2007 California Public Utilities Code Article 6. Requirements For The Public Utilities Commission

CA Codes (puc:360-380)

360.  The commission shall ensure that existing, and if necessary,
additional filings at the Federal Energy Regulatory Commission
request confirmation of the relevant provisions of this chapter and
seek the authority needed to give the Independent System Operator the
ability to secure generating and transmission resources necessary to
guarantee achievement of planning and operating reserve criteria no
less stringent than those established by the Western Electricity
Coordinating Council and the North American Electric Reliability
Council.


360.5.  The commission shall determine that portion of each existing
electrical corporation's retail rate effective on January 5, 2001,
that is equal to the difference between the generation related
component of the retail rate and the sum of the costs of the utility'
s own generation, qualifying facility contracts, existing bilateral
contracts, and ancillary services.  That portion of the retail rate
shall be known as the California Procurement Adjustment.  The
commission shall further determine the amount of the California
Procurement Adjustment that is allocable to the power sold by the
department.  That amount shall be payable, by each electrical
corporation, upon receipt by the electrical corporation of the
revenues from its retail end use customers, to the department for
deposit in the Department of Water Resources Electric Power Fund,
established by Section 80200 of the Water Code.  The amount
determined pursuant to this subdivision shall be known as the Fixed
Department of Water Resources Set-Aside.



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.



362.  (a) In proceedings pursuant to Section 455.5, 851, or 854, the
commission shall ensure that facilities needed to maintain the
reliability of the electric supply remain available and operational,
consistent with maintaining open competition and avoiding an
overconcentration of market power.  In order to determine whether the
facility needs to remain available and operational, the commission
shall utilize standards that are no less stringent than the Western
Electricity Coordinating Council and North American Electric
Reliability Council standards for planning reserve criteria.
   (b) The commission shall require that generation facilities
located in the state that have been disposed of in proceedings
pursuant to Section 851 are operated by the persons or corporations
who own or control them in a manner that ensures their availability
to maintain the reliability of the electric supply system.



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.



364.  (a) The commission shall adopt inspection, maintenance,
repair, and replacement standards for the distribution systems of
investor-owned electric utilities no later than March 31, 1997.  The
standards, which shall be performance or prescriptive standards, or
both, as appropriate, for each substantial type of distribution
equipment or facility, shall provide for high quality, safe and
reliable service.
   (b) In setting its standards, the commission shall consider:
cost, local geography and weather, applicable codes, national
electric industry practices, sound engineering judgment, and
experience.  The commission shall also adopt standards for operation,
reliability, and safety during periods of emergency and disaster.
The commission shall require each utility to report annually on its
compliance with the standards.  That report shall be made available
to the public.
   (c) The commission shall conduct a review to determine whether the
standards prescribed in this section have been met.  If the
commission finds that the standards have not been met, the commission
may order appropriate sanctions, including penalties in the form of
rate reductions or monetary fines.  The review shall be performed
after every major outage.  Any money collected pursuant to this
subdivision shall be used to offset funding for the California
Alternative Rates for Energy Program.



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, for
the determination of which transmission and distribution facilities
are subject to the exclusive jurisdiction of the commission, and for
approval, to the extent necessary, of the cost recovery mechanism
established as provided in Sections 367 to 376, inclusive.  The
commission shall also participate fully in all proceedings before the
Federal Energy Regulatory Commission in connection with the
Independent System Operator and 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.
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.



365.5.  Nothing in this chapter shall prevent the commission from
exercising its authority to investigate a process for certification
and regulation of the rates, charges, terms, and conditions of
default service.  If the commission determines that a process for
certification and regulation of default service is in the public
interest, the commission shall submit its findings and
recommendations to the Legislature for approval.



366.  (a) The commission shall take actions as needed to facilitate
direct transactions between electricity suppliers and end-use
customers. Customers shall be entitled to aggregate their  electrical
loads on a voluntary basis, provided that each customer does so by a
positive written declaration.  If no positive declaration is made by
a customer, that customer shall continue to be served by the
existing electrical corporation or its successor in interest, except
aggregation by community choice aggregators, accomplished pursuant to
Section 366.2.
   (b) Aggregation of customer electrical load shall be authorized by
the commission for all customer classes, including, but not limited,
to small commercial or residential customers.  Aggregation may be
accomplished by private market aggregators, special districts, or on
any other basis made available by market opportunities and agreeable
by positive written declaration by individual consumers, except
aggregation by community choice aggregators, which shall be
accomplished pursuant to Section 366.2.



366.1.  (a) As used in this section, the following terms have the
following meanings:
   (1) "Department" means the Department of Water Resources with
respect to its power program described in Chapter 2 (commencing with
Section 80100) of Division 27 of the Water Code.
   (2) "Existing project participant" means a city with rights and
obligations to the Magnolia Power Project under the Magnolia Power
Project Planning Agreement, dated May 1, 2001.
   (3) "Magnolia Power Project" means a proposed natural gas-fired
electric generating facility to be located at an existing site in
Burbank and for which an application for certification has been filed
with the State Energy Resources Conservation and Development Act
(Docket No. 00-SIT-1) and deemed data adequate pursuant to the
expedited six-month licensing process established under Section 25550
of the Public Resources Code.
   (b) Notwithstanding Section 80110 of the Water Code or Commission
Decision 01-09-060, if the Magnolia Power Project has been
constructed and is otherwise capable of beginning deliveries of
electricity to the existing project participants, an existing project
participant may serve as a community aggregator on behalf of all
retail end-use customers within its jurisdiction.
   (c) Subdivision (b) shall not become operative until both of the
following occur:
   (1) The commission implements a cost-recovery mechanism,
consistent with subdivision (d), that is applicable to customers that
elected to purchase electricity from an alternate provider between
February 1, 2001, and the effective date of the act adding this
section.
   (2) The commission submits a report certifying its satisfaction of
paragraph (1) to the Senate Energy, Utilities and Communications
Committee, or its successor, and the Assembly Committee on Utilities
and Commerce, or its successor.
   (d) (1) It is the intent of the Legislature that each retail
end-use customer that has purchased power from an electrical
corporation  on or after February 1, 2001, should bear a fair share
of the department's power purchase costs, as well as power purchase
contract obligations incurred as of January 1, 2003, that are
recoverable from electrical corporation customers in
commission-approved rates. It is the further intent of the
Legislature to prevent any shifting of recoverable costs between
customers.
   (2) The Legislature finds and declares that the provisions in this
subdivision are consistent with the requirements of Section 360.5
and Division 27 (commencing with Section 80000) of the Water Code,
and are therefore declaratory of existing law.
   (e) A retail end-use customer purchasing power from a community
aggregator pursuant to subdivision (b) shall reimburse the department
for all of the following:
   (1) A charge equivalent to the charge which would otherwise be
imposed on the customer by the commission to recover bond related
costs pursuant to an agreement between the commission and the
Department of Water Resources pursuant to Section 80110 of the Water
Code, that charge shall be payable until all obligations of the
Department of Water Resources pursuant to Division 27 of the Water
Code are fully paid or otherwise discharged.
   (2) The costs of the department, equal to the share of the
department's estimated net unavoidable power purchase contract costs
attributable to the customer, as determined by the commission, for
the period commencing with the customer's purchases of electricity
from a community aggregator, through the expiration of all then
existing power purchase contracts entered into by the department.
   (f) A retail end-use customer purchasing power from a community
aggregator pursuant to subdivision (b) shall reimburse the electrical
corporation that previously served the customer for all of the
following:
   (1) The electrical corporation's unrecovered past
undercollections, including all financing costs attributable to that
customer, that the commission lawfully determines may be recovered in
rates.
   (2) The costs of the electrical corporation recoverable in
commission-approved rates, equal to the share of the electrical
corporation's estimated net unavoidable power purchase contract costs
attributable to the customer, as determined by the commission, for
the period commencing with the customer's purchases of electricity
from the community aggregator, through the expiration of all then
existing power purchase contracts entered into by the electrical
corporation.
   (g) (1) A charge or cost imposed pursuant to subdivision (e), and
all revenues received to pay the charge or cost, shall be the
property of the Department of Water Resources.  A charge or cost
imposed pursuant to subdivision (f), and all revenues received to pay
the charge or cost, shall be the property of the particular
electrical corporation.  The commission shall establish mechanisms,
including agreements with, or orders with respect to, electrical
corporations necessary to assure that the revenues received to pay a
charge or cost payable pursuant to this section are promptly remitted
to the party entitled to those revenues.
   (2) A charge or cost imposed pursuant to this section shall be
nonbypassable.



366.2.  (a) (1) Customers shall be entitled to aggregate their
electric loads as members of their local community with community
choice aggregators.
   (2) Customers may aggregate their loads through a public process
with community choice aggregators, if each customer is given an
opportunity to opt out of their community's aggregation program.
   (3) If a customer opts out of a community choice aggregator's
program, or has no community choice program available, that customer
shall have the right to  continue to be served by the existing
electrical corporation or its successor in interest.
   (b) If a public agency seeks to serve as a community choice
aggregator, it shall offer the opportunity to purchase electricity to
all residential customers within its jurisdiction.
   (c) (1) Notwithstanding Section 366, a community choice aggregator
is hereby authorized to aggregate the electrical load of interested
electricity consumers within its boundaries to reduce transaction
costs to consumers, provide consumer protections, and leverage the
negotiation of contracts.  However, the community choice aggregator
may not aggregate electrical load if that load is served by a local
publicly owned electric utility, as defined in subdivision (d) of
Section 9604.  A community choice aggregator may group retail
electricity customers to solicit bids, broker, and contract for
electricity and energy services for those customers.  The community
choice aggregator may enter into agreements for services to
facilitate the sale and purchase of electricity and other related
services.  Those service agreements may be entered into by a single
city or county, a city and county, or by a group of cities, cities
and counties, or counties.
   (2) Under community choice aggregation, customer participation may
not require a positive written declaration, but all customers shall
be informed of their right to opt out of the community choice
aggregation program.  If no negative declaration is made by a
customer, that customer shall be served through the community choice
aggregation program.
   (3) A community choice aggregator establishing electrical load
aggregation pursuant to this section shall develop an implementation
plan detailing the process and consequences of aggregation.  The
implementation plan, and any subsequent changes to it, shall be
considered and adopted at a duly noticed public hearing.  The
implementation plan shall contain all of the following:
   (A) An organizational structure of the program, its operations,
and its funding.
   (B) Ratesetting and other costs to participants.
   (C) Provisions for disclosure and due process in setting rates and
allocating costs among participants.
   (D) The methods for entering and terminating agreements with other
entities.
   (E) The rights and responsibilities of program participants,
including, but not limited to, consumer protection procedures, credit
issues, and shutoff procedures.
   (F) Termination of the program.
   (G) A description of the third parties that will be supplying
electricity under the program, including, but not limited to,
information about financial, technical, and operational capabilities.

   (4) A community choice aggregator establishing electrical load
aggregation shall prepare a statement of intent with the
implementation plan.  Any community choice load aggregation
established pursuant to this section shall provide for the following:

   (A) Universal access.
   (B) Reliability.
   (C) Equitable treatment of all classes of customers.
   (D) Any requirements established by state law or by the commission
concerning aggregated service.
   (5) In order to determine the cost-recovery mechanism to be
imposed on the community choice aggregator pursuant to subdivisions
(d), (e), and (f) that shall be paid by the customers of the
community choice aggregator to prevent shifting of costs, the
community choice aggregator shall file the implementation plan with
the commission, and any other information requested by the commission
that the commission determines is necessary to develop the
cost-recovery mechanism in subdivisions (d), (e), and (f).
   (6) The commission shall notify any electrical corporation serving
the customers proposed for aggregation that an implementation plan
initiating community choice aggregation has been filed, within 10
days of the filing.
   (7) Within 90 days after the community choice aggregator
establishing load aggregation files its implementation plan, the
commission shall certify that it has received the implementation
plan, including any additional information necessary to determine a
cost-recovery mechanism.  After certification of receipt of the
implementation plan and any additional information requested, the
commission shall then provide the community choice aggregator with
its findings regarding any cost recovery that must be paid by
customers of the community choice aggregator to prevent a shifting of
costs as provided for in subdivisions (d), (e), and (f).
   (8) No entity proposing community choice aggregation shall act to
furnish electricity to electricity consumers within its boundaries
until the commission determines the cost-recovery that must be paid
by the customers of that proposed community choice aggregation
program, as provided for in subdivisions (d), (e), and (f).  The
commission shall designate the earliest possible effective date for
implementation of a community choice aggregation program, taking into
consideration the impact on any annual procurement plan of the
electrical corporation that has been approved by the commission.
   (9) All electrical corporations shall cooperate fully with any
community choice aggregators that investigate, pursue, or implement
community choice aggregation programs.  Cooperation shall include
providing the entities with appropriate billing and electrical load
data, including, but not limited to, data detailing electricity needs
and patterns of usage, as determined by the commission, and in
accordance with procedures established by the commission.  Electrical
corporations shall continue to provide all metering, billing,
collection, and customer service to retail customers that participate
in community choice aggregation programs.  Bills sent by the
electrical corporation to retail customers shall identify the
community choice aggregator as providing the electrical energy
component of the bill.  The commission shall determine the terms and
conditions under which the electrical corporation provides services
to community choice aggregators and retail customers.
   (10) (A) A city, county, or city and county that elects to
implement a community choice aggregation program within its
jurisdiction pursuant to this chapter shall do so by ordinance.
   (B) Two or more cities, counties, or cities and counties may
participate as a group in a community choice aggregation pursuant to
this chapter, through a joint powers agency established pursuant to
Chapter 5 (commencing with Section 6500) of Division 7 of Title 1 of
the Government Code, if each entity adopts an ordinance pursuant to
subparagraph (A).
   (11) Following adoption of aggregation through the ordinance
described in paragraph (10), the program shall allow any retail
customer to opt out and to continue to be served as a bundled service
customer by the existing electrical corporation, or its successor in
interest.  Delivery services shall be provided at the same rates,
terms, and conditions, as approved by the commission, for community
choice aggregation customers and customers that have entered into a
direct transaction where applicable, as determined by the commission.
  Once enrolled in the aggregated entity, any ratepayer that chooses
to opt out within 60 days or two billing cycles of the date of
enrollment may do so without penalty and shall be entitled to receive
default service pursuant to paragraph (3) of subdivision (a).
Customers that return to the electrical corporation for procurement
services shall be subject to the same terms and conditions as are
applicable to other returning direct access customers from the same
class, as determined by the commission, as authorized by the
commission pursuant to this code or any other provision of law.  Any
reentry fees to be imposed after the opt-out period specified in this
paragraph, shall be approved by the commission and shall reflect the
cost of reentry.  The commission shall exclude any amounts
previously determined and paid pursuant to subdivisions (d), (e), and
(f) from the cost of reentry.
   (12) Nothing in this section shall be construed as authorizing any
city or any community choice retail load aggregator to restrict the
ability of retail electricity customers to obtain or receive service
from any authorized electric service provider in a manner consistent
with law.
   (13) (A) The community choice aggregator shall fully inform
participating customers at least twice within two calendar months, or
60 days, in advance of the date of commencing automatic enrollment.
Notifications may occur concurrently with billing cycles.  Following
enrollment, the aggregated entity shall fully inform participating
customers for not less than two consecutive billing cycles.
Notification may include, but is not limited to, direct mailings to
customers, or inserts in water, sewer, or other utility bills.  Any
notification shall inform customers of both of the following:
   (i) That they are to be automatically enrolled and that the
customer has the right to opt out of the community choice aggregator
without penalty.
   (ii) The terms and conditions of the services offered.
   (B) The community choice aggregator may request the commission to
approve and order the electrical corporation to provide the
notification required in subparagraph (A).  If the commission orders
the electrical corporation to send one or more of the notifications
required pursuant to subparagraph (A) in the electrical corporation's
normally scheduled monthly billing process, the electrical
corporation shall be entitled to recover from the community choice
aggregator all reasonable incremental costs it incurs related to the
notification or notifications.  The electrical corporation shall
fully cooperate with the community choice aggregator in determining
the feasibility and costs associated with using the electrical
corporation's normally scheduled monthly billing process to provide
one or more of the notifications required pursuant to subparagraph
(A).
   (C) Each notification shall also include a mechanism by which a
ratepayer may opt out of community choice aggregated service.  The
opt out may take the form of a self-addressed return postcard
indicating the customer's election to remain with, or return to,
electrical energy service provided by the electrical corporation, or
another straightforward means by which the customer may elect to
derive electrical energy service through the electrical corporation
providing service in the area.
   (14) The community choice aggregator shall register with the
commission, which may require additional information to ensure
compliance with basic consumer protection rules and other procedural
matters.
   (15) Once the community choice aggregator's contract is signed,
the community choice aggregator shall notify the applicable
electrical corporation that community choice service will commence
within 30 days.
   (16) Once notified of a community choice aggregator program, the
electrical corporation shall transfer all applicable accounts to the
new supplier within a 30-day period from the date of the close of
their normally scheduled monthly metering and billing process.
   (17) An electrical corporation shall recover from the community
choice aggregator any costs reasonably attributable to the community
choice aggregator, as determined by the commission, of implementing
this section, including, but not limited to, all business and
information system changes, except for transaction-based costs as
described in this paragraph.  Any costs not reasonably attributable
to a community choice aggregator shall be recovered from ratepayers,
as determined by the commission.  All reasonable transaction-based
costs of notices, billing, metering, collections, and customer
communications or other services provided to an aggregator or its
customers shall be recovered from the aggregator or its customers on
terms and at rates to be approved by the commission.
   (18) At the request and expense of any community choice
aggregator, electrical corporations shall install, maintain and
calibrate metering devices at mutually agreeable locations within or
adjacent to the community aggregator's political boundaries.  The
electrical corporation shall read the metering devices and provide
the data collected to the community aggregator at the aggregator's
expense.  To the extent that the community aggregator requests a
metering location that would require alteration or modification of a
circuit, the electrical corporation shall only be required to alter
or modify a circuit if such alteration or modification does not
compromise the safety, reliability or operational flexibility of the
electrical corporation's facilities.  All costs incurred to modify
circuits pursuant to this paragraph, shall be born by the community
aggregator.
   (d) (1) It is the intent of the Legislature that each retail
end-use customer that has purchased power from an electrical
corporation on or after February 1, 2001, should bear a fair share of
the Department of Water Resources' electricity purchase costs, as
well as electricity purchase contract obligations incurred as of the
effective date of the act adding this section, that are recoverable
from electrical corporation customers in commission-approved rates.
It is further the intent of the Legislature to prevent any shifting
of recoverable costs between customers.
   (2) The Legislature finds and declares that this subdivision is
consistent with the requirements of Division 27 (commencing with
Section 80000) of the Water Code and Section 360.5, and is therefore
declaratory of existing law.
   (e) A retail end-use customer that purchases electricity from a
community choice aggregator pursuant to this section shall pay both
of the following:
   (1) A charge equivalent to the charges that would otherwise be
imposed on the customer by the commission to recover bond related
costs pursuant to any agreement between the commission and the
Department of Water Resources pursuant to Section 80110 of the Water
Code, which charge shall be payable until any obligations of the
Department of Water Resources pursuant to Division 27 (commencing
with Section 80000) of the Water Code are fully paid or otherwise
discharged.
   (2) Any additional costs of the Department of Water Resources,
equal to the customer's proportionate share of the Department of
Water Resources' estimated net unavoidable electricity purchase
contract costs as determined by the commission, for the period
commencing with the customer's purchases of electricity from the
community choice aggregator, through the expiration of all then
existing electricity purchase contracts entered into by the
Department of Water Resources.
   (f) A retail end-use customer purchasing electricity from a
community choice aggregator pursuant to this section shall reimburse
the electrical corporation that previously served the customer for
all of the following:
   (1) The electrical corporation's unrecovered past undercollections
for electricity purchases, including any financing costs,
attributable to that customer, that the commission lawfully
determines may be recovered in rates.
   (2) Any additional costs of the electrical corporation recoverable
in commission-approved rates, equal to the share of the electrical
corporation's estimated net unavoidable electricity purchase contract
costs attributable to the customer, as determined by the commission,
for the period commencing with the customer's purchases of
electricity from the community choice aggregator, through the
expiration of all then existing electricity purchase contracts
entered into by the electrical corporation.
   (g) (1) Any charges imposed pursuant to subdivision (e) shall be
the property of the Department of Water Resources.  Any charges
imposed pursuant to subdivision (f) shall be the property of the
electrical corporation.  The commission shall establish mechanisms,
including agreements with, or orders with respect to, electrical
corporations necessary to ensure that charges payable pursuant to
this section shall be promptly remitted to the party entitled to
payment.
   (2) Charges imposed pursuant to subdivisions (d), (e), and (f)
shall be nonbypassable.
   (h) Notwithstanding Section 80110 of the Water Code, the
commission shall authorize community choice aggregation only if the
commission imposes a cost-recovery mechanism pursuant to subdivisions
(d), (e), (f), and (g).  Except as provided by this subdivision,
this section shall not alter the suspension by the commission of
direct purchases of electricity from alternate providers other than
by community choice aggregators, pursuant to Section 80110 of the
Water Code.
   (i) (1) The commission shall not authorize community choice
aggregation until it implements a cost-recovery mechanism, consistent
with subdivisions (d), (e), and (f), that is applicable to customers
that elected to purchase electricity from an alternate provider
between February 1, 2001, and January 1, 2003.
   (2) The commission shall not authorize community choice
aggregation until it submits a report certifying compliance with
paragraph (1) to the Senate Energy, Utilities and Communications
Committee, or its successor, and the Assembly Committee on Utilities
and Commerce, or its successor.
   (3) The commission shall not authorize community choice
aggregation until it has adopted rules for implementing community
choice aggregation.
   (j) The commission shall prepare and submit to the Legislature, on
or before January 1, 2006, a report regarding the number of
community choices aggregations, the number of customers served by
community choice aggregations, third party suppliers to community
choice aggregations, compliance with this section, and the overall
effectiveness of community choice aggregation programs.



366.5.  (a) No change in the aggregator or supplier of electric
power for any small commercial customer may be made until one of the
following means of confirming the change has been completed:
   (1) Independent third-party telephone verification.
   (2) Receipt of a written confirmation received in the mail from
the consumer after the consumer has received an information package
confirming the agreement.
   (3) The customer signs a document fully explaining the nature and
effect of the change in service.
   (4) The customer's consent is obtained through electronic means,
including, but not limited to, computer transactions.
   (b) No change in the aggregator or provider of electric power for
any residential customer may be made over the telephone until the
change has been confirmed by an independent third-party verification
company, as follows:
   (1) The third-party verification company shall meet each of the
following criteria:
   (A) Be independent from the entity that seeks to provide the new
service.
   (B) Not be directly or indirectly managed, controlled, or
directed, or owned wholly or in part, by an entity that seeks to
provide the new service or by any corporation, firm, or person who
directly or indirectly manages, controls, or directs, or owns more
than 5 percent of the entity.
   (C) Operate from facilities physically separate from those of the
entity that seeks to provide the new service.
   (D) Not derive commission or compensation based upon the number of
sales confirmed.
   (2) The entity seeking to verify the sale shall do so by
connecting the resident by telephone to the third-party verification
company or by arranging for the third-party verification company to
call the customer to confirm the sale.
   (3) The third-party verification company shall obtain the customer'
s oral confirmation regarding the change, and shall record that
confirmation by obtaining appropriate verification data.  The record
shall be available to the customer upon request.  Information
obtained from the customer through confirmation shall not be used for
marketing purposes.  Any unauthorized release of this information is
grounds for a civil suit by the aggrieved resident against the
entity or its employees who are responsible for the violation.
   (4) Notwithstanding paragraphs (1), (2), and (3), an aggregator or
provider of electric power shall not be required to comply with
these provisions when the customer directly calls an aggregator or
provider of electric power to change service providers.  However, an
aggregator or provider of electric power shall not avoid the
verification requirements by asking a customer to contact an
aggregator or provider of electric power directly to make any change
in the service provider.
   (c) No change in the aggregator or provider of electric power for
any residential customer may be made via an Internet transaction, in
which the customer accesses the website of the aggregator or
provider, unless both of the following occur with respect to
confirming the change:
   (1) In addition to any other information gathered in the course of
the transaction, the customer shall be asked to read and respond to
a separate screen that states, in easily legible text, the following:

   "I acknowledge that in entering this transaction I am voluntarily
choosing to change the entity that supplies me with my electric
power."
   (2) The separate screen shall offer the customer the option to
complete or terminate the transaction.
   (d) (1) No change in the aggregator or provider of electric power
for any residential customer may be made via a written transaction
unless the change has been confirmed, as provided in this
subdivision.  In order to comply with this subdivision, in addition
to any other information gathered in the course of the transaction,
and in addition to any other signature required, the customer shall
be asked to sign and date a document separate from that written
transaction, containing the following words printed in 10-point type
or larger:
   "I acknowledge that in signing this contract or agreement, I am
voluntarily choosing to change the entity that supplies me with
electric power."
   (2) The acknowledgment document described in paragraph (1) may not
be included with a check or in connection with a sweepstakes
solicitation.
   (e) Any aggregator or provider of electric power offering
electricity service to residential and small commercial customers
that switches the electric service of a customer without the customer'
s consent shall be liable to the aggregator or provider of electric
power offering electricity services previously selected by the
customer in an amount equal to all charges paid by the customer after
the violation and shall refund to the customer any amount in excess
of the amount that the customer would have been obligated to pay had
the customer not been switched.
   (f) An aggregator or provider of electric power shall keep a
record of the confirmation of a change pursuant to subdivision (b),
(c), or (d) for two years from the date of that confirmation, and
shall make those records available, upon request, to the customer and
to the commission in the course of a commission investigation of a
customer complaint or an investigation pursuant to subdivision (c) of
Section 394.2.
   (g) Public agencies are exempt from this section to the extent
they are serving customers within their jurisdiction.
   (h) Notwithstanding subdivisions (c) and (d), the commission may
require third-party verification for all residential changes to
electric service providers if it finds that the application of
subdivisions (c) and (d) results in the unauthorized changing of a
customer's electric service provider.
   (i) An electrical corporation is exempt from this section for
customers that default to the service of the electrical corporation.

   (j) Electric power sold to customers pursuant to Section 80100 of
the Water Code is not subject to this section.



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 (,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.


367.3.  (a) For purposes of this section, a "qualifying direct
transaction customer" means any customer that meets each of the
following requirements:
   (1) The customer entered into a direct transaction with an
electric service provider for electric service for a plant or
facility in California, by executing a contract prior to January 1,
2000, that extended service through at least February 1, 2001.
   (2) The plant or facility was, after February 1, 2001,
involuntarily returned to the electrical corporation for electrical
service, as a result of the electric service provider terminating
electrical service under the direct transaction contract.
   (3) The plant or facility entered into a new direct transaction
with an electric service provider for the plant or facility's
electric service and a direct access service request (DASR) was
submitted within 90 days from the date the plant or facility's most
recent direct transaction contract was involuntarily terminated.
   (4) The plant or facility continuously participated in an
interruptible or curtailable service program.
   (5) The plant or facility had an average total cost for all
aspects of electric service, as a percentage of sales, in excess of 8
percent, for the five years beginning January 1, 1996, and
continuing to December 31, 2000.
   (6) The plant or facility had an average net profit margin as a
percentage of sales of greater than 2 percent, for the five years
beginning January 1, 1996, and continuing to December 31, 2000.
   (7) The average total electric service cost as a percentage of
sales, exceeded the average net profit margin as a percentage of
sales for the plant or facility, for the five years beginning January
1, 1996, and continuing to December 31, 2000.
   (8) The customer submits an application to the commission pursuant
to this section within seven days of the operative date of the act
adding this section, accompanied by a declaration from an officer,
director, or owner stating that unless relieved of the expense of the
direct access cost responsibility surcharge, the plant or facility
that purchases electric service under the direct transaction
contract, faces certain and imminent closure.
   (b) If the commission finds it is in the public interest and there
is no feasible alternative, the commission may defer or waive the
collection of a portion of the cost responsibility surcharge
otherwise applicable to a qualifying direct transaction customer, to
the extent necessary to mitigate the conditions described in
paragraph (8) of subdivision (a).  That deferral or waiver may not
result in any shifting of costs to bundled service customers, either
immediately or over time, or delay the full and timely recovery of
costs from direct access customers as a group.
   (c) The commission shall issue a decision on an application
submitted pursuant to this section on or before September 4, 2003.
Notwithstanding subdivisions (d) and (g) of Section 311, the
commission may issue its decision in less than 30 days following
filing and service of the proposed decision.
   (d) The commission shall require an electrical corporation to
defer collection of a portion of the cost responsibility surcharge
otherwise applicable to a qualifying direct transaction customer
while an application submitted pursuant to this section is pending
before the commission and, if the application is granted, until the
deferral or waiver is operative.
   (e) This section shall remain in effect only until January 1,
2009, and as of that date is repealed, unless a later enacted
statute, that is enacted before January 1, 2009, deletes or extends
that date.



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.



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:
   (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.



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.



369.  The commission shall establish an effective mechanism that
ensures recovery of transition costs referred to in Sections 367,
368, 375, and 376, and subject to the conditions in Sections 371 to
374, inclusive, from all existing and future consumers in the service
territory in which the utility provided electricity services as of
December 20, 1995; provided, that the costs shall not be recoverable
for new customer load or incremental load of an existing customer
where the load is being met through a direct transaction and the
transaction does not otherwise require the use of transmission or
distribution facilities owned by the utility.  However, the
obligation to pay the competition transition charges cannot be
avoided by the formation of a local publicly owned electrical
corporation on or after December 20, 1995, or by annexation of any
portion of an electrical corporation's service area by an existing
local publicly owned electric utility.
   This section shall not apply to service taken under tariffs,
contracts, or rate schedules that are on file, accepted, or approved
by the Federal Energy Regulatory Commission, unless otherwise
authorized by the Federal Energy Regulatory Commission.




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, 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.



371.  (a) Except as provided in Sections 372 and 374, the uneconomic
costs provided in Sections 367, 368, 375, and 376 shall be applied
to each customer based on the amount of electricity purchased by the
customer from an electrical corporation or alternate supplier of
electricity, subject to changes in usage occurring in the normal
course of business.
   (b) Changes in usage occurring in the normal course of business
are those resulting from changes in business cycles, termination of
operations, departure from the utility service territory, weather,
reduced production, modifications to production equipment or
operations, changes in production or manufacturing processes, fuel
switching, including installation of fuel cells pending a contrary
determination by the California Energy Resources Conservation and
Development Commission in Section 383, 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.


372.  (a) It is the policy of the state to encourage and support the
development of cogeneration as an efficient, environmentally
beneficial, competitive energy resource that will enhance the
reliability of local generation supply, and promote local business
growth.  Subject to the specific conditions provided in this section,
the commission shall determine the applicability to customers of
uneconomic costs as specified in Sections 367, 368, 375, and 376.
Consistent with this state policy, the commission shall provide that
these costs shall not apply to any of the following:
   (1) To load served onsite or under an over the fence arrangement
by a nonmobile self-cogeneration or cogeneration facility that was
operational on or before December 20, 1995, or by increases in the
capacity of a facility to the extent that the increased capacity was
constructed by an entity holding an ownership interest in or
operating the facility and does not exceed 120 percent of the
installed capacity as of December 20, 1995, provided that 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, and
376.
   (C) Construct a self-cogeneration or cogeneration facility of
approximately the same capacity as the facility previously deferred,
provided that the costs provided in Sections 367, 368, 375, and 376
shall apply consistent with subdivision (e) of Section 367, unless
otherwise authorized by the commission pursuant to subdivision (c).
   (3) Subject to the firewall described in subdivision (e) of
Section 367, provide that the ratemaking treatment for
self-cogeneration or cogeneration deferral agreements executed 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 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 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
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.


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.




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
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 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.

   (3) To loads served by irrigation districts, water districts,
water storage districts, municipal utility districts, and other water
agencies that, on December 20, 1995, were members of the Southern
San Joaquin Valley Power Authority, or the Eastside Power Authority,
provided, however, that this paragraph shall be applicable only to
that portion of each district or agency's load that is used to power
pumps that are owned by that district or agency as of December 20,
1995, or replacements thereof, and is being used to pump water for
district purposes.  The rates applicable to these districts and
agencies shall be adjusted as of January 1, 1997.
   (4) The provisions of this subdivision shall no longer be
operative after March 31, 2002.
   (5) The provisions of paragraph (1) shall not be applicable to any
irrigation district, water district, or water agency described in
paragraph (2) or (3).
   (6) Transmission services provided to any irrigation district
described in paragraph (1) or (2) shall be provided pursuant to
otherwise applicable tariffs.
   (7) Nothing in this chapter shall be deemed to grant the
commission any jurisdiction over irrigation districts not already
granted to the commission by existing law.
   (b) To give the full effect to the legislative intent in enacting
Section 701.8, the costs provided in Sections 367, 368, 375, and 376
shall not apply to the load served by preference power purchased from
a federal power marketing agency, or its successor, pursuant to
Section 701.8 as it existed on January 1, 1996, provided that the
power is used solely for the customer's own systems load and not for
sale.  The costs of this provision shall be borne by all ratepayers
in the affected service territory, notwithstanding the firewall
established in subdivision (e) of Section 367.
   (c) To give effect to an existing relationship, the obligation to
pay the uneconomic costs specified in Sections 367, 368, 375, and 376
shall not apply to that portion of the load of the University of
California campus situated in 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.


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.



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.



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.



377.  The commission shall continue to regulate the facilities for
the generation of electricity owned by any public utility prior to
January 1, 1997, that are subject to commission regulation until the
owner of those facilities has applied to the commission to dispose of
those facilities and has been authorized by the commission under
Section 851 to undertake that disposal.  Notwithstanding any other
provision of law, no facility for the generation of electricity owned
by a public utility may be disposed of prior to January 1, 2006.
The commission shall ensure that public utility generation assets
remain dedicated to service for the benefit of California ratepayers.



377.1.  Section 377 does not apply to the four run-of-river
hydroelectric project works located on the Truckee River, as
referenced in Section 210(b)(17) of Public Law 101-618 or to the two
run-of-river hydroelectric projects, also known as the Naches Drop
plant and Naches plant, located on the Wapatox Canal on the Naches
River in the State of Washington.



377.2.  Notwithstanding Section 377, a facility for the generation
of electricity, or an interest in a facility for the generation of
electricity, that is located outside of this state, is owned by a
public utility that serves 60,000 or fewer customer accounts in this
state, and is not necessary to serve that public utility's customers
in this state, may be disposed of upon approval of the commission
pursuant to Section 851 or upon exemption by the commission pursuant
to Section 853.



378.  The commission shall authorize new optional rate schedules and
tariffs, including new service offerings, that accurately reflect
the loads, locations, conditions of service, cost of service, and
market opportunities of customer classes and subclasses.




379.  Nuclear decommissioning costs shall not be part of the costs
described in Sections 367, 368, 375, and 376, but shall be recovered
as a nonbypassable charge until the time as the costs are fully
recovered.  Recovery of decommissioning costs may be accelerated to
the extent possible.



379.5.  Notwithstanding any other provision of law, on or before
March 7, 2001, the commission, in consultation with the Independent
System Operator, shall take all of the following actions, and shall
include the reasonable costs involved in taking those actions in the
distribution revenue requirements of utilities regulated by the
commission, as appropriate:
   (a) (1) Identify and undertake those actions necessary to reduce
or remove constraints on the state's existing electrical transmission
and distribution system, including, but not limited to,
reconductoring of transmission lines, the addition of capacitors to
increase voltage, the reinforcement of existing transmission
capacity, and the installation of new transformer banks.  The
commission shall, in consultation with the Independent System
Operator, give first priority to those geographical regions where
congestion reduces or impedes electrical transmission and supply.
   (2) Consistent with the existing statutory authority of the
commission, afford electrical corporations a reasonable opportunity
to fully recover costs it determines are reasonable and prudent to
plan, finance, construct, operate, and maintain any facilities under
its jurisdiction required by this section.
   (b) In consultation with the State Energy Resources Conservation
and Development Commission, adopt energy conservation demand-side
management and other initiatives in order to reduce demand for
electricity and reduce load during peak demand periods.  Those
initiatives shall include, but not be limited to, all of the
following:
   (1) Expansion and acceleration of residential and commercial
weatherization programs.
   (2) Expansion and acceleration of programs to inspect and improve
the operating efficiency of heating, ventilation, and
air-conditioning equipment in new and existing buildings, to ensure
that these systems achieve the maximum feasible cost-effective energy
efficiency.
   (3) Expansion and acceleration of programs to improve energy
efficiency in new buildings, in order to achieve the maximum feasible
reductions in uneconomic energy and peak electricity consumption.
   (4) Incentives to equip commercial buildings with the capacity to
automatically shut down or dim nonessential lighting and
incrementally raise thermostats during a peak electricity demand
period.
   (5) Evaluation of installing local infrastructure to link
temperature setback thermostats to real-time price signals.
   (6) Incentives for load control and distributed generation to be
paid for enhancing reliability.
   (7) Differential incentives for renewable or super clean
distributed generation resources pursuant to Section 379.6.
   (8) Reevaluation of all efficiency cost-effectiveness tests in
light of increases in wholesale electricity costs and of natural gas
costs to explicitly include the system value of reduced load on
reducing market clearing prices and volatility.
   (c) In consultation with the Energy Resources Conservation and
Development Commission, adopt and implement a residential,
commercial, and industrial peak reduction program that encourages
electric customers to reduce electricity consumption during peak
power periods.



379.6.  (a) (1) The commission, in consultation with the State
Energy Resources Conservation and Development Commission, shall
administer, until January 1, 2012, the self-generation incentive
program for distributed generation resources originally established
pursuant to Chapter 329 of the Statutes of 2000.
   (2) Except as provided in paragraph (3), the extension of the
program pursuant to Chapter 894 of the Statutes of 2003, as amended
by Chapter 675 of the Statutes of 2004 and Chapter 22 of the Statutes
of 2005, shall apply to all eligible technologies, as determined by
the commission, until January 1, 2008.
   (3) The commission shall administer solar technologies separately,
after January 1, 2007, pursuant to the California Solar Initiative
adopted by the commission in Decision 06-01-024.
   (b) Commencing January 1, 2008, until January 1, 2012, eligibility
for the program pursuant to paragraphs (1) and (2) of subdivision
(a) shall be limited to fuel cells and wind distributed generation
technologies that meet or exceed the emissions standards required
under the distributed generation certification program requirements
of Article 3 (commencing with Section 94200) of Subchapter 8 of
Chapter 1 of Division 3 of Title 17 of the California Code of
Regulations.
   (c) Eligibility for the self-generation incentive program's level
3 incentive category shall be subject to the following conditions:
   (1) Commencing January 1, 2007, all combustion-operated
distributed generation projects using fossil fuel shall meet an
oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per
megawatthour and a minimum efficiency of 60 percent. A minimum
efficiency of 60 percent shall be measured as useful energy output
divided by fuel input. The efficiency determination shall be based on
100 percent load.
   (2) Combined heat and power units that meet the 60-percent
efficiency standard may take a credit to meet the applicable NOx
emissions standard of 0.07 pounds per megawatthour. Credit shall be
at the rate of one megawatthour for each 3.4 million British thermal
units (Btus) of heat recovered.
   (3) Notwithstanding paragraph (1), a project that does not meet
the applicable NOx emissions standard is eligible if it meets both of
the following requirements:
   (A) The project operates solely on waste gas. The commission shall
require a customer that applies for an incentive pursuant to this
paragraph to provide an affidavit or other form of proof, that
specifies that the project shall be operated solely on waste gas.
Incentives awarded pursuant to this paragraph shall be subject to
refund and shall be refunded by the recipient to the extent the
project does not operate on waste gas. As used in this paragraph,
"waste gas" means natural gas that is generated as a byproduct of
petroleum production operations and is not eligible for delivery to
the utility pipeline system.
   (B) The air quality management district or air pollution control
district, in issuing a permit to operate the project, determines that
operation of the project will produce an onsite net air emissions
benefit, compared to permitted onsite emissions if the project does
not operate. The commission shall require the customer to secure the
permit prior to receiving incentives.
   (d) In determining the eligibility for the self-generation
incentive program, minimum system efficiency shall be determined
either by calculating electrical and process heat efficiency as set
forth in Section 218.5, or by calculating overall electrical
efficiency.
   (e) In administering the self-generation incentive program, the
commission may adjust the amount of rebates, include other ultraclean
and low-emission distributed generation technologies, as defined in
Section 353.2, and evaluate other public policy interests, including,
but not limited to, ratepayers, and energy efficiency and
environmental interests.
   (f) On or before November 1, 2008, the State Energy Resources
Conservation and Development Commission, in consultation with the
commission and the State Air Resources Board, shall evaluate the
costs and benefits, including air pollution, efficiency, and
transmission and distribution system improvements, of providing
ratepayer subsidies for renewable and fossil fuel "ultraclean and
low-emission distributed generation," as defined in Section 353.2, as
part of the integrated energy policy report adopted pursuant to
Chapter 4 (commencing with Section 25300) of Division 15 of the
Public Resources Code. The State Energy Resources Conservation and
Development Commission shall include recommendations for changes in
the eligibility of technologies and fuels under the program, and
whether the level of subsidy should be adjusted, after considering
its conclusions on costs and benefits pursuant to this subdivision.



379.7.  (a) The Legislature finds and declares that the
demonstration project authorized pursuant to this section, at the
Antelope Valley Fairgrounds, to determine actual energy and cost
savings that may be achieved when investments are made onsite to both
reduce overall electricity demand and to offset peak electricity
demand through the installation of (1) cost-effective energy
efficient equipment and fixtures, and (2) a photovoltaic solar energy
system, will provide valuable empirical data upon which to optimize
future ratepayer investments in cost-effective energy efficiency and
photovoltaic solar systems.
   (b) (1) The demonstration project authorized pursuant to this
section shall be referred to as the Antelope Valley Fairgrounds EE
and PV Synergy Demonstration Project.
   (2) To ensure that potential energy and cost savings from
cost-effective energy efficient equipment and fixtures are achieved,
the Antelope Valley Fairgrounds shall do both of the following:
   (A) Implement the recommendations of the energy audit performed on
July 27, 2004.
   (B) Include cost-effective energy efficient equipment and fixtures
in all future expansions of the fairgrounds.
   (3) To ensure that potential energy and cost savings are achieved
from a photovoltaic solar energy system of up to 630 kilowatts
installed at the Antelope Valley Fairgrounds, the photovoltaic solar
energy system shall meet both of the following criteria:
   (A) Be installed in a manner that optimizes operating efficiency,
including appropriate siting.
   (B) Consist of components that are new and unused and have a
warranty of not less than 10 years to protect against defects and
undue degradation of electrical generation output.
   (c) An electrical corporation providing electrical service to the
Antelope Valley Fairgrounds shall, by February 1, 2006, file with the
commission a tariff providing for an incentive rate consistent with
this section. The incentive rate shall provide stability and
certainty over a 10-year period in an amount and in a manner to
support investment in, and to test the durability of, the
photovoltaic solar energy system installed at the fairgrounds. The
incentive rate, together with an incentive from the self-generation
incentive program that recognizes the energy efficiency investments
made at the fairgrounds as authorized pursuant to Section 379.6,
shall provide for a 10-year payback period for the photovoltaic solar
energy system. The incentive rate shall not result in any cost
shifting among customer classes of the electrical corporation.
   (d) Actual energy and cost savings shall be determined through
annual energy audits and ongoing metering of electricity used and
electricity produced on a time-of-use basis.
   (e) The demonstration project will be complete 10 years from the
date the Antelope Valley Fairgrounds first takes electrical service
pursuant to the incentive rate required by this section.
   (f) Biennial reports shall be submitted to the commission and to
the Legislature by the Antelope Valley Fairgrounds. The reports shall
include actual recorded electricity usage by the fairgrounds and
electricity produced by the photovoltaic solar energy system at the
fairgrounds, on a time-of-use basis. A final report shall be
submitted to the commission and to the Legislature within six months
of the conclusion of the demonstration project. The final report
shall include an analysis of the energy and cost savings achieved at
the fairgrounds, the effectiveness of combining investment in energy
efficiency and a photovoltaic solar energy system on the same site,
the performance and durability of the photovoltaic solar energy
system over the life of the demonstration project, and
recommendations for optimizing ratepayer investment in energy
efficiency and photovoltaic solar energy systems.
   (g) This section shall remain in effect only until January 1,
2017, and as of that date is repealed, unless a later enacted
statute, that is enacted before January 1, 2017, deletes or extends
that date.


380.  (a) The commission, in consultation with the Independent
System Operator, shall establish resource adequacy requirements for
all load-serving entities.
   (b) In establishing resource adequacy requirements, the commission
shall achieve all of the following objectives:
   (1) Facilitate development of new generating capacity and
retention of existing generating capacity that is economic and
needed.
   (2) Equitably allocate the cost of generating capacity and prevent
shifting of costs between customer classes.
   (3) Minimize enforcement requirements and costs.
   (c) Each load-serving entity shall maintain physical generating
capacity adequate to meet its load requirements, including, but not
limited to, peak demand and planning and operating reserves. The
generating capacity shall be deliverable to locations and at times as
may be necessary to provide reliable electric service.
   (d) Each load-serving entity shall, at a minimum, meet the most
recent minimum planning reserve and reliability criteria approved by
the Board of Trustees of the Western Systems Coordinating Council or
the Western Electricity Coordinating Council.
   (e) The commission shall implement and enforce the resource
adequacy requirements established in accordance with this section in
a nondiscriminatory manner. Each load-serving entity shall be subject
to the same requirements for resource adequacy and the renewables
portfolio standard program that are applicable to electrical
corporations pursuant to this section, or otherwise required by law,
or by order or decision of the commission. The commission shall
exercise its enforcement powers to ensure compliance by all
load-serving entities.
   (f) The commission shall require sufficient information,
including, but not limited to, anticipated load, actual load, and
measures undertaken by a load-serving entity to ensure resource
adequacy, to be reported to enable the commission to determine
compliance with the resource adequacy requirements established by the
commission.
   (g) An electrical corporation's costs of meeting resource adequacy
requirements, including, but not limited to, the costs associated
with system reliability and local area reliability, that are
determined to be reasonable by the commission, or are otherwise
recoverable under a procurement plan approved by the commission
pursuant to Section 454.5, shall be fully recoverable from those
customers on whose behalf the costs are incurred, as determined by
the commission, at the time the commitment to incur the cost is made
or thereafter, on a fully nonbypassable basis, as determined by the
commission. The commission shall exclude any amounts authorized to be
recovered pursuant to Section 366.2 when authorizing the amount of
costs to be recovered from customers of a community choice aggregator
or from customers that purchase electricity through a direct
transaction pursuant to this subdivision.
   (h) The commission shall determine and authorize the most
efficient and equitable means for achieving all of the following:
   (1) Meeting the objectives of this section.
   (2) Ensuring that investment is made in new generating capacity.
   (3) Ensuring that existing generating capacity that is economic is
retained.
   (4) Ensuring that the cost of generating capacity is allocated
equitably.
   (i) In making the determination pursuant to subdivision (h), the
commission may consider a centralized resource adequacy mechanism
among other options.
   (j) For purposes of this section, "load-serving entity" means an
electrical corporation, electric service provider, or community
choice aggregator. "Load-serving entity" does not include any of the
following:
   (1) A local publicly owned electric utility as defined in Section
9604.
   (2) The State Water Resources Development System commonly known as
the State Water Project.
   (3)  Customer generation located on the customer's site or
providing electric service through arrangements authorized by Section
218, if the customer generation, or the load it serves, meets one of
the following criteria:
   (A) It takes standby service from the electrical corporation on a
commission-approved rate schedule that provides for adequate backup
planning and operating reserves for the standby customer class.
   (B) It is not physically interconnected to the electric
transmission or distribution grid, so that, if the customer
generation fails, backup electricity is not supplied from the
electricity grid.
   (C) There is physical assurance that the load served by the
customer generation will be curtailed concurrently and commensurately
with an outage of the customer generation.