Bill Text: CA SB1195 | 2013-2014 | Regular Session | Introduced
NOTE: There are more recent revisions of this legislation. Read Latest Draft
Bill Title: State ballot pamphlet.
Spectrum: Partisan Bill (Democrat 1-0)
Status: (Passed) 2014-08-11 - Chaptered by Secretary of State. Chapter 187, Statutes of 2014. [SB1195 Detail]
Download: California-2013-SB1195-Introduced.html
Bill Title: State ballot pamphlet.
Spectrum: Partisan Bill (Democrat 1-0)
Status: (Passed) 2014-08-11 - Chaptered by Secretary of State. Chapter 187, Statutes of 2014. [SB1195 Detail]
Download: California-2013-SB1195-Introduced.html
BILL NUMBER: SB 1195 INTRODUCED
BILL TEXT
INTRODUCED BY Senator Padilla
FEBRUARY 20, 2014
An act to amend Section 332.1, 367, 369, 370, 371, 372, 373, 374,
379, 397, 846.2, 9600, and 9607 of, and to repeal Sections 350,
367.7, 368, 368.5, 374.5, and 375 of, the Public Utilities Code,
relating to electricity.
LEGISLATIVE COUNSEL'S DIGEST
SB 1195, as introduced, Padilla. Electrical restructuring.
The existing restructuring of the electrical industry within the
Public Utilities Act provides for the establishment of an Independent
System Operator and a Power Exchange as nonprofit public benefit
corporations. Existing law requires the Independent System Operator,
within 6 months after receiving approval for its operation by the
Federal Energy Regulatory Commission, to provide a report to the
Legislature and the Electricity Oversight Board containing specified
matter.
This bill would repeal this reporting requirement.
Electrical restructuring states the intent of the Legislature that
individual customers not experience rate increases as a result of
the allocation of transition costs, as specified, and requires the
Public Utilities Commission to implement a methodology for
calculating certain Power Exchange energy credits.
This bill would repeal this provision.
Electrical restructuring requires each electrical corporation to
propose a cost recovery plan to the commission for the recovery of
the uneconomic costs of an electrical corporation's
generation-related assets and obligations, requires that the plan
contain specified matter, and requires that the plan set rates for
each customer class, rate schedule, contract, or tariff option, at
levels equal to the level as shown on electric rate schedules as of
June 10, 1996, provided that rates for residential and small
commercial customers be reduced so that these customers receive rate
reductions of no less than 10% for 1998 continuing through 2002.
Electrical restructuring prohibits the commission, upon the
termination of the 10% rate reduction for residential and small
commercial customers, from subjecting those residential and small
commercial customers to any rate increase or future rate obligations
solely as a result of the termination of the 10% rate reduction.
This bill would repeal these provisions.
Electrical restructuring requires any electrical corporation
serving agricultural customers with multiple meters to conduct
research based on a statistically valid sample of those customers and
meters to determine the typical simultaneous peak load of those
customers and to report the results to those customers and the
commission by July 1, 2001. Electrical restructuring requires the
commission to consider the research results in setting future
electrical distribution rates for those customers.
This bill would repeal this provision.
Electrical restructuring requires the commission to allow recovery
of reasonable employee related transition costs incurred and
projected for severence, retraining, early retirement, outplacement,
and related expenses for the employees in order to mitigate potential
negative impacts on utility personnel directly affected by
restructuring.
This bill would repeal this provision.
This bill would strike references to these repealed statutes.
Vote: majority. Appropriation: no. Fiscal committee: no.
State-mandated local program: no.
THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:
SECTION 1. Section 332.1 of the Public Utilities Code is amended
to read:
332.1. (a) (1) It is the intent of the Legislature to enact Item
1 (revised) on the commission's August 21, 2000 , agenda,
entitled "Opinion Modifying Decision (D.) D.00-06-034 and D.00-08-021
to Regarding Interim Rate Caps for San Diego Gas and Electric
Company," as modified below.
(2) It is also the intent of the Legislature that to the extent
that the Federal Energy Regulatory Commission orders refunds to
electrical corporations pursuant to their findings, the commission
shall ensure that any refunds are returned to customers.
(b) The commission shall establish a ceiling of six and
five-tenths cents ($0.065) per kilowatthour on the energy component
of electric bills for electricity supplied to residential, small
commercial, and street lighting customers by the San Diego Gas and
Electric Company, through December 31, 2002, retroactive to June 1,
2000. If the commission finds it in the public interest, this ceiling
may be extended through December 2003 and may be adjusted as
provided in subdivision (d).
(c) The commission shall establish an accounting procedure to
track and recover reasonable and prudent costs of providing electric
energy to retail customers unrecovered through retail bills due to
the application of the ceiling provided for in subdivision (b). The
accounting procedure shall utilize revenues associated with sales of
energy from utility-owned or managed generation assets to offset an
undercollection, if undercollection occurs. The accounting procedure
shall be reviewed periodically by the commission, but not less
frequently than semiannually. The commission may utilize an existing
proceeding to perform the review. The accounting procedure and review
shall provide a reasonable opportunity for San Diego Gas and
Electric Company to recover its reasonable and prudent costs of
service over a reasonable period of time.
(d) If the commission determines that it is in the public interest
to do so, the commission, after the date of the completion of the
proceeding described in subdivision (g), may adjust the ceiling from
the level specified in subdivision (b), and may adjust the frozen
rate from the levels specified in subdivision (f), consistent with
the Legislature's intent to provide substantial protections for
customers of the San Diego Gas and Electric Company and their
interest in just and reasonable rates and adequate service.
(e) For purposes of this section, "small commercial customer"
includes, but is not limited to, all San Diego Gas and Electric
Company accounts on Rate Schedule A of the San Diego Gas and Electric
Company, all accounts of customers who are "general acute care
hospitals," as defined in Section 1250 of the Health and Safety Code,
all San Diego Gas and Electric Company accounts of customers who are
public or private schools for pupils in kindergarten or any of
grades 1 to 12, inclusive, and all accounts on Rate Schedule AL-TOU
under 100 kilowatts.
(f) The commission shall establish an initial frozen rate of six
and five-tenths cents ($0.065) per kilowatthour on the energy
component of electric bills for electricity supplied to all customers
by the San Diego Gas and Electric Company not subject to subdivision
(b), for the time period ending with the end of the rate freeze for
the Pacific Gas and Electric Company and the Southern California
Edison Company pursuant to Section 368 ,
retroactive to February 7, 2001. The commission shall consider the
comparable energy components of rates for comparable customer classes
served by the Pacific Gas and Electric Company and the Southern
California Edison Company and, if it determines it to be in the
public interest, the commission may adjust this frozen rate, and may
do so, retroactive to the date that rate increases took effect for
customers of Pacific Gas and Electric Company and Southern California
Edison Company pursuant to the commission's March 27, 2001,
decision. The commission shall determine the Fixed Department of
Water Resources Set-Aside pursuant to Section 360.5 for customers
subject to this section, reflecting a retail rate consistent with the
rate for the energy component of electric bills as determined in
this subdivision, in place of the retail rate in effect on January 5,
2001. This section shall be construed to modify the payment
provisions, but may not be construed to modify the electric
procurement obligations of the Department of Water Resources,
pursuant to any contract or agreement in accordance with Division 27
(commencing with Section 80000) of the Water Code, and in effect as
of February 7, 2001, between the Department of Water Resources and
San Diego Gas and Electric Company.
(g) The commission shall institute a proceeding to examine the
prudence and reasonableness of the San Diego Gas and Electric Company
in the procurement of wholesale energy on behalf of its customers,
for a period beginning, at the latest, on June 1, 2000. If the
commission finds that San Diego Gas and Electric Company acted
imprudently or unreasonably, the commission shall issue orders that
it determines to be appropriate affecting the retail rates of San
Diego Gas and Electric Company customers including, but not limited
to, refunds.
(h) Nothing in this section may be construed to limit the
authority of the Department of Water Resources pursuant to Division
27 (commencing with Section 80000) of the Water Code.
SEC. 2. Section 350 of the Public Utilities Code is repealed.
350. The Independent System Operator, in consultation with the
California Energy Resources Conservation and Development Commission,
the Public Utilities Commission, the Western Electricity Coordinating
Council, and concerned regulatory agencies in other western states,
shall within six months after the Federal Energy Regulatory
Commission approval of the Independent System Operator, provide a
report to the Legislature and to the Oversight Board that does the
following:
(a) Conducts an independent review and assessment of Western
Electricity Coordinating Council operating reliability criteria.
(b) Quantifies the economic cost of major transmission outages
relating to the Pacific Intertie, Southwest Power Link, DC link, and
other important high voltage lines that carry power both into and
from California.
(c) Identifies the range of cost-effective options that would
prevent or mitigate the consequences of major transmission outages.
(d) Identifies communication protocols that may be needed to be
established to provide advance warning of incipient problems.
(e) Identifies the need for additional generation reserves and
other voltage support equipment, if any, or other resources that may
be necessary to carry out its functions.
(f) Identifies transmission capacity additions that may be
necessary at certain times of the year or under certain conditions.
(g) Assesses the adequacy of current and prospective institutional
provisions for the maintenance of reliability.
(h) Identifies mechanisms to enforce transmission right-of-way
maintenance.
(i) Contains recommendations regarding cost-beneficial
improvements to electric system reliability for the citizens of
California.
SEC. 3. Section 367 of the Public Utilities Code is amended to
read:
367. The commission shall identify and determine those costs and
categories of costs for generation-related assets and obligations,
consisting of generation facilities, generation-related regulatory
assets, nuclear settlements, and power purchase contracts, including,
but not limited to, restructurings, renegotiations or terminations
thereof approved by the commission, that were being collected in
commission-approved rates on December 20, 1995, and that may become
uneconomic as a result of a competitive generation market, in that
these costs may not be recoverable in market prices in a competitive
market, and appropriate costs incurred after December 20, 1995, for
capital additions to generating facilities existing as of December
20, 1995, that the commission determines are reasonable and should be
recovered, provided that these additions are necessary to maintain
the facilities through December 31, 2001. These uneconomic costs
shall include transition costs as defined in subdivision (f) of
Section 840, and shall be recovered from all customers or in the case
of fixed transition amounts, from the customers specified in
subdivision (a) of Section 841, on a nonbypassable basis and shall:
(a) Be amortized over a reasonable time period, including
collection on an accelerated basis, consistent with not increasing
rates for any rate schedule, contract, or tariff option above the
levels in effect on June 10, 1996; provided that, the recovery shall
not extend beyond December 31, 2001, except as follows:
(1) Costs associated with employee-related transition costs
as set forth in subdivision (b) of Section 375
shall continue until fully collected; provided, however, that the
cost collection shall not extend beyond December 31, 2006.
(2) Power purchase contract obligations shall continue for the
duration of the contract. Costs associated with any buy-out,
buy-down, or renegotiation of the contracts shall continue to be
collected for the duration of any agreement governing the buy-out,
buy-down, or renegotiated contract; provided, however, no power
purchase contract shall be extended as a result of the buy-out,
buy-down, or renegotiation.
(3) Costs associated with contracts approved by the commission to
settle issues associated with the Biennial Resource Plan Update may
be collected through March 31, 2002; provided that only 80 percent of
the balance of the costs remaining after December 31, 2001, shall be
eligible for recovery.
(4) Nuclear incremental cost incentive plans for the San Onofre
nuclear generating station shall continue for the full term as
authorized by the commission in Decision 96-01-011 and Decision
96-04-059; provided that the recovery shall not extend beyond
December 31, 2003.
(5) Costs associated with the exemptions provided in subdivision
(a) of Section 374 may be collected through March 31, 2002, provided
that only fifty million dollars ($50,000,000) of the balance of the
costs remaining after December 31, 2001, shall be eligible for
recovery.
(6) Fixed transition amounts, as defined in subdivision (d) of
Section 840, may be recovered from the customers specified in
subdivision (a) of Section 841 until all rate reduction bonds
associated with the fixed transition amounts have been paid in full
by the financing entity.
(b) Be based on a calculation mechanism that nets the negative
value of all above market utility-owned generation-related assets
against the positive value of all below market utility-owned
generation related assets. For those assets subject to valuation, the
valuations used for the calculation of the uneconomic portion of the
net book value shall be determined not later than December 31, 2001,
and shall be based on appraisal, sale, or other divestiture. The
commission's determination of the costs eligible for recovery and of
the valuation of those assets at the time the assets are exposed to
market risk or retired, in a proceeding under Section 455.5, 851, or
otherwise, shall be final, and notwithstanding Section 1708 or any
other provision of law, may not be rescinded, altered or amended.
(c) Be limited in the case of utility-owned fossil generation to
the uneconomic portion of the net book value of the fossil capital
investment existing as of January 1, 1998, and appropriate costs
incurred after December 20, 1995, for capital additions to generating
facilities existing as of December 20, 1995, that the commission
determines are reasonable and should be recovered, provided that the
additions are necessary to maintain the facilities through December
31, 2001. All "going forward costs" of fossil plant operation,
including operation and maintenance, administrative and general, fuel
and fuel transportation costs, shall be recovered solely from
independent Power Exchange revenues or from contracts with the
Independent System Operator, provided that for the purposes of this
chapter, the following costs may be recoverable pursuant to this
section:
(1) Commission-approved operating costs for particular
utility-owned fossil powerplants or units, at particular times when
reactive power/voltage support is not yet procurable at market-based
rates in locations where it is deemed needed for the reactive
power/voltage support by the Independent System Operator, provided
that the units are otherwise authorized to recover market-based rates
and provided further that for an electrical corporation that is also
a gas corporation and that serves at least four million customers as
of December 20, 1995, the commission shall allow the electrical
corporation to retain any earnings from operations of the reactive
power/voltage support plants or units and shall not require the
utility to apply any portions to offset recovery of transition costs.
Cost recovery under the cost recovery mechanism shall end on
December 31, 2001.
(2) An electrical corporation that, as of December 20, 1995,
served at least four million customers, and that was also a gas
corporation that served less than four thousand customers, may
recover, pursuant to this section, 100 percent of the uneconomic
portion of the fixed costs paid under fuel and fuel transportation
contracts that were executed prior to December 20, 1995, and were
subsequently determined to be reasonable by the commission, or 100
percent of the buy-down or buy-out costs associated with the
contracts to the extent the costs are determined to be reasonable by
the commission.
(d) Be adjusted throughout the period through March 31, 2002, to
track accrual and recovery of costs provided for in this subdivision.
Recovery of costs prior to December 31, 2001, shall include a return
as provided for in Decision 95-12-063, as modified by Decision
96-01-009, together with associated taxes.
(e) (1) Be allocated among the various classes of customers, rate
schedules, and tariff options to ensure that costs are recovered from
these classes, rate schedules, contract rates, and tariff options,
including self-generation deferral, interruptible, and standby rate
options in substantially the same proportion as similar costs are
recovered as of June 10, 1996, through the regulated retail rates of
the relevant electric utility, provided that there shall be a
firewall segregating the recovery of the costs of competition
transition charge exemptions such that the costs of competition
transition charge exemptions granted to members of the combined class
of residential and small commercial customers shall be recovered
only from these customers, and the costs of competition transition
charge exemptions granted to members of the combined class of
customers, other than residential and small commercial customers,
shall be recovered only from these customers.
(2) Individual customers shall not experience rate increases as a
result of the allocation of transition costs. However, customers who
elect to purchase energy from suppliers other than the Power Exchange
through a direct transaction, may incur increases in the total price
they pay for electricity to the extent the price for the energy
exceeds the Power Exchange price.
(3) The commission shall retain existing cost allocation
authority, provided the firewall and rate freeze principles are not
violated.
SEC. 4. Section 367.7 of the Public Utilities Code is repealed.
367.7. (a) It is the intent of the Legislature in enacting this
section to ensure that individual customers do not experience rate
increases as a result of the allocation of transition costs, in
accordance with paragraph (2) of subdivision (e) of Section 367.
(b) The commission shall implement a methodology whereby the Power
Exchange energy credit for a customer with a meter installed on or
after June 30, 2000, that is capable of recording hourly data is
calculated based on the actual hourly data for that customer. The
Power Exchange energy credit for a customer with a meter installed
before June 30, 2000, that is capable of recording hourly data shall,
at the election of the customer, on a one-time basis before June 30,
2000, be calculated based on either (1) the actual hourly data for
that customer or (2) the average load profile for that customer
class. If the customer fails to make an election, that customer's
Power Exchange energy credit shall continue to be based on the
average load profile for that customer class.
(c) Additional incremental billing costs incurred as a result of
the methodology implemented by the commission pursuant to subdivision
(b) may be recoverable through rates for that customer class, if the
commission finds that the costs are reasonable.
(d) The methodology implemented by the commission pursuant to
subdivisions (b) and (c) shall not result in any shifts in cost
between customer classes and shall be consistent with the firewall
provision set forth in subdivision (e) of Section 367.
SEC. 5. Section 368 of the Public Utilities Code is repealed.
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.
SEC. 6. Section 368.5 of the Public Utilities Code is repealed.
368.5. (a) Notwithstanding any other provision of law, upon the
termination of the 10-percent rate reduction for residential and
small commercial customers set forth in subdivision (a) of Section
368, the commission may not subject those residential and small
commercial customers to any rate increases or future rate obligations
solely as a result of the termination of the 10-percent rate
reduction.
(b) The provisions of subdivision (a) do not affect the authority
of the commission to raise rates for reasons other than the
termination of the 10-percent rate reduction set forth in subdivision
(a) of Section 368.
(c) Nothing in this section shall further extend the authority to
impose fixed transition amounts, as defined in subdivision (d) of
Section 840, or further authorize or extend rate reduction bonds, as
defined in subdivision (e) of Section 840.
SEC. 7. Section 369 of the Public Utilities Code is amended to
read:
369. The commission shall establish an effective mechanism that
ensures recovery of transition costs referred to in Sections 367
, 368, 375, and 376, and 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.
SEC. 8. Section 370 of the Public Utilities Code is amended to
read:
370. The commission shall require, as a prerequisite for any
consumer in California to engage in direct transactions permitted in
Section 365, that beginning with the commencement of these direct
transactions, the consumer shall have an obligation to pay the costs
provided in Sections 367 , 368, 375, and 376, and
subject to the conditions in Sections 371 to 374, inclusive, directly
to the electrical corporation providing electricity service in the
area in which the consumer is located. This obligation shall be set
forth in the applicable rate schedule, contract, or tariff option
under which the customer is receiving service from the electrical
corporation. To the extent the consumer does not use the electrical
corporation's facilities for direct transaction, the obligation to
pay shall be confirmed in writing, and the customer shall be advised
by any electricity marketer engaged in the transaction of the
requirement that the customer execute a confirmation. The requirement
for marketers to inform customers of the written requirement shall
cease on January 1, 2002.
SEC. 9. Section 371 of the Public Utilities Code is amended to
read:
371. (a) Except as provided in Sections 372 and 374, the
uneconomic costs provided in Sections 367 , 368, 375,
and 376 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.
SEC. 10. Section 372 of the Public Utilities Code is amended to
read:
372. (a) It is the policy of the state to encourage and support
the development of cogeneration as an efficient, environmentally
beneficial, competitive energy resource that will enhance the
reliability of local generation supply, and promote local business
growth. Subject to the specific conditions provided in this section,
the commission shall determine the applicability to customers of
uneconomic costs as specified in Sections 367 , 368, 375,
and 376. 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.
SEC. 11. Section 373 of the Public Utilities Code is amended to
read:
373. (a) Electrical corporations may apply to the commission for
an order determining that the costs identified in Sections 367
, 368, 375, and 376 not be collected from a
particular class of customer or category of electricity consumption.
(b) Subject to the fire wall specified in subdivision (e) of
Section 367, the provisions of this section and Sections 372 and 374
shall apply in the event the commission authorizes a nonbypassable
charge prior to the implementation of an Independent System Operator
and Power Exchange referred to in subdivision (a) of Section 365.
SEC. 12. Section 374 of the Public Utilities Code is amended to
read:
374. (a) In recognition of statutory authority and past
investments existing as of December 20, 1995, and subject to the
firewall specified in subdivision (e) of Section 367, the obligation
to pay the uneconomic costs identified in Sections 367 ,
368, 375, and 376 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.
SEC. 13. Section 374.5 of the Public Utilities Code is repealed.
374.5. Any electrical corporation serving agricultural customers
that have multiple electric meters shall conduct research based on a
statistically valid sample of those customers and meters to determine
the typical simultaneous peak load of those customers. The results
of the research shall be reported to the customers and the commission
not later than July 1, 2001. The commission shall consider the
research results in setting future electric distribution rates for
those customers.
SEC. 14. Section 375 of the Public Utilities Code is repealed.
375. (a) In order to mitigate potential negative impacts on
utility personnel directly affected by electric industry
restructuring, as described in Decision 95-12-063, as modified by
Decision 96-01-009, the commission shall allow the recovery of
reasonable employee related transition costs incurred and projected
for severance, retraining, early retirement, outplacement and related
expenses for the employees.
(b) The costs, including employee related transition costs for
employees performing services in connection with Section 363, shall
be added to the amount of uneconomic costs allowed to be recovered
pursuant to this section and Sections 367, 368, and 376, provided
recovery of these employee related transition costs shall extend
beyond December 31, 2001, provided recovery of the costs shall not
extend beyond December 31, 2006. However, there shall be no recovery
for employee related transition costs associated with officers,
senior supervisory employees, and professional employees performing
predominantly regulatory functions.
SEC. 15. Section 379 of the Public Utilities Code is amended to
read:
379. Nuclear decommissioning costs shall not be part of the costs
described in Sections 367 , 368, 375, and 376,
but shall be recovered as a nonbypassable charge until the time as
the costs are fully recovered. Recovery of decommissioning costs may
be accelerated to the extent possible.
SEC. 16. Section 397 of the Public Utilities Code is amended to
read:
397. (a) Notwithstanding subdivision (a) of Section 368,
to To ensure the continued safe and reliable
provision of electric service during the transition to competition,
and to limit the effect of fuel price volatility in electric rates
paid by California consumers, it is in the public interest to allow
an electrical corporation which is also a gas corporation and served
fewer than four million customers as of December 20, 1995, to file
with the commission a rate cap mechanism which shall include a Fuel
Price Index Mechanism requiring limited adjustments in an electrical
corporation's authorized System Average Rate in effect on June 10,
1996, to reflect price changes in the fuel market. The commission
shall authorize an electrical corporation to implement a rate cap
mechanism which includes a Fuel Price Index Mechanism provided the
following criteria are met:
(1) The Fuel Price Index Mechanism shall be based on the Southern
California Border Index price for natural gas as published
periodically in Natural Gas Intelligence Magazine. The "Starting
Point" of the Fuel Price Index Mechanism shall be defined as the
California Border Index price as published in Natural Gas
Intelligence for January 1, 1996.
(2) The Fuel Price Index Mechanism shall include a "deadband"
defined as a price range for natural gas that is any price up to 10
percent higher, or lower, than the Starting Point.
(3) The electrical corporation shall not file for a change in its
authorized System Average Rate unless the California Border Index
price, on a 12-month, rolling average basis, is outside the deadband.
If the published California Border Index is outside of the deadband,
the electrical corporation shall increase, or decrease, its
authorized System Average Rate by an amount equal to the product of
25 percent multiplied by the percentage by which the 12-month rolling
average natural gas price is higher, or lower, than the deadband.
(4) In no case shall an electrical corporation's authorized System
Average Rate under the Fuel Price Index Mechanism exceed the average
of the authorized system average rates for the two largest
electrical corporations as of June 10, 1996.
(5) This section shall become inoperative on December 31, 2001.
SEC. 17. Section 846.2 of the Public Utilities Code is amended to
read:
846.2. (a) Notwithstanding subdivision (c) of Section 841, for
any electrical corporation that ended its rate freeze period
described in subdivision (a) of Section 368 prior to July
15, 1999, the commission may order a fair and reasonable credit to
ratepayers of any excess rate reduction bond proceeds.
(b) "Excess rate reduction bond proceeds," as used in this
section, means proceeds from the sale of rate reduction bonds
authorized by commission financing orders issued pursuant to this
article that are subsequently determined by the commission to be in
excess of the amounts necessary to provide the 10-percent rate
reduction during the period when the rates were frozen
pursuant to subdivision (a) of Section 368. frozen.
SEC. 18. Section 9600 of the Public Utilities Code is amended to
read:
9600. (a) It is the intent of the Legislature that California's
local publicly owned electric utilities and electric corporations
should commit control of their transmission facilities to the
Independent System Operator as described in Chapter 2.3 (commencing
with Section 330) of Part 1 of Division 1. These utilities should
jointly advocate to the Federal Energy Regulatory Commission a
pricing methodology for the Independent System Operator that results
in an equitable return on capital investment in transmission
facilities for all Independent System Operator participants and is
based on the following principles:
(1) Utility specific access charge rates as proposed in Docket No.
EC96-19-000 as finally approved by the Federal Energy Regulatory
Commission reflecting the costs of that utility's transmission
facilities shall go into effect on the first day of the Independent
System Operator operation. The utility specific rates shall honor all
of the terms and conditions of existing transmission service
contracts and shall recognize any wheeling revenues of existing
transmission service arrangements to the transmission owner.
(2) (A) No later than two years after the initial operation of the
Independent System Operator, the Independent System Operator shall
recommend for adoption by the Federal Energy Regulatory Commission a
rate methodology determined by a decision of the Independent System
Operator governing board, provided that the decision shall be based
on principles approved by the governing board including, but not
limited to, an equitable balance of costs and benefits, and shall
define the transmission facility costs, if any, which shall be rolled
in to the transmission service rate and spread equally among all
Independent System Operator transmission users, and those
transmission facility costs, if any, which should be specifically
assigned to a specific utility's service area.
(B) If there is no governing board decision, the rate methodology
shall be determined following a decision by the alternative dispute
resolution method set forth in the Independent System Operator
bylaws.
(C) If no alternative dispute resolution decision is rendered,
then a default rate methodology shall be a uniform regional
transmission access charge and a utility specific local transmission
access charge, provided that the default rate methodology shall be
recommended for implementation upon termination of the cost recovery
plan set forth in Section 368 or no later than two
years after the initial operation of the Independent System
Operator, whichever is later. For purposes of this paragraph,
regional transmission facilities are defined to be transmission
facilities operating at or above 230 kilovolts plus an appropriate
percentage of transmission facilities operating below 230 kilovolts;
all other transmission facilities shall be considered local. The
appropriate percentage of transmission facilities described above
shall be consistent with the guidelines in Federal Energy Regulatory
Commission Order No. 888 and any exception approved by that
commission.
(3) If the rate methodology implemented as a result of a decision
by the Independent System Operator governing board or resulting from
the independent system operator alternative dispute resolution
process results in rates different than those in effect prior to the
decision for any transmission facility owner, the amount of
any differences between
the new rates and the prior rates shall be recorded in a tracking
account to be recovered from customers and paid to the appropriate
transmission owners by the transmission facility owner after
termination of the cost recovery plan set forth in Section 368. The
recovery and payments shall be based on an amortization period not to
exceed three years in the case of the electrical corporations or
five years in the case of the local publicly owned electric
utilities.
(4) The costs of transmission facilities placed in service after
the date of initial implementation of the Independent System Operator
shall be recovered using the rate methodology in effect at the time
the facilities go into operation.
(5) The electrical corporations and the local publicly owned
electric utilities shall jointly develop language for implementation
proposals to the Federal Energy Regulatory Commission based on these
principles.
(6) Nothing in this section shall compel any party to violate
restrictions applicable to facilities financed with tax-exempt bonds
or contractual restrictions and covenants regarding use of
transmission facilities existing as of December 20, 1995.
(b) Following a final Federal Energy Regulatory Commission
decision approving the Independent System Operator, no California
electrical corporation or local publicly owned electric utility shall
be authorized to collect any competition transition charge
authorized pursuant to this division and Chapter 2.3 (commencing with
Section 330) of Part 1 of Division 1 unless it commits control of
its transmission facilities to the Independent System Operator.
SEC. 19. Section 9607 of the Public Utilities Code is amended to
read:
9607. (a) The intent of this section is to avoid cost-shifting to
customers of an electrical corporation resulting from the transfer
of distribution services from an electrical corporation to an
irrigation district.
(b) Except as otherwise provided in this section and Section 9608,
and notwithstanding any other provision of law, an irrigation
district that offered electric service to retail customers as of
January 1, 1999, may not construct, lease, acquire, install, or
operate facilities for the distribution or transmission of
electricity to retail customers located in the service territory of
an electrical corporation providing electric distribution services,
unless the district has first applied for and received the approval
of the commission and implements its service consistent with the
commission's order. The commission shall find that service to be in
the public interest and shall approve the request of a district to
provide distribution or transmission of electricity to retail
customers located in the service territory of an electrical
corporation providing electric distribution service if, after notice
and hearing, the commission determines all of the following:
(1) The district will provide universal service to all retail
customers who request service within the area to be served, at
published tariff rates and on a just, reasonable, and
nondiscriminatory basis, comparable to that provided by the current
retail service provider.
(2) If the area the district is proposing to serve is either of
the following:
(A) Is within the district's boundaries but less than the entire
district, the area to be served includes a percentage of residential
customers and small customers, based on load, comparable to the
percentage of residential and small customers in the district, based
on load.
(B) Includes territory outside the district's boundaries, in which
case the territory outside the district's boundaries must include a
percentage of residential customers and small customers, based on
load, comparable to the percentage of residential and small customers
in the county or counties where service is to be provided, based on
load.
(3) Service by the district will be consistent with the intent of
the state to avoid economic waste caused by duplication of facilities
as set forth in Section 8101.
(4) Service by the district will include reasonable mitigation of
any adverse effects on the reliability of an existing service by the
electrical corporation.
(5) The district has established, funded, and is carrying out
public purpose and low-income programs comparable to those provided
by the current electric retail service provider.
(6) That district's tariffed electric rates, exclusive of
commodity costs, will be at least 15 percent below the tariffed
electric rates, exclusive of commodity costs and nonbypassable
charges under Sections 367, 368, 375, 376, and
379, of the electrical corporation for comparable services.
(7) Service by the district is in the public interest.
(c) An irrigation district that obtains the approval of the
commission under this section to serve an area shall prepare an
annual report available to the public on the total load and number of
accounts of residential, low-income, agricultural, commercial, and
industrial customers served by the irrigation district in the
approved service area.
(d) The commission shall have jurisdiction to resolve and
adjudicate complaint cases brought against an irrigation district
that offered electric service to retail customers as of January 1,
1999, by an interested party where the complaint concerns retail
electric service outside the boundaries of the district and within
the service territory of an electrical corporation. Nothing in this
section grants the commission jurisdiction to adjudicate complaint
cases involving retail electric service by an irrigation district
inside its boundaries or inside an irrigation district's exclusive
service territory.
(e) Any project involving electric transmission or distribution
facilities to be constructed or installed by an irrigation district
to serve retail customers located in the service territory of an
electrical corporation providing electric distribution services shall
comply with the California Environmental Quality Act, (Division 13
(commencing with Section 21000)) of the Public Resources Code. The
county in which the construction or installation is to occur shall
act as the lead agency. If a project involves the construction or
installation of electric transmission or distribution facilities in
more than one county, the county where the majority of the
construction is anticipated to occur shall act as the lead agency.
(f) An irrigation district may not offer service to customers
outside of its district boundaries before offering service to all
customers within its district boundaries.
(g) This section does not apply to electric distribution service
provided by Modesto Irrigation District to those customers or within
those areas described in subdivisions (a), (b), and (c) of Section
9610.
(h) The provisions of this section shall not apply to (1) a
cumulative 90 megawatts of load served by the Merced Irrigation
District that is located within the boundaries of Merced Irrigation
District, as those boundaries existed on December 20, 1995, together
with the territory of Castle Air Force Base which was located outside
the District district on that date, or
(2) electric load served by the District
district which was not previously served by an electric
corporation that is located within the boundaries of Merced
Irrigation District, as those boundaries existed on December 20,
1995, together with the territory of Castle Air Force Base which was
located outside the District district
on that date.
(i) For purposes of this section, a megawatt of load shall be
calculated in accordance with the methodology established by the
California Energy Resource Conservation and Development Commission in
its Docket No. 96-IRR-1890, but the 90 megawatts shall not include
electrical usage by customers that move to the areas described in
paragraph (1) after December 31, 2000.
(j) Subdivision (a) of this section shall not apply to the
construction, modification, lease, acquisition, installation, or
operation of facilities for the distribution or transmission of
electricity to customers electrically connected to a district as of
December 31, 2000, or to other customers who subsequently locate at
the same premises.
(k) In recognition of contractual arrangements and settlements
existing as of June 1, 2000, this section does not apply to the
acquisition or operation of the electric distribution facilities that
are the subject of the Settlement Agreement dated May 1, 2000,
between Pacific Gas and Electric Company and the San Joaquin
Irrigation District.
( l ) For purposes of this section, retail customers do
not include an irrigation district's own electric load being served
of retail by an electrical corporation.
