necessary by the department.
(d) The department shall enter the information received pursuant
to subdivision (c) in the Prohibited Armed Persons File to create a
record of each firearm surrendered during the amnesty period.
(e) A prohibited person who surrenders a firearm pursuant to
subdivision (a) shall not be charged with illegal possession of
firearms for any firearm the department has on record as having been
surrendered pursuant to subdivision (d).
(f) At the expiration of the 30-day amnesty period described in
subdivision (a), a person prohibited from possessing a firearm and
eligible to participate in the amnesty program who still maintains
possession of his or her firearms shall be subject to a civil fine of
up to two thousand five hundred dollars ($2,500) per firearm in
addition to any criminal penalties authorized by law, including, but
not limited to, penalties described in Chapter 3 (commencing with
Section 29900) of this code and Sections 8100 and 8103 of the Welfare
and Institutions Code.
(g) A prohibited person shall not to be charged with illegal
possession of a firearm, nor be subject to the fine described in
subdivision (f), if he or she provides evidence satisfactory to the
department that he or she lawfully surrendered his or her firearm
prior to the commencement of the amnesty period.
(h) Any firearms surrendered to a local law enforcement agency
pursuant to this section shall be sold or destroyed as provided in
Section 18005.
(i) Sections 26500 and 27545, and subdivision (a) of Section
31615, shall not apply to the surrender of firearms to a local law
enforcement agency pursuant to this section.
SEC. 2. If the Commission on State Mandates
determines that this act contains costs mandated by the state,
reimbursement to local agencies and school districts for those costs
shall be made pursuant to Part 7 (commencing with Section 17500) of
Division 4 of Title 2 of the Government Code.