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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
/X/ Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2000
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue (626) 302-1212
Rosemead, California 91770 (Registrant's telephone number,
(Address of principal executive offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------ ---------------------
Capital Stock
Cumulative Preferred American and Pacific
4.08% Series 4.32% Series
4.24% Series 4.78% Series
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of April 16, 2001, there were 434,888,104 shares of Common Stock outstanding,
all of which are held by the registrant's parent holding company. The aggregate
market value of registrant's voting stock held by non-affiliates was
approximately $197,534,061.75 on or about April 16, 2001, based upon prices
reported by the American Stock Exchange. The market values of the various
classes of voting stock held by non-affiliates, as of April 16, 2001, were as
follows: CUMULATIVE PREFERRED STOCK $40,079,061.75; $100 CUMULATIVE PREFERRED
STOCK $157,455,000.00.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents listed below have been incorporated by
reference into the parts of this report so indicated.
(1) Designated portions of the Annual Report to
Shareholders for the year ended December 31, 2000......Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 2001 Annual
Meeting of Shareholders........................................ Part III
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TABLE OF CONTENTS
Item Page
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Part I
1. Business ............................................................................................... 1
Forward-Looking Statements.......................................................................... 1
Competitive Environment............................................................................. 3
Significant Developments in California Electric Utility Restructuring............................... 3
Regulation.......................................................................................... 10
Changing Regulatory Environment..................................................................... 11
Other Rate Matters.................................................................................. 16
Fuel Supply and Purchased Power Costs............................................................... 21
Environmental Matters............................................................................... 22
2. Properties.............................................................................................. 25
Existing Generating Facilities...................................................................... 25
Construction Program and Capital Expenditures....................................................... 27
Nuclear Power Matters............................................................................... 27
3. Legal Proceedings....................................................................................... 31
Geothermal Generators' Litigation................................................................... 31
San Onofre Personal Injury Litigation............................................................... 31
Navajo Nation Litigation.............................................................................32
Shareholder Litigation...............................................................................33
Power Generator Litigation.......................................................................... 34
PX Performance Bond Litigation...................................................................... 39
4. Submission of Matters to a Vote of Security Holders..................................................... 40
Executive Officers of the Registrant................................................................ 40
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters................................... 42
6. Selected Financial Data................................................................................. 42
7. Management's Discussion and Analysis of Results of Operations and Financial Condition................... 42
7A. Quantitative and Qualitative Disclosures About Market Risk.............................................. 42
8. Financial Statements and Supplementary Data............................................................. 42
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 42
Part III
10. Directors and Executive Officers of the Registrant...................................................... 42
11. Executive Compensation.................................................................................. 43
12. Security Ownership of Certain Beneficial Owners and Management.......................................... 43
13. Certain Relationships and Related Transactions.......................................................... 43
Part IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................ 43
Financial Statements................................................................................ 43
Report of Independent Public Accountants and Schedules Supplementing Financial Statements........... 43
Exhibits............................................................................................ 44
Reports on Form 8-K ................................................................................ 44
Signatures.......................................................................................... 49
PART I
Item 1. Business
Southern California Edison Company (SCE) was incorporated in 1909 under the laws
of the State of California. SCE is a public utility primarily engaged in the
business of supplying electric energy to a 50,000 square-mile area of Central
and Southern California, excluding the City of Los Angeles and certain other
cities. The SCE service territory includes approximately 800 cities and
communities and a population of more than 11 million people. Beginning in April
1998, pursuant to the restructuring of the California electric utility industry
mandated by a 1996 state law, other entities have had the ability to sell
electricity in SCE's service territory, utilizing SCE's transmission and
distribution lines at tariffed rates. As a part of this utility industry
restructuring, SCE sold some of its electric generating plants in 1998. SCE
currently retains other electric generating plants, however, and it retains its
transmission and distribution lines over which it transmits and distributes the
electricity generated by SCE and other generators to the customers in SCE's
service territory. The Memorandum of Understanding (MOU) that Edison
International and SCE have entered into with the California Department of Water
Resources (CDWR) with the endorsement of the Governor of California (described
in Significant Developments in California Electric Utility Restructuring) calls
for the sale of SCE's transmission assets to an agency of the State of
California. As a further part of the industry restructuring, SCE had been
required for an intended interim transitional period (ending no later than
year-end 2001) to sell all SCE-generated electricity to the California Power
Exchange (PX) at prices determined by periodic public auctions, and to buy any
electricity needed to serve SCE's retail customers from the PX at similarly
determined prices. As part of a December 15, 2000, order, the Federal Energy
Regulatory Commission (FERC) eliminated the requirement that SCE buy and sell
power exclusively through the PX and California Independent System Operator
(ISO). In mid-January 2001, the PX suspended SCE's trading privileges for
failure to post collateral due to SCE's rating agency downgrades. The PX
suspended its day-ahead and day-of energy trading on January 30 and January 31,
2001, respectively. On March 9, 2001, the PX filed for Chapter 11 bankruptcy
protection. As discussed in Significant Developments in California Electric
Utility Restructuring below, the CDWR is providing power for sale to SCE's
customers to the extent SCE cannot provide sufficient power from SCE's own
generation and power contracts. SCE delivers such power and collects revenues
for it on behalf of CDWR. In 2000, SCE's total operating revenue was derived
from: 38.2% residential customers, 38.3% commercial customers, 8.4% industrial
customers, 6.6% public authorities, 2.3% agricultural and other customers, and
6.2% other electric revenue. SCE had 12,593 full-time employees at year-end
2000. SCE comprises the largest portion of the assets and revenue of its parent
holding company, Edison International.
Forward-Looking Statements
This annual report contains forward-looking statements that reflect SCE's
current expectations and projections about future events based on SCE's
knowledge of present facts and circumstances and assumptions about future
events. Other information distributed by SCE that is incorporated herein or
refers to or incorporates this annual report may also contain forward-looking
statements. In this annual report and elsewhere, the words "expects,"
"believes," "anticipates," "estimates," "intends," "plans," "probable" and
variations of such words and similar expressions are intended to identify
forward-looking statements. Such statements necessarily involve risks and
uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that
could cause results to differ are:
o Edison International's and SCE's financial condition, liquidity and credit
ratings have been adversely affected by California's electricity crisis.
Edison International and SCE have entered into a memorandum of
understanding (MOU) with the endorsement of the Governor of California,
which provides a plan for SCE's financial recovery by SCE selling its
transmission assets to an agency of the State of California and issuing
bonds to finance its undercollected power procurement costs, among other
steps. However, the MOU cannot be implemented unless the California
Legislature enacts necessary legislation, the California Public Utilities
Commission (CPUC) and FERC adopt necessary
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orders, and various parties negotiate and execute definitive agreements.
Edison International and SCE cannot be certain that all the required
parties will take the necessary actions.
o Edison International and SCE are seeking to regain investment grade credit
ratings so they can re-enter the credit markets on reasonable terms. The
success of their efforts depends on the implementation of the MOU, which in
turn depends on actions of legislators, regulatory bodies and others.
o SCE is seeking to avoid bankruptcy. To conserve cash, SCE suspended certain
payments for debt service and purchased power. As a result numerous
creditors are suing SCE, and some have threatened the possible filing of an
involuntary bankruptcy petition against SCE. SCE's nonpayment of certain
debt obligations also entitles debtholders to exercise remedies against
Edison International, including possibly accelerating the repayment of
principal.
o The CPUC recently adopted retroactive changes in regulatory accounting
mechanisms and implemented other measures that impair SCE's ability to
recover its costs and investments. As a result, SCE has taken a $2.5
billion ($4.2 billion on a pre-tax basis) fourth quarter write-off of
regulatory assets. The write-off eliminates SCE's retained earnings and
SCE's ability to pay dividends and issue additional first mortgage bonds.
If the MOU described above is implemented or a rate mechanism provided by
legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amounts that were
previously charged against earnings, current accounting standards provide
that a regulatory asset would be reinstated with a corresponding increase
in earnings. But to implement the MOU, SCE will need the cooperation of
legislators, regulators and other parties.
o SCE may be affected by actions of regulatory bodies setting rates, adopting
or modifying cost recovery, accounting or rate-setting mechanisms and
implementing the restructuring of the electric utility industry. For
example, regulatory actions in California affect SCE's ability to recover
its past investments in utility plant and earn competitive returns.
o SCE may be affected by legislative and regulatory measures adopted and
being contemplated by federal and state authorities to address the
California electricity crisis or deregulation in other states, pending
legislation that would repeal or amend key statutes governing the electric
industry.
o SCE may be affected by increased competition in the electric utility
business and other energy-related businesses, including among other things
the ability of customers to purchase energy and metering and billing
services from nonutility energy service providers.
o SCE owns and operates power generation facilities and, therefore, may be
affected by changes in the supply, demand and price for electric capacity
and energy in relevant markets and the cost and availability of fuel and
fuel transportation.
o As an owner-operator of power generation facilities, SCE also may be
affected by unpredictable weather conditions that may affect seasonal
patterns of revenue collection, cause changes in demand (and prices) for
electricity for heating and cooling purposes, and result in higher costs
for repair or maintenance of assets.
o SCE may be affected by financial market conditions such as inflation and
changes in interest rates, which could affect the availability and cost of
external financing, as well as the actions of securities rating agencies.
o SCE is subject to power plant operation risks, including strikes, equipment
failures and other issues.
o SCE may be affected by changes in tax laws or unfavorable interpretation
and application of the laws by tax authorities.
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o The operation of power generation, transmission or distribution facilities
by SCE involves the potential for new or increased environmental
liabilities associated with power plants and other facilities or
operations, resulting from changes in laws, accidents or other events.
o SCE is seeking to create and expand new businesses, such as
telecommunications and other energy-related consumer products and services.
Those businesses are subject to various risks involved with start-up
activities, such as developing products, gaining customers, establishing
management processes, hiring qualified personnel, and so forth.
o SCE may be subject to legal proceedings arising out of financial reporting,
commercial disputes, property rights, personal injuries, and other
circumstances.
Additional information about the risk factors listed above is contained
throughout this annual report. Readers are urged to read this entire report and
carefully consider the risks, uncertainties and other factors that affect SCE's
business. The information contained in this report is subject to change without
notice. Readers should review future reports filed by SCE with the Securities
and Exchange Commission (SEC).
Competitive Environment
SCE operates in a highly regulated environment in which it has an obligation to
deliver electric service to customers in return for an exclusive franchise
within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1994, state lawmakers and
the CPUC initiated the electric industry restructuring process. In 1996, the
California Legislature enacted comprehensive restructuring legislation. SCE was
directed by the CPUC to divest the bulk of its gas-fired generation portfolio.
Furthermore, under the legislation and CPUC decisions, prices for wholesale
purchases of electricity from power suppliers are set by markets while the
retail prices paid by utility customers for electricity delivered to them
remained frozen at June 1996 levels. California's electric utilities, including
SCE, are currently facing a financial and liquidity crisis as a result of the
changes brought about by restructuring. (See Significant Developments in
California Electric Utility Restructuring below for a description of the most
recent developments.)
Significant Developments in California Electric Utility Restructuring
Beginning in May 2000, SCE began experiencing adverse impacts from unusually
high prices for energy and ancillary services procured through the PX and the
ISO. These high wholesale prices, coupled with the freeze on SCE's retail rates
mandated by the 1996 restructuring legislation, resulted in substantial
increases in the amount of undercollections in SCE's transition revenue account
(TRA). SCE's TRA is a regulatory asset account in which SCE records the
difference between revenues received from customers through the frozen rates and
the costs of providing service to customers, (which includes purchased power
procurement costs). As of December 31, 2000, the amount of undercollections
recorded was $4.5 billion. Based on a CPUC decision on March 27, 2001 (see
further discussion below), this overcollection, and SCE's coal and hydroelectric
balancing account undercollections (which amounted to $1.5 billion as of
December 31, 2000), were reclassified. In addition, SCE's transition cost
balancing account (TCBA), representing recovery of stranded costs net of a
previously recorded credit for market valuation of hydroelectric generation
assets and the overcollections in the balancing accounts for the coal and
hydroelectric generating assets, was recalculated to be a $2.9 billion
undercollection.
On April 9, 2001, Edison International, SCE and the CDWR executed a Memorandum
of Understanding (MOU) which sets forth a comprehensive plan calling for
legislation, regulatory action and definitive agreements to resolve important
aspects of the energy crisis, and which, if implemented, is expected to help
restore SCE's creditworthiness and liquidity. The Governor of the State of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. Edison
International, SCE and the CDWR committed in the MOU to proceed in good faith to
sponsor and support the required legislation and to negotiate in good faith the
necessary
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definitive agreements. If required legislation is not adopted and definitive
agreements executed by August 15, 2001, or if the CPUC does not adopt required
implementing decisions by June 8, 2001, the MOU may be terminated by Edison
International, SCE or the CDWR. Neither Edison International nor SCE can provide
assurance that all the required legislation will be enacted, regulatory actions
taken and definitive agreements executed before the applicable deadlines.
Implementation of the MOU, which is discussed in more detail below, will require
numerous actions by the parties and by other California state agencies and the
FERC, and would require significant changes in the regulatory decisions and
other actions discussed below.
The growing undercollections and the concerns of lenders and others that SCE
might not obtain regulatory approval of rate increases sufficient to cover
ongoing procurement costs and recover past costs materially and adversely
affected the liquidity of Edison International and SCE, becoming particularly
pronounced in January 2001. With its revenues providing substantially less cash
flow than needed for power purchases and other ongoing costs, SCE and its parent
company, Edison International, soon had no unused borrowing capacity under their
existing credit facilities and were unable to arrange any additional facilities.
Moreover, Edison International and SCE found themselves unable to issue
commercial paper or otherwise access the capital markets on reasonable terms. To
conserve cash and enable SCE to continue essential business operations, in
mid-January 2001, SCE temporarily suspended the payment of certain obligations
for principal and interest on outstanding debt and for purchased power.
As of March 31, 2001, SCE had $2.7 billion in obligations that were unpaid and
overdue including: (1) $626 million to the PX or the ISO; (2) $1.1 billion to
power producers that are qualifying facilities (QFs); (3) $229 million in PX
energy credits for energy service providers; (4) $506 million of matured
commercial paper; (5) $206 million of principal and interest on its 5-7/8%
notes; and (6) $7 million of other obligations. Unpaid obligations will continue
to accrue interest, as applicable. At March 31, 2001, SCE had estimated cash
reserves of approximately $2.0 billion, which is approximately $700 million less
than its outstanding obligations and preferred stock dividends in arrears. As of
March 31, 2001, the total preferred stock dividends in arrears was $6 million.
The amounts due to the ISO or PX in clause (1) above do not include $275 million
that has been charged back to SCE as a result of defaults in payments by Pacific
Gas and Electric Company (PG&E). SCE has disputed its obligation for such amount
in proceedings before the FERC and on April 6, 2001, the FERC ordered that such
charges be rescinded. As of March 31, 2001, SCE resumed payment of interest on
its debt obligations. Edison International has paid and expects to continue to
pay its obligations, as they are due, subject to obtaining financing. SCE has
repurchased $549 million of pollution control bonds that could not be remarketed
in accordance with their terms. These bonds may be remarketed in the future if
SCE's credit status improves sufficiently.
On March 27, 2001, SCE announced that it will commence payments on deferred
indebtedness. These payments include (1) past due interest on first and
refunding mortgage bonds, Series 93C Due 2026 and Series 93H Due 2004 (which was
paid on March 30, 2001); (2) past due interest on senior unsecured notes, 5-7/8%
Series Due 2001 (which will be paid on April 19, 2001, to holders of record as
of April 9, 2001, in accordance with the applicable indenture); (3) interest on
matured commercial paper; and (4) interest on extendible commercial notes.
Payments on the commercial paper and extendible commercial notes were made on
April 6, 2001, and all interest was brought current to March 31, 2001, for the
commercial paper and March 28, 2001, for the extendible commercial notes.
Payments will also include interest on past due interest. Regular payments will
be resumed on all interest due going forward, including interest payments due
under SCE's bank credit facilities. Interest on commercial paper will be paid
monthly, and interest on the 5-7/8% Series notes will be paid semiannually.
Notices will be provided to holders of the securities about the timing and
amount of the interest payments they will receive. The aggregate amount required
to bring interest payments on outstanding indebtedness current as of March 31,
2001, is approximately $26 million.
On December 14, 2000, following an announcement from the ISO that electricity
generators were refusing to sell into the California market due to concerns
about the financial stability of SCE and Pacific Gas and Electric Company, the
U.S. Secretary of Energy issued an order requiring power generators to make
arrangements to generate and deliver electricity as required by the ISO after
the ISO certifies it has been unable to secure adequate electricity supplies in
the market. After being renewed multiple times, the order
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expired on February 6, 2001. However, on February 7, 2001, a federal court judge
issued a temporary restraining order requiring power suppliers to sell to the
California grid. On February 23, 2001, a federal court judge issued a stay of
litigation in the case of four power suppliers who agreed to extend their power
sales pending a hearing set for March 16, 2001. On March 16, 2001, a federal
court judge put the case on hold until March 20, 2001. On March 21, 2001, a
federal court judge ordered one of the power suppliers to continue to sell power
to the California grid. The three other power suppliers had signed an agreement
with the judge voluntarily agreeing to continue to sell power to the grid while
awaiting a review of the issue by the FERC. On April 6, 2001, the United States
Ninth Circuit Court of Appeals issued a stay order, suspending the lower court's
March 21 order until a final appeals ruling can be issued.
On January 17, 2001, following rolling blackouts in the northern California
service territory of Pacific Gas and Electric Company, California Governor Gray
Davis signed an order declaring an emergency and authorizing the CDWR to
purchase power in order to prevent further blackouts.
Subsequently, on February 1, 2001, Governor Davis signed into law Assembly Bill
(AB) IX, which was passed by the California Legislature as an urgency measure
during a special session and took effect immediately. The new law authorized the
CDWR to enter into contracts to purchase electric power and sell power at cost
directly to retail customers being served by SCE, and authorized the CDWR to
issue revenue bonds to finance electricity purchases. The new law directed the
CPUC to determine the amount of a California Procurement Adjustment (CPA) to
determine further the amount of the CPA allocable to the power sold by the CDWR
which will be payable to the CDWR when received by SCE. On March 7, 2001, the
CPUC issued an interim order in which it held that the CDWR's purchases are not
subject to prudency review by the CPUC, and that the CPUC must approve and
impose, either as a part of existing rates or as additional rates, rates
sufficient to enable the CDWR to recover its revenue requirements.
On March 27, 2001, the CPUC adopted an interim CPA-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh established in the order (based on rates in effect on
January 5, 2001), for each kWh the CDWR sells to SCE's customers. The CPUC
determined that the generation-related component of retail rates should be equal
to the total bundled electric rate (including the 1(cent) per kWh surcharge
adopted by the CPUC on January 4, 2001) less certain non-generation related
rates or charges. For the period January 19 through January 31, 2001, the CPUC
ordered SCE to pay the CDWR at a rate of 6.277 cents per kWh. The CPUC
determined that the company-wide generation-related rate component is 7.277
cents per kWh, (which will increase to 10.277 cents per kWh for electricity
delivered after March 27, 2001, due to the 3 cent surcharge discussed below) for
each kWh delivered to customers beginning February 1, 2001, until more specific
rates are calculated. The CPUC ordered SCE to pay the CDWR within 45 days after
the CDWR supplies power to retail customers. Using these rates, SCE has billed
customers $196 million for energy sales made by CDWR during the period January
19 through March 31, 2001, and has forwarded $52 million to CDWR on behalf of
these customers as of March 31, 2001. In compliance with that same order, SCE is
currently paying the CDWR amounts approximating $2.5 million to $4 million
daily.
In addition, this interim order proposed a method the CPUC will use to calculate
the CPA in accordance with AB 1X and applied the proposed method to propose a
company-wide average CPA rate. Using this rate, the order determined a proposed
CPA revenue amount, to be used by the CDWR to determine the amount of bonds it
may issue. All or a portion of the CPA may be allocated by the CPUC to reimburse
the CDWR for its power purchases on behalf of utility customers.
In an interim order on April 3, 2001, the CPUC adopted the method to calculate
the CPA and then applied that method to calculate a company-wide CPA rate for
each California utility. The CPUC used that rate to determine the CPA revenue
amount which can be used by the CDWR for issuing bonds. The CPUC stated that its
decision is narrowly focused to calculate the maximum amount of bonds that the
CDWR may issue and does not dedicate any particular revenue stream to the CDWR.
The CPUC determined that SCE's CPA rate is 1.120 cents per kWh, which generates
annual revenues of $856.43 million. According to the CPUC's methodology, the
aggregate annual revenues generated by the CPA rates determined for the three
California investor-owned utilities would allow the CDWR to issue up to $13.4
billion of bonds to pay for power purchases by the CDWR under the provisions of
AB 1X. In its
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calculation of the CPA, the CPUC disregarded all the adjustments requested by
SCE in its comments filed on March 29, 2001 (discussed below). As to SCE's
concerns that the CPA may be overstated and could cause deleterious financial
effects on SCE, the CPUC stated that the interim order does not allocate the
CPA, and SCE may comment on the allocation of the CPA at a later time.
SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that it
considers to be reasonably priced, leaving the ISO to purchase in the short-term
market the additional power necessary to meet system requirements. The ISO, in
turn, takes the position that it will charge SCE for the costs of power it
purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions, scheduled or not. In any event, SCE takes the position that it is
not responsible for purchases of power by the CDWR or the ISO from and after
January 18, 2001, the day after the Governor signed the order authorizing the
CDWR to begin purchasing power for utility customers. The MOU contemplates that
the CDWR will assume the entire responsibility for procuring the electricity
needs of SCE's customers through December 31, 2002, to the extent not met by
SCE's retained generation and power contracts. SCE cannot predict the outcome of
any of these proceedings or issues.
In addition to the CPA-related order discussed above, on March 27, 2001, the
CPUC adopted several other significant decisions regarding California's current
energy crisis. These March 27, 2001, decisions deal with complex matters and in
many respects are unclear or ambiguous. Edison International and SCE believe
that in some respects the CPUC's March 27, 2001, decisions are unlawful and
unconstitutional. Many elements of the decisions will be developed further in
ongoing proceedings, the timing of which is uncertain. Furthermore, key
components of the decisions would have to be modified, or the decisions
rescinded, to implement the MOU that Edison International and SCE signed on
April 9, 2001, with the CDWR (discussed below).
In an interim order adopted on March 27, 2001, the CPUC granted SCE and other
California utilities a rate increase in the form of a three-cents per
kilowatt-hour (kWh) surcharge on electricity sold, effective immediately (rate
stabilization decision). However, the three-cent surcharge will not be collected
in rates until the CPUC establishes an appropriate rate design. The CPUC
proposed a tiered rate design in an assigned commissioner's ruling and asked for
comments. The assigned commissioner said the tiered rate design is intended to
encourage conservation by requiring customers to pay more for electricity above
a threshold usage level. The three-cent surcharge will not apply to residential
electricity usage below 130% of baseline rates or to certain low-income
customers. The CPUC will probably hold hearings on the rate design and may not
issue a decision until some time in May 2001. SCE has asked the CPUC to
immediately adopt an interim rate increase that would allow the rate change to
go into effect sooner.
The CPUC stated in its interim order that SCE is to use revenue generated by the
three-cent surcharge to pay power costs incurred after March 27, 2001. SCE must
refund the surcharge to ratepayers if SCE does not properly use it to pay power
costs. If any refunds of power costs are obtained from power generators and
sellers, those refunds will be used to reduce customer rates or to pay power
costs. SCE must also refund the three-cent surcharge to the extend that any
court or administrative body denies refunds from power generators or sellers in
a proceeding where recovery is hampered by lack of cooperation from SCE. The
CPUC also affirmed that an earlier one-cent per kWh surcharge granted on January
4, 2001, is now permanent under California legislation adopted in February 2001,
known as AB 1X. The CPUC stated that revenues from the one-cent surcharge must
be used to pay for power purchases and not for any other costs. The CPUC ordered
that the three-cent surcharge must be added
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to the rate paid to the CDWR to reimburse the CDWR for its costs of purchasing
power for delivery to SCE's customers (see above).
On March 27, 2001, the CPUC also ordered SCE to begin making payments to QFs for
power deliveries on a going forward basis, commencing with April 2001
deliveries. SCE must pay QFs within 15 days of the end of the QF's billing
period, and QFs are allowed to establish 15-day billing periods. The CPUC
provided two special payment options for the month of April only. Failure to
make a payment when due will result in a fine equal to the amount owed. The CPUC
also modified the formula used in calculating payments to most QFs by
substituting natural gas index prices based on deliveries at the Oregon border
in the place of index prices at the Arizona border. The order further revises
other aspects of the payment formula to take into account changes in intrastate
gas transportation costs. SCE anticipates that the changes will probably result
in lower QF energy prices. The changes apply where appropriate regardless of
whether the QF uses natural gas or other resources such as solar or wind.
In its March 27 decisions, the CPUC granted a petition previously filed by The
Utility Reform Network (TURN), a ratepayer advocacy group, that was opposed by
SCE and Pacific Gas and Electric Company. The CPUC directed that the balance in
SCE's TRA, whether positive or negative, be transferred on a monthly basis to
SCE's transition cost balancing account (TCBA), effective retroactively to
January 1, 1998. The TRA is a regulatory asset account in which SCE records the
difference between revenues received from customers through currently frozen
rates and the costs of providing service to customers, including power
procurement costs. The TCBA is a regulatory balancing account that tracks the
recovery of generation-related transition costs, including stranded investments.
The CPUC also ordered SCE to retroactively restate and record balances in its
generation memorandum accounts to the TRA on a monthly basis before any transfer
of generation revenues to the TCBA. SCE believes that this decision by the CPUC
is a fundamental departure from established regulatory accounting and ratemaking
procedures and is unlawful and unconstitutional. SCE believes the CPUC's intent
was to deny SCE lawful recovery of its costs and to artificially extend the end
of the current rate freeze. The CPUC characterized the changes as merely
reducing the prior revenues recorded in the TCBA, thereby affecting only the
amount of transition cost recovery achieved to date. Based upon the transfer of
balances into the TCBA, the CPUC stated that the current rate freeze has not
ended and will not end until the earlier of recovery of all specified transition
costs or March 31, 2002. The CPUC said that any undercollection in the TRA
cannot be recovered after the rate freeze ends. But the CPUC also said that it
will monitor the balances remaining in the TCBA and consider how to address
remaining balances in the ongoing proceedings. If the CPUC does not modify this
decision in a manner consistent with the MOU, SCE intends to challenge this CPUC
decision through all appropriate avenues.
In response to the CPUC's request in the interim CPA-related order, SCE filed
comments on the proposed CPA calculation method on March 29 and April 2, 2001.
In the limited time available to consider the impact of the CPUC's March 27
decisions, SCE estimated that its future revenues will not be sufficient to
cover its own costs of retained generation and power purchases. SCE provided a
forecast showing that the net effect of the rate increases described above, the
decision on QF payments described below, and the payments ordered to be made to
CDWR could result in a shortfall in the CPA calculation of $1.743 billion for
SCE during 2001. SCE further stated that the proposed calculation method does
not properly reflect all relevant generation costs, and that adoption of the
method and later allocation of a portion of the CPA to the CDWR would materially
exacerbate SCE's revenue shortfall. SCE commented that other flaws in the
calculation are that: (1) the proposed CPA is for an indefinite period with no
mechanism for adjustments based on changes in actual costs; (2) it ignores the
potential impact on SCE's costs if the CDWR is not responsible for the full
net-short position; (3) it assumes too low a cost for QF payments (as discussed
below); (4) it may improperly exclude authorized generation-related costs; (5)
it improperly excludes revenues from nuclear incentive pricing; and (6) the
methodology for calculating the CPA is flawed and based on unreasonable
assumptions.
In its comments on the CPUC's methodology for calculating the CPA, SCE also
discussed the QF pricing resulting from the CPUC's March 27 decision on QF
payments. SCE stated that the CPA calculation proposed by the CPUC is based on
an assumed QF price of $80 per MWh, which was a target price in earlier
negotiations with QFs seeking a settlement on lower prices. However, those
negotiations failed.
7
SCE provided to the CPUC a forecast showing that QF prices through the remainder
of 2001, based on the revised formula adopted by the CPUC and independently
forecasted gas prices, will be substantially higher than $80 per MWh.
On April 9, 2001, Edison International and SCE signed a MOU with the CDWR
regarding the California energy crisis and its effects on SCE. California
Governor Gray Davis and his representatives participated in the negotiation of
the MOU, and Governor Davis endorsed implementation of all the elements of the
MOU. The MOU sets forth a comprehensive plan calling for legislation, regulatory
action and definitive agreements to resolve important aspects of the energy
crisis and which, if implemented, is expected to help restore SCE's
creditworthiness and liquidity. Key elements of the MOU include:
o SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate book
value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, then if the State elects,
SCE's hydroelectric assets, and potentially additional rights to output
from other generating stations, may be sold to the State in their place.
SCE will use the proceeds of the sale in excess of book value to reduce its
undercollected costs and retire outstanding debt incurred in financing
those costs. SCE will agree to operate and maintain the transmission assets
for at least three years, for a fee to be negotiated.
o Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the
undercollected amount over the expected gain on sale of SCE's transmission
assets, as well as certain other costs. Such securitization will occur as
soon as reasonably practicable after passage of the necessary legislation
and satisfaction of other conditions of the MOU. The second dedicated rate
component would not be securitized and would not appear in rates unless the
transmission sale failed to close within a two-year period. The second
component is designed to allow SCE to obtain bridge financing of the
portion of the undercollection intended to be recovered through the gain on
the transmission sale.
o SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenues sufficient to cover its costs from January 1, 2001, associated
with the retained generation assets and existing power contracts. The MOU
calls for the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.
o The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are
referred to as SCE's "net short position.") SCE will resume procurement of
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.
o SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2001. Through the same date, a
ratemaking capital structure for SCE will not be established with different
proportions of common equity or preferred equity to debt than set forth in
current authorizations. These measures are intended to enable SCE to
achieve and maintain an investment grade credit rating.
o Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a lesser
amount approved by the CPUC. The equity component of the investments will
be funded from SCE's retained earnings or, if necessary, from equity
investments by Edison International.
8
o An affiliate of Edison International, Edison Mission Energy ("EME") will
execute a contract with the CDWR or another state agency for the provision
of power to the state at cost-based rates for 10 years from a power project
currently under development. EME will use all commercially reasonable
efforts to place the first phase of the project into service before the end
of Summer 2001.
o SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be assigned
to nonprofit entities or certain governmental agencies. SCE will be
permitted to continue utility uses on the subject lands.
o After the other elements of the MOU are implemented, SCE will enter into a
settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.
The parties agree in the MOU that each of its elements is part of an integrated
package, and effectuation of each element will depend upon effectuation of the
others. To implement the MOU, numerous actions must be taken by the parties and
by other agencies of the State of California and the FERC. The California
Legislature must enact legislation to authorize purchase of SCE's transmission
system or other assets, establish the dedicated rate components, authorize
and/or direct the CPUC to take certain actions, and authorize other agreements
and actions. The CPUC must also adopt the dedicated rate components and
financing orders, modify existing decisions, and take various ratemaking and
other actions. The CDWR and other state agencies must enter into definitive
agreements for the purchase of assets from SCE and to embody various other
elements of the MOU. The sale of SCE's transmission system and other elements of
the MOU must be approved by the FERC. Edison International, SCE, and the CDWR
committed in the MOU to proceed in good faith to sponsor and support the
required legislation and to negotiate in good faith the necessary definitive
agreements, and Governor Davis has endorsed the MOU and has agreed to work for
its complete implementation. The California Legislature, the CPUC, the FERC, and
other governmental entities on whose part action will be necessary to implement
the MOU are not parties to the MOU.
The MOU may be terminated by either SCE or CDWR if required legislation is not
adopted and definitive agreements executed by August 15, 2001, or if the CPUC
does not adopt required implementing decisions within 60 days after the MOU was
signed, or if certain other adverse changes occur. Edison International and SCE
cannot provide assurance that all the required legislation will be enacted,
regulatory actions taken, and definitive agreements executed before the
applicable deadlines.
Edison International and SCE believe that the MOU is an important step towards
an acceptable resolution of the major issues affecting Edison International and
SCE as a result of the California energy crisis, including restoring their
creditworthiness and creating a positive framework for future financial
stability, but achievement of those results is not assured. A California voter
initiative or referendum previously has been threatened against any measures
that would raise consumer rates or aid California's investor-owned utilities. In
addition, execution of the MOU does not eliminate the possibility that any of
SCE's creditors could take steps to force SCE into bankruptcy proceedings.
On April 6, 2001, Pacific Gas and Electric Company (PG&E) announced that it had
filed for reorganization under Chapter 11 of the United States Bankruptcy Code.
PG&E said that neither its parent holding company nor any of the parent's other
subsidiaries are affected by PG&E's filing. PG&E cited as reasons for its
bankruptcy filing the failure by the State of California to assume full
procurement responsibility for PG&E's net short position, the CPUC's actions on
March 27 and April 3, 2001, that created new payment obligations for PG&E, lack
of progress in negotiations with the state to provide recovery of power purchase
costs, the CPUC's adoption of an illegal and retroactive accounting change, and
the slow progress of discussions with representatives of Governor Davis (the
actions of the CPUC cited by PG&E are discussed above).
9
SCE is still working to avoid bankruptcy, despite PG&E's announcement that it is
filing for bankruptcy court protection. Edison International and SCE continue to
believe that a comprehensive solution to the current crisis through agreements,
legislation and regulatory actions, as contemplated by the MOU, is a preferable
course of action. Neither Edison International nor SCE can predict the impact of
PG&E's bankruptcy on implementation of the MOU and on Edison International's and
SCE's other efforts to resolve their current financial and liquidity problems.
Regulation
SCE's retail operations are, for the most part, subject to regulation by the
CPUC. The CPUC has the authority to regulate, among other things, retail rates,
issuance of securities, and accounting practices. SCE's wholesale operations are
subject to regulation by the FERC. The FERC has the authority to regulate
wholesale rates as well as other matters, including retail transmission service
pricing, accounting practices, and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the U.S. Nuclear Regulatory Commission
(NRC) with respect to its nuclear power plants. NRC regulations govern the
granting of licenses for the construction and operation of nuclear power plants
and subject those power plants to continuing review and regulation.
The construction, planning, and siting of SCE's power plants within California
are subject to the jurisdiction of the California Energy Commission and the
CPUC. SCE is subject to the rules and regulations of the California Air
Resources Board and local air pollution control districts with respect to the
emission of pollutants into the atmosphere; the regulatory requirements of the
California State Water Resources Control Board and regional boards with respect
to the discharge of pollutants into waters of the state; and the requirements of
the California Department of Toxic Substances Control with respect to handling
and disposal of hazardous materials and wastes. SCE is also subject to
regulation by the Environmental Protection Agency (EPA), which administers
certain federal statutes relating to environmental matters. Other federal,
state, and local laws and regulations relating to environmental protection, land
use, and water rights also affect SCE.
The California Coastal Commission has continuing jurisdiction over the coastal
permit for San Onofre Nuclear Generating Station Units 2 and 3. Although the
units are operating, the permit's mitigation requirements have not yet been
completed. California Coastal Commission jurisdiction may continue for several
years due to implementation and oversight of permit mitigation conditions,
including restoration of wetlands and construction of an artificial reef for
kelp. Additionally, in the summer of 2000, SCE applied for a coastal permit to
construct a dry cask spent fuel storage installation for Units 2 and 3. This
permit application was approved, with certain conditions, by the California
Coastal Commission at its meeting on March 13, 2001.
The U.S. Department of Energy has regulatory authority over certain aspects of
SCE's operations and business relating to energy conservation, power plant fuel
use and disposal, electric sales for export, public utility regulatory policy,
and natural gas pricing.
In 1997, the CPUC adopted a decision which established new rules governing the
relationship between California's natural gas local distribution companies,
electric utilities, and certain of their affiliates. While SCE and its
affiliates have been subject to affiliate transaction rules since the
establishment of its holding company structure in 1988, these new rules are more
detailed and restrictive. As required by the new rules and an interim CPUC
resolution, SCE has filed preliminary and revised compliance plans which set
forth SCE's implementation of the new affiliate transaction rules. The CPUC has
not yet ruled on the sufficiency of SCE's October 1998 revised compliance plan.
In January 2001, the CPUC issued an Order Instituting Rulemaking to commence the
review of the 1997 Affiliate Transaction Rules that the original decision itself
requires. The CPUC proposes that some rules be considered for streamlining or
other revision, while inviting interested parties to submit proposals of their
own. No decision is expected before the end of the year 2001 at the earliest.
10
On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the CPUC in public filings about
SCE's financial condition. The audit report covers, among other things, cash
needs, credit relationships, accounting mechanisms to track stranded cost
recovery, the flow of funds between SCE and Edison International, and earnings
of SCE's California affiliates. On March 15, 2001, the CPUC released a draft of
a proposed order instituting investigation.
At its March 27, 2000, meeting, the CPUC deferred action on a proposed order
instituting an investigation whether California's investor-owned utilities,
including SCE, have complied with past CPUC decisions authorizing the formation
of their holding companies and governing affiliate transactions, as well as
applicable statutes. On March 29, 2001, an assigned commissioner's ruling was
issued that requires Edison International and SCE to respond within 10 days to
document requests and questions that are identical to document requests and
questions included in the proposed order instituting investigation. At its
meeting on April 3, 2001, the CPUC adopted the proposed order. The order reopens
past CPUC decisions authorizing the utilities to form holding companies and
initiates an investigation into (1) whether the holding companies violated
requirements to give priority to the capital needs of their respective utility
subsidiaries; (2) whether "ring fencing" actions by Edison International and
PG&E Corporation and their respective nonutility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries; (3) whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were
comparable stand-alone utility companies; (4) any additional suspected
violations of laws or CPUC rules and decisions; and (5) whether additional
rules, conditions, or other changes to the holding company decisions are
necessary. The MOU signed on April 9, 2001, with the CDWR calls for the CPUC to
adopt a decision clarifying that the "first priority" condition in SCE's holding
company decision refers to equity investment, not working capital for operating
costs. Neither Edison International nor SCE can provide assurance that the CPUC
will adopt such a decision, or predict what effects the investigation or any
subsequent actions by the CPUC may have on either of them.
Changing Regulatory Environment
SCE currently operates in a highly regulated environment in which it has an
obligation to deliver electric service to customers in return for an exclusive
franchise within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1994, state lawmakers and
the CPUC initiated the electric industry restructuring process. In 1996, the
California Legislature enacted comprehensive restructuring legislation. SCE was
directed by the CPUC to divest the bulk of its generation portfolio. Today,
those generating plants are owned by independent power companies. Along with
electric industry restructuring, a mandated multi-year freeze on the rates that
SCE could charge its customers was mandated and transition cost recovery
mechanisms allowing SCE to recover its stranded costs associated with
generation-related assets were implemented.
As described above, skyrocketing wholesale energy pricing and resulting
liquidity pressures placed upon SCE and other investor-owned utilities has
caused the restructuring process to change significantly as California adopted
short-term measures, and works to develop longer-term solutions, to address the
energy crisis. SCE's remaining generation portfolio was impacted by California
state legislation enacted in January 2001 barring the sale of utility generating
facilities, including SCE's Mohave, Palo Verde and Four Corners generating
facilities, until 2006. Under the MOU, SCE would continue to own its share of
these generating assets, which would be subject to cost-based ratemaking,
through 2010. SCE's efforts to recover its transition and power procurement
costs associated with restructuring are described below under Recovery of
Transition and Power Procurement Costs.
Recovery of Transition and Power Procurement Costs
SCE's transition costs included power purchases from QF contracts (which are the
direct result of prior legislative and regulatory mandates), recovery of certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the
11
recovery of income tax benefits previously flowed through to customers,
postretirement benefit transition costs, accelerated recovery of investment in
San Onofre Units 2 and 3 and the Palo Verde units, and certain other costs.
Transition costs related to power-purchase contracts are being recovered through
the terms of each contract. The CPUC decisions provide that most of the
remaining transition costs are subject to recovery only through the end of the
transition period (not later than March 31, 2002). Although the MOU provides
for, among other things, SCE to be entitled to sufficient revenue to cover its
costs from January 2001 associated with retaining generation and existing power
contracts, the implementation of the MOU requires the CPUC to modify various
decisions. Because of the CPUC's decisions on and after March 27, 2001,
including the retroactive transfer of balances from SCE's TRA to its TCBA and
related changes and other regulatory and legislative actions (see discussion in
the Significant Developments in California Electric Utility Restructuring
above), SCE is not able to conclude that the regulatory assets and liabilities
related to purchased-power settlements, the unamortized loss on SCE's generating
plant sales in 1998, and various other regulatory assets and liabilities
(including income taxes previously flowed through to customers) related to
certain generating assets are probable of recovery through the rate-making
process. As a result, these balances were written off as a charge to earnings as
of December 31, 2000. If the MOU is implemented, or a rate mechanism provided by
legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings.
During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: competition transition charge (CTC) revenue,
revenue from the sale or valuation of generation assets in excess of book
values, and net market revenue from the sale of SCE-controlled generation into
the ISO and PX markets. However, due to the events discussed above (see
Significant Developments in California Electric Utility Restructuring), revenue
from the sale of SCE generation into the ISO and PX markets and from the sale or
valuation of generation assets in excess of book values (prohibited by state
legislation enacted in January 2001) is no longer available to SCE. CTC revenue
is determined residually (i.e., CTC revenue is the residual amount remaining
from monthly gross customer revenue under the rate freeze after subtracting the
revenue requirements for transmission, distribution, nuclear decommissioning and
public benefit programs, and ISO payments and power purchases from the PX and
ISO). The CTC applies to all customers who were using or began using utility
services on or after the CPUC's 1995 restructuring decision date. Residual CTC
revenue is calculated through the TRA mechanism.
Beginning in May 2000, SCE experienced adverse impacts from high prices for
energy and ancillary services procured through the PX and ISO. These high
wholesale prices, coupled with the current freeze on SCE's rates, resulted in
substantial increases in the amount of undercollections in SCE's TRA, reaching
$4.5 billion as of December 31, 2000. Additional information about the financial
impact of this undercollection and various ongoing and proposed legislative and
regulatory efforts and judicial proceedings designed to address or otherwise
relating to it, is provided in Management's Discussion and Analysis in SCE's
Annual Report to Shareholders for the year ended December 31, 2000 (Annual
Report), under Regulatory Environment - Status of Transition and Power
Procurement Costs Recovery section incorporated herein by reference pursuant to
General Instruction G(2).
Rate Reduction Notes
In December 1997, after receiving approval from the CPUC and the California
Infrastructure and Economic Development Bank, a limited liability company
created by SCE issued approximately $2.5 billion of rate reduction notes.
Residential and small commercial customers, whose 10% rate reduction began
January 1, 1998, are repaying the notes over the expected ten-year term through
non-bypassable charges based on electricity consumption. There were originally
seven classes of notes. The first class, in the amount of $246.3 million,
matured in December 1998, and the second class in the amount of $307.3 million
matured in March 2000. The remaining Notes consist of five classes with
scheduled maturities beginning in 2001 and ending in 2007, with interest rates
ranging from 6.17% to 6.42%.
12
Other Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation:
distribution, transmission and generation. Moreover, in response to the
above-referenced skyrocketing wholesale energy pricing, SCE has initiated rate
stabilization proceedings at the CPUC. In addition, SCE jointly petitioned the
FERC to find that the California wholesale electricity market was not workably
competitive, to immediately impose a price cap for energy and ancillary
services, and to take other responsive measures.
Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend through December 2001. Key elements of the distribution PBR include:
distribution rates indexed for inflation based on the Consumer Price Index less
a productivity factor; adjustments for cost changes that are not within SCE's
control; a cost-of-capital trigger mechanism based on changes in a utility bond
index; standards for customer satisfaction; service reliability and safety; and
a net revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from distribution operations.
Transmission revenue is being determined through the FERC-authorized rates that
are subject to refund. Since the initiation of the ISO in April 1998,
transmission cost recovery has been under FERC authority. In July 2000, FERC
issued a final decision in SCE's 1998 FERC transmission rate case in which it
ordered a reduction of approximately $38 million to SCE's proposed annual base
transmission revenue requirement of $213 million. Of the total reduction of $38
million, about $24 million is associated with the rejection by FERC of SCE's
proposed method for allocating overhead costs to transmission operations. SCE
filed a Conditional Petition for Rehearing of the decision in August 2000,
asking that FERC reconsider the decision assuming that the CPUC does not allow
SCE to recover the $24 million in CPUC jurisdictional rates. In February 2001,
SCE filed with the CPUC a request to recover in CPUC-jurisdictional rates the
overhead costs not permitted by FERC to be included in transmission rates. A
CPUC decision is not expected until late in 2001. In the meantime, SCE continues
to collect transmission revenues based on the originally proposed $213 million
level, subject to refund pending final resolution of the 1998 rate case. SCE
expects that any refund amounts ultimately ordered by FERC associated with
transmission will not be refunded to retail customers but will be credited
against the amount of accrued transition/procurement costs.
Effective with the commencement of the ISO and PX operations on March 31, 1998,
generation costs were subject to recovery through the market and transition cost
recovery mechanisms, which included the nuclear rate-making agreements. During
the rate freeze, revenue from generation-related operations has been determined
through the market and transition cost recovery mechanisms, which included the
nuclear rate-making agreements. The portion of revenue related to coal
generation plant costs (Mohave Generating Station and Four Corners Generating
Station) that were made uneconomic by electric industry restructuring has been
recovered through the transition cost recovery mechanisms. After April 1, 1998,
coal generation operating costs have been recovered through the market. The
excess of power sales revenue from the coal generating plants over the plants'
operating costs has been accumulated in a coal generation balancing account.
SCE's costs associated with its hydroelectric plants have been recovered through
a performance-based mechanism. The mechanism set the hydroelectric revenue
requirement and established a formula for extending it through the duration of
the electric industry restructuring transition period, or until market valuation
of the hydroelectric facilities, whichever occurred first. The mechanism
provided that power sales revenue from hydroelectric facilities in excess of the
hydroelectric revenue requirement is accumulated in a hydroelectric balancing
account. In accordance with a CPUC decision issued in 1997, the credit balances
in the coal and hydroelectric balancing accounts were transferred to the TCBA at
the end of 1998 and 1999. However, due to the CPUC's March 27, 2001, rate
stabilization decision, the credit balances in these balancing accounts have now
been transferred to the TRA on a monthly basis, retroactive to January 1, 1998.
In addition, the TRA balance, whether over- or undercollected, has now been
transferred to the TCBA on a monthly basis, retroactive to January 1, 1998. Due
to a December 15, 2000, FERC order, SCE is no longer required to buy and sell
power exclusively through the ISO and PX. In mid-January 2001, the PX suspended
SCE's trading privileges for failure to post collateral due to SCE's rating
agency downgrades. As a result, power from SCE's coal and hydroelectric plants
is no longer being sold through the market and these two balancing accounts have
13
become inactive. As a key element of the MOU, SCE would continue to own its
generation assets, which would be subject to cost-based ratemaking, through
2010. The MOU calls for the CPUC to adopt cost recovery mechanisms consistent
with SCE obtaining and maintaining an investment grade credit rating.
In 1999, SCE filed an application with the CPUC proposing for purposes of the
application a market value for its hydroelectric generation-related assets at
approximately $1.0 billion (almost twice the assets' book value) and proposing
to retain and operate the hydroelectric assets under a performance-based,
revenue-sharing mechanism. Under the MOU, SCE would withdraw this application,
and would continue to operate the hydroelectric assets under cost-based
ratemaking, through 2010.
In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48%
interest in Four Corners Generating Station to Pinnacle West Energy (PWE) for
$550 million, subject to certain adjustments. The transaction remained subject
to the approval of the CPUC, the NRC, the FERC and other state and federal
entities, and to the receipt of a favorable ruling from the Internal Revenue
Service. In January 2001, California state legislation was enacted which bars
the sale of utility generating facilities, including SCE's Palo Verde and Four
Corners generating facilities, until 2006. Under the MOU, SCE would withdraw its
application to sell these generation interests and would continue to own its
generating assets, which would be subject to cost-based ratemaking, through
2010.
In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. In light of its
four-point market reform proposal of October 2000, on November 16, 2000, SCE
filed a rate stabilization plan with the CPUC seeking, among other things, a
9.9% rate increase for all customers (excluding low-income customers whose
increase would be 4.95%) for a two-year period beginning January 1, 2001.
Hearings were held in late December 2000 and on January 4, 2001, and the CPUC
issued an interim decision authorizing SCE to establish an interim surcharge of
1(cent) per kilowatt-hour for 90 days, subject to refund. The revenue from the
surcharge is being tracked through a balancing account and applied to ongoing
power procurement costs. The surcharge resulted in rate increases, on average,
of approximately 7% to 25%, depending on the class of customer. As noted in the
decision, the 90-day period allowed independent auditors engaged by the CPUC to
perform a comprehensive review of SCE's financial position, as well as that of
Edison International and other affiliates.
In its interim rate stabilization order adopted on March 27, 2001, the CPUC
granted SCE a rate increase in the form of a 3(cent) per kWh surcharge applied
only to electric power costs, effective immediately, and affirmed that the
1(cent) interim surcharge granted on January 4, 2001, is now permanent. Also, in
the interim order, the CPUC granted a petition previously filed by TURN and
directed that the balance in SCE's TRA, over- or undercollected, be transferred
on a monthly basis to the TCBA, retroactive to January 1, 1998, (see Significant
Developments in California Electric Utility Restructuring).
In October 2000, SCE filed a joint petition urging the FERC to immediately find
the California wholesale electricity market to be not workably competitive;
immediately impose a cap on the price for energy and ancillary services; and
institute further expedited proceedings regarding the market failure, mitigation
of market power, structural solutions and responsibility for refunds. On
December 15, 2000, the FERC released a final order containing remedies and other
actions in response to the problems in the California electricity market. On
December 26, 2000, SCE filed an emergency petition in the federal Court of
Appeals challenging the FERC order and seeking a writ of mandamus requiring the
FERC to immediately establish cost-based wholesale rates. On January 5, 2001,
the Court denied SCE's petition. The effect of the denial is to leave in place
the FERC's market mechanisms. SCE's petition for rehearing remains pending.
In November 2000, SCE filed with the CPUC a request for approval to credit the
TCBA (and debit the Generation Asset Balancing Account) as soon as possible with
the aggregate net gain on the pending sales of the Mohave, Four Corners and Palo
Verde generation plants, which would have the effect of substantially
accelerating the end of SCE's statutory rate freeze. The CPUC dismissed the
request without full proceedings on the grounds that it was premature. Due to
events discussed above in Significant Developments in California Electric
Utility Restructuring (State legislation enacted in
14
January 2001 bars the sale or valuation of SCE's remaining generation assets
until 2006), revenue from the sale of generation assets in excess of book values
is no longer available to SCE. Additionally, as indicated above, under the MOU
SCE would continue to own its generating assets, which would be subject to
cost-based ratemaking, through 2010.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69
million or submit cost-of-service information to the FERC to justify their
prices above $273/MWh during ISO Stage 3 emergencies in January 2001. On April
9, 2001, SCE filed opposing the order as inadequate, particularly because the
FERC is unwilling to exercise any control over the sellers' exercise of market
power during periods other than Stage 3 emergencies. On March 16, 2001, the FERC
ordered six wholesale sellers of energy to refund an additional $55 million or
submit cost-of-service information to the FERC to justify their prices above
$430/MWh during ISO Stage 3 emergencies in February 2001. A Stage 3 emergency
refers to 1.5% or less in reserve power, which could trigger rotating blackouts
in some neighborhoods.
See Regulatory Environment - Generation and Power Procurement and Regulatory
Environment - Rate Stabilization Proceeding sections of the Management's
Discussion and Analysis in the Annual Report, incorporated herein by reference
pursuant to General Instruction G(2), for more information about SCE's revenue
from its generation-related operations, recovery of its investment in its
nuclear facilities, market valuation of its hydroelectric generation-related
assets, the proposed sales of its interests in the Palo Verde and Four Corners
generating facilities, rate stabilization proceedings before the CPUC and its
FERC petition seeking specific regulatory responses to the wholesale energy
market dysfunction, and on accounting for generation-related assets and power
procurement costs.
Restructuring Implementation Costs
In May 1998, SCE filed an application with the CPUC to identify the categories
of restructuring implementation costs (including costs related to the start-up
and development of both the PX and ISO, and related to the implementation of
direct access) and to establish the reasonableness of those costs incurred in
1997. In September 1999, the CPUC approved a settlement agreement between SCE,
the Office of Ratepayer Advocates (ORA) and several other parties allowing SCE
to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would no longer be allowed to recover these transition costs
under restructuring legislation.
Market Risk Exposures
In 1997, SCE bought gas call options to mitigate its transition cost recovery
exposure to increases in energy costs. In October 2000, SCE sold its remaining
options; the gains were credited to the TCBA. In July 1999, SCE began
participating in forward purchases through a PX block forward market. Initially,
the only product available in the PX block forward market provided a monthly
block of energy delivered six days a week (excluding Sundays and holidays), 16
hours a day. The CPUC originally limited SCE's use of the PX block forward
market to a maximum of approximately 2,000 MW in any month. The PX requested and
was granted authority from the FERC to sell other forward products including a
peak product that specified power delivery six days a week, eight hours a day
(excluding holidays). In March 2000, the CPUC approved SCE's request for
rate-making treatment for its use of these additional products and for an
expansion of the limits from all forward PX products up to 5,200 MW in summer
months. In April 2000, the CPUC approved SCE's request to begin a demand
responsiveness program that would allow customers to be paid to curtail their
load during times of very high PX energy prices. In August 2000, the CPUC
approved SCE's request to enter into bilateral power contracts. The CPUC
approval limited the quantity of power that could be contracted for, required
pre-approval for contracts extending beyond 2002, and required that all
contracts expire on or before December 31, 2005. SCE entered into bilateral
power contracts in November 2000. On December 31, 2000, the "mark-to-market"
value of SCE's block-forward and bilateral forward contracts (market value of
the contracted power less the contract cost) was $424 million and $398 million,
respectively. During the last eight months of 2000, SCE experienced
significantly
15
higher PX purchased-power expenses despite savings of $684 million realized from
its power hedging contracts over that period.
On February 2, 2001, the State of California seized SCE's block forward
contracts. Under law, the State must compensate SCE for the reasonable value of
the contracts. The PX has indicated that it will also seek to recover the monies
SCE owes to the PX from any proceeds from the contracts. On or about February
26, 2001, SCE filed a claim against the State Board of Control (now known as the
California Victim Compensation and Government Claims Board) seeking recovery of
damages incurred as a result of the State's seizure of the block forward
contracts. SCE has also notified Governor Gray Davis of SCE's intention to
pursue a claim for damages. The Board has yet to respond to SCE's claim. The
MOU, if implemented, calls for settlement of SCE's claim relating to these block
forward contracts.
Other Rate Matters
CPUC Retail Ratemaking
The CPUC regulates the charges for services provided by SCE to its retail
customers. As discussed above in the section on Changing Regulatory Environment,
the way in which the CPUC regulates SCE is changing. The CPUC has issued both
final and interim decisions regarding direct access, transition cost recovery,
and rate unbundling in the restructuring of the electric industry. While some of
them (such as those regarding transition cost recovery) are being challenged by
SCE both before the CPUC as well as in judicial proceedings, the above decisions
have affected cost recovery and rate regulation, and authorized new ratemaking
mechanisms which were implemented, replacing the Electric Revenue Adjustment
Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates mechanism
(pre-restructuring ratemaking mechanisms) as of January 1, 1998.
Under the restructuring legislation, total rates for all customers were frozen
at June 10, 1996, levels, although residential and small commercial customers
received a 10% reduction from the June 10, 1996, rate levels beginning on
January 1, 1998. These rate levels were to remain in effect for the remainder of
the transition period; however, on January 4, 2001, the CPUC issued an interim
decision authorizing SCE to establish an interim surcharge of 1(cent) per
kilowatt-hour for 90 days, subject to refund. This was followed by the CPUC's
interim rate stabilization order adopted on March 27, 2001 (see Other Revenue
and Cost Recovery Mechanisms). Under these frozen rates, individual rate
components (distribution, transmission, nuclear decommissioning, and public
purpose programs) are determined according to CPUC- or FERC-authorized
mechanisms, with the generation rate determined residually by subtracting these
other components from the total rate. Beginning for rates effective in 1999, the
consolidation of the individual rate component changes and the calculation of
the residual generation rate are set forth for CPUC approval as part of the
Revenue Adjustment Proceeding (RAP). On June 1, 1998, SCE filed its first annual
RAP Report in compliance with CPUC directives to: (1) consolidate authorized
rates and revenue requirements associated with various proceedings and
mechanisms; (2) verify the residual CTC revenue calculation in the TRA; (3)
verify the regulatory account balances which were transferred to the TCBA on
January 1, 1998 (see Annual Transition Cost Proceeding below for further
discussion of the TCBA); (4) streamline certain balancing and memorandum
accounts; and (5) review the PX charge/credit calculation. On June 6, 1999, the
CPUC issued its final 1998 RAP decision. In compliance with that decision, SCE
updated its nongeneration rate components in October 1999. To maintain overall
frozen rate levels, to the extent nongeneration rate components are authorized
to change, the generation rate component changes equal and opposite from the
nongeneration rate component changes. The decision also instructed SCE to
include in the 1999 RAP Report a PX credit calculation that reflects the
long-run marginal costs of customer account managers, customer service
representatives, self-provision of ancillary services, and financing costs for
purchasing power from the PX.
In June 1999, the CPUC issued a decision regarding unbundling SCE's cost of
capital based on major utility functions. The decision was in response to SCE's
May 1998 application on this issue. The CPUC found no unbundling adjustment was
required in setting 1999 cost of capital for the California electric
16
utilities. Furthermore, the CPUC ruled that SCE's rate of return should continue
to be governed by the cost of capital trigger mechanism authorized as part of
SCE's performance-based ratemaking mechanism. (See discussion under Other
Revenue and Cost-Recovery Mechanisms.) As a result, SCE's return on equity for
1999 was unchanged at 11.6%.
On August 9, 1999, SCE filed its 1999 RAP Report requesting CPUC approval of the
following: (1) consolidation of the 2000 nongeneration revenue requirements; (2)
rate levels for 2000, including the residually determined generation rates; (3)
2000 kWh sales forecast; (4) entries to the TRA for the period June 1, 1998,
through May 31, 1999; (5) proposed retention, elimination, and modification of
balancing and memorandum accounts; (6) implementation and costs of electric
vehicle programs during the record period; (7) administration of SCE's
self-generation deferral rate contracts during the record period; and (8) the
proposed additional .007/kWh (7 cents/MWh) credit to direct access customers
associated with SCE's procurement of PX energy for bundled service customers.
The most hotly contested issue was the computation of the PX Credit Adder
intended to reflect each utility's long-run marginal cost of power procurement.
On August 2, 2000, two proposed decisions (PDs) were issued - a PD of ALJ
Barnett and an Alternate PD of Commissioner Neeper. ALJ Barnett adopted for all
three investor-owned utilities a PX Credit Adder of .007 cents per kWh (7 cents
per MWh). This is the PX Credit Adder that SCE had proposed. ALJ Barnett adopted
all of SCE's arguments on long-run marginal cost and used SCE's formulation of
the PX credit as a model for the other utilities. Commissioner Neeper adopted,
and later through a revised PD modified, a different PX Credit Adder. A revised
Alternate PD by Commissioner Bilas proposing yet another PX Credit Adder was
issued on November 6, 2000. Like other Alternates, it relied on the "average
cost" methodology of the ORA. On January 4, 2001, the PD of ALJ Barnett was
adopted by the CPUC. The decision put SCE on notice that it will no longer be
able to prospectively recover 100% of its reliability must-run costs in the TRA.
The decision adopted all other RAP issues SCE requested.
Nuclear Decommissioning and Public Purpose Program Rates
Recovery of SCE's nuclear decommissioning costs and legislatively mandated
public purpose program funding is made through rates set to recover 100% of
these costs. Public purpose programs include cost effective energy efficiency,
research, renewable technology development, and low income programs.
Annual Transition Cost Proceedings (ATCP)
In 1997, the CPUC established the ATCP to determine whether SCE's TCBA entries
are recorded pursuant to applicable CPUC decisions and the restructuring
legislation, and whether certain expenses are justified. The purpose of the ATCP
is to ensure the recovery of generation-related transition costs through the
TCBA that complies with the guidelines established by the CPUC. The TCBA tracks
the recovery of transition costs, including the accelerated recovery of plant
balances, QF and purchased power costs, and regulatory assets and obligations.
1998 ATCP
On September 1, 1998, SCE filed its first ATCP Report with the CPUC and
requested, among other things, that entries made to the TCBA and applicable
generation-related memorandum accounts during the record period of January 1,
1998, through June 30, 1998, be found to be justified and in compliance with
applicable CPUC decisions and the restructuring legislation. On March 31, 1999,
the ORA submitted its report and made the following recommendations adverse to
SCE: (1) $2.37 million in QF shareholder incentive amounts should be disallowed;
(2) $3.2 million in employee-related transition costs should be disallowed; and
(3) $9.67 million in post-retirement benefits other than pensions (PBOPs) and
$5.76 million in long-term disability regulatory assets should be rejected. On
June 14, 1999, the ALJ granted SCE's motion to strike the ORA's testimony and
recommendations on the third item. Prior to hearings, the ORA and SCE
recommended that the CPUC adopt a stipulation and joint recommendation
17
whereby SCE would not recover $895,000 in retention bonuses, and $1.19 million
of the total QF shareholder incentive amounts. On October 8, 1999, the matter
was submitted to the CPUC.
On January 6, 2000, an ALJ issued a proposed decision adopting the stipulation
and joint recommendation as specified above. In addition, the proposed decision
provided clarification on the following four accounting issues impacting the
operation of the TCBA: (1) It directs SCE and the other utilities to review
their estimates of market value for each divested generating plant and
recalculate the interest accrued on undercollections of the TCBA during the
record period. SCE believes it used the market value accounting directed by the
proposed decision; (2) It clarifies the accounting methodology used to estimate
the market value of retained generating assets. At this time, SCE believes there
will be no negative impact on earnings associated with this issue; (3) It
directs SCE to apply the TCBA overcollection of $350.7 million as of June 30,
1998, to further accelerate the depreciation of those transition cost assets
with the highest rate of return, and in a manner that provides the greater tax
benefits (i.e., to accelerate the recovery of nuclear sunk costs). It also
directs SCE to net a $238 million undercollection in the ISO/PX implementation
delay memorandum account against the TCBA overcollection in the calculation. SCE
estimates a $10 million impact over the entire transition period ending December
31, 2001, if this accounting change is adopted by the CPUC; and (4) It disallows
the recovery through the TCBA for the record period of certain
telecommunications, training, mechanical service shop and warehouse equipment
that were related to SCE's divested generating plants but was not purchased by
the new owners. The net book value of these retained assets is in the $8 million
to $10 million range. Comments to the proposed decision were filed in January
and a supplemental brief was filed on February 1, 2000.
On February 17, 2000, the ALJ prepared a revised proposed decision that
addressed these four matters and left intact other provisions of the proposed
decision. The revised proposed decision was approved by the CPUC on the same
day. The decision found that SCE's calculation of the TCBA for the record period
was correct and that SCE appropriately applied the overcollection as of June 30,
1998, to the subsequent undercollection. Therefore, the decision does not
require SCE to accelerate recovery of its nuclear assets. The decision changes
the accounting methodology used to estimate the market value of retained
generating assets and requires that SCE credit the TCBA for the aggregate net
book value of SCE's non-nuclear assets, including the land surrounding such
assets. SCE's shares of the Mohave Station and Four Corners Generating Station
(Four Corners) are excluded from this requirement. Ongoing depreciation, taxes,
and return will be recovered through market revenue. The decision disallows the
recovery through the TCBA for the record period of the retained assets but does
not preclude SCE from seeking recovery in future record periods. The
disallowance for the 1998 record period was $55,000.
On February 29, 2000, SCE made a request to the CPUC's Executive Director for an
extension of time to file the compliance advice letter so that the CPUC could
review SCE's soon-to-be filed petition for a stay of the decision, application
for rehearing and/or petition for modification of the decision. In a letter
dated March 3, 2000, the Executive Director granted SCE an extension of time
until May 31, 2000, to file its advice letter compliance filing.
Once SCE had the opportunity to fully review the decision adopted by the CPUC,
it discovered that the revisions by the CPUC in response to the parties'
comments had inadvertently omitted establishing a new account to record the
corresponding debit to the TCBA credit for the aggregate net book value of any
remaining non-nuclear generation assets. SCE immediately informed the Assigned
Commissioner of the omission, and the Assigned Commissioner issued on March 2,
2000, an Assigned Commissioner's Ruling (ACR) proposing the CPUC establish a
generation asset memorandum account to record this debit. If no debit account
was established by the CPUC, any offsetting debit would be considered as a $300
million charge to earnings on an after tax basis.
In its comments to the ACR, SCE proposed that this account be established as a
balancing account, the Generation Asset Balancing Account, or GABA, in order to
avoid problems associated with limits for short-term borrowing purposes. The
CPUC agreed, and on June 8, 2000, established the GABA. SCE filed its
18
compliance advice letter in June 2000. On April 13, 2000, SCE filed a petition
for modification seeking modification of the decision to restore recovery of
authorized return, taxes, and depreciation for its hydro assets through the
TCBA. It is not known when the CPUC will act on SCE's petition for modification.
On November 9, 2000, SCE filed a petition for modification of D.00-02-048
requesting the CPUC to allow SCE to credit its TCBA (and debit its GABA) with
the aggregate net above-book gain reflected in the pending sales of SCE's
interest in Mohave, Four Corners and Palo Verde generating plants. Crediting
these amounts to the TCBA would allow SCE to accelerate the end of its rate
freeze as requested in SCE's Rate Stabilization Application, A.00-11-038 (as
revised on December 20, 2000).
1999 ATCP
On September 1, 1999, SCE filed its 1999 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1998 through
June 1999. On February 23, 2000, the ORA issued its report and made the
following disallowance recommendations adverse to SCE: (1) approximately $5.5
million in post-record period adjustments booked after the date of divestiture
for capital additions made in 1996 to divested fossil generating plants that was
transferred to the TCBA; (2) $17.2 million related to the termination contract
with the Sacramento Municipal Utility District (SMUD); (3) $252,000 in
employee-related transition costs; and (4) a $136,000 adjustment to the QF
subaccount of the TCBA. SCE served its rebuttal testimony on March 29, 2000, and
supplemental testimony on April 3, 2000. Prior to hearings, ORA and SCE executed
a Settlement Agreement that resolved all issues associated with SCE's filing.
The parties agreed that (1) SCE made the $5.5 million adjustment and a $136,000
adjustment to the TCBA as referred to above; (2) ORA no longer contests the
reasonableness of SCE's termination contracts with SMUD; and (3) $192,000 in
employee-related transition costs are to be disallowed. In the settlement, the
parties agree that the Union Worker Protection Benefit (WPB) Agreements were
reviewed for reasonableness by ORA in this proceeding and that the programs and
benefits in each of the WPB Agreements are reasonable and qualify for recovery
as transition costs through the TCBA. On October 19, 2000, the CPUC issued its
decision that approved the Settlement Agreement, closing this proceeding.
2000 ATCP
On September 1, 2000, SCE filed its 2000 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1999 through
June 2000. ORA issued its report on February 27, 2001. In its report, ORA
recommended, among other things, that the Commission: (1) defer review of SCE's
natural gas procurement and management activities, including a $10 million post
record period adjustment, until the 2001 ATCP; (2) disallow $882,000 of
employee-related transition costs; and (3) adjust the TCBA undercollection
downward $4.35 million to reflect the reasonableness of post record period
adjustments. On March 15, 2001, in response to SCE's First Set of Data Requests
based on ORA's Report, ORA withdrew its recommendation to defer its review of
SCE's natural gas procurement and management activities, including a $10,000,000
gas options post-record period adjustment, until the 2001 ATCP. ORA found the
$10,000,000 post-period adjustment to be reasonable as well as SCE's natural gas
procurement and management activities during the record period with respect to
the El Paso contract. Since ORA no longer objects to the $10,000,000 gas options
post-record period adjustment, ORA no longer recommends that the TCBA needs to
be further adjusted and now agrees with SCE's June 30, 2000, TCBA balance. The
only contested issue that remains is the $882,000 in employee-related transition
costs. SCE's rebuttal testimony was mailed on March 27, 2001, and hearings are
scheduled for May 21 through May 25, 2001.
Annual Energy Cost Adjustment Clause (ECAC) Proceedings
Through 1998, SCE filed ECAC applications each year with the CPUC regarding its
fuel and purchased power expenses, seeking the CPUC's determination that SCE's
fuel and purchased power costs, including payments to QFs, were reasonable. The
last ECAC application filed in 1998 was closed in 1999. The
19
ECAC reasonableness revision of certain costs, including QF payments, is now
reviewed in the ATCP proceedings discussed above.
Palo Verde Nuclear Generating Station
In January 1997, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $1.2 billion in Palo Verde Units 1, 2, and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. The future operating costs, including nuclear fuel and nuclear
fuel financing costs, and incremental capital expenditures, are subject to
balancing account treatment through 2001. Beginning January 1, 1998, the
balancing account became part of the TCBA mechanism. The existing NUIP will
continue only for purposes of calculating a reward for performance of any unit
above an 80% capacity factor for a fuel cycle. These rate-making plans and the
TCBA mechanism will continue for rate-making purposes through the end of the
rate freeze period. However, due to the various unresolved regulatory and
legislative issues (see discussion in the Significant Developments in California
Electric Utility Restructuring above), SCE is not able to conclude that the
unamortized nuclear investment regulatory assets are probable of recovery
through the rate-making process. As a result, these balances were written off as
a charge to earnings as of December 31, 2000. Beginning in 2002, SCE will be
required to share the net benefits received from the operation of Palo Verde
equally with ratepayers. If the MOU is implemented, or a rate mechanism provided
by legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings. In addition, if the MOU is
implemented, the requirement that SCE share the net benefits received from the
post-2001 operation of Palo Verde equally with ratepayers will be eliminated.
San Onofre Nuclear Generating Station Units 2 and 3
In April 1996, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. San Onofre's operating costs, including nuclear fuel, nuclear
fuel financing costs, and incremental capital expenditures, are recovered
through an incentive pricing plan which allows SCE to receive about 4(cent) per
kWh through December 31, 2003. Beginning January 1, 1998, the accelerated plant
recovery and incremental cost incentive pricing became part of the TCBA
mechanism. These rate-making plans and the TCBA mechanism will continue for
rate-making purposes through the end of the rate freeze period. However, due to
the various unresolved regulatory and legislative issues (as discussed in
Significant Developments in California Electric Utility Restructuring), SCE is
not able to conclude that the unamortized nuclear investment regulatory assets
are probable of recovery through the rate-making process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000. If
the MOU is implemented, or a rate mechanism provided by legislation or
regulatory authority is established that makes recovery from regulated rates
probable as to all or a portion of the amount that has been charged against
earnings, a regulatory asset would be correspondingly reinstated with a
corresponding increase in earnings. Beginning in 2004, SCE will be required to
share the benefits received from operation of San Onofre Units 2 and 3 equally
with ratepayers. In addition, if the MOU is implemented, the sharing of net
benefits received from the post-2003 operation of San Onofre Units 2 and 3
equally between shareholders and ratepayers would be eliminated, but these units
would continue to be subject to cost-based ratemaking through December 31, 2010.
New Accounting Rules
An accounting rule, which requires that costs related to start-up activities be
expensed as incurred, became effective January 1, 1999. This new accounting rule
did not materially affect SCE's results of operations or its financial position.
20
On January 1, 2001, SCE adopted a new accounting standard for derivative
instruments and hedging activities. The new standard requires all derivatives be
recognized on the balance sheet at fair value. Gains or losses from changes in
fair value would be recognized in earnings in the period of change unless the
derivative is designated as a hedging instrument. Gains or losses from hedges of
a forecasted transaction or foreign currency exposure would be recorded as a
separate component of shareholders' equity under the caption Accumulated Other
Comprehensive Income. Gains or losses from hedges of a recognized asset or
liability or a firm commitment would be reflected in earnings for the
ineffective portion of the hedge. SCE's derivatives qualify for hedge accounting
under the new standard. On the implementation date, SCE recorded its interest
rate swap agreement (terminated January 5, 2001), and its block forward power
purchase contracts (seized by the State of California on February 2, 2001) at
fair value on its balance sheet. SCE does not anticipate any earnings impact
from its derivatives, since it expects that any market price changes will be
recovered in rates.
Fuel Supply and Purchased Power Costs
Since April 1, 1998, SCE had been required to sell all of its generated and
purchased power through the PX and ISO, schedule delivery of the power through
the ISO, and acquire all of its power from the PX and ISO to distribute to its
retail customers. These PX and ISO transactions were reported net. As of
December 15, 2000, the FERC eliminated this buying and selling requirement. On
January 30, 2001, the PX suspended its day-ahead and day-of energy trading, and
it subsequently ceased operations and filed for bankruptcy. Furthermore,
beginning in January 2001, the CDWR began purchasing power for SCE's customers.
The MOU contemplates that the CDWR will assume the entire responsibility for
procuring the electricity needs of SCE's customers through December 31, 2002, to
the extent not met by SCE's retained generation and power contracts.
In 2000, PX/ISO purchased-power expense increased significantly due to
electricity shortages and dramatic price increases for natural gas, a key input
of electricity production. The increased volume of higher priced PX purchases
was minimally offset by increases in PX sales revenue and ISO net revenue, as
well as an increase in the market value of gas call options. Increases in the
options' market value decreased purchased-power expense. These gas call options
(which were sold in October 2000) mitigated SCE's transition cost recovery
exposure to increases in energy prices.
SCE's sources of energy during 2000 were as follows: 58.6% purchased power;
22.3% nuclear; 13.7% coal; and 5.4% hydro.
Natural Gas Supply
As a result of the sale of all of its gas-fired generating stations, SCE has
terminated four long-term natural gas supply and three long-term gas
transportation contracts which had been used to import gas from Canada. In
addition, SCE has exercised an option under its 15-year gas transportation
commitment with El Paso Natural Gas Company to reduce its capacity obligation
from 200 million to 130 million cubic feet per day. SCE permanently assigned its
contract with El Paso in November 2000 paying $12.3 million in consideration to
the assignee.
Nuclear Fuel Supply
SCE has contractual arrangements covering 100% of the projected nuclear fuel
requirements for San Onofre through the years indicated below:
Uranium concentrates(*)........................................ 2003
Conversion................................................ 2003
Enrichment................................................ 2003
Fabrication............................................... 2005
---------------
(*) Assumes the San Onofre participants meet their supply obligations in a
timely manner.
21
Assuming normal operation and full utilization of existing on-site storage
capacity, San Onofre Units 2 and 3 will maintain full-core offload reserve
through 2005. The Nuclear Waste Policy Act of 1982 requires that the United
States Department of Energy provide for the disposal of utility spent nuclear
fuel beginning January 31, 1998. The Department of Energy has defaulted on its
obligation to begin acceptance of spent nuclear fuel from the commercial nuclear
industry by that date. Additional spent fuel storage either on-site or at
another location will be required to permit continued operations beyond 2005.
Participants at Palo Verde have contractual agreements for uranium concentrates
to meet projected requirements through 2002. Independent of arrangements made by
other participants, SCE will furnish its share of uranium concentrates
requirement through at least 2001 from existing contracts. Contracts covering
100% of requirements are in place for enrichment through 2003 and fabrication
through 2015. Contracts covering 75% of conversion requirements in 2001 are in
place with negotiations on-going for the remainder.
Palo Verde has existing fuel storage pools and is in the process of completing
construction of a new facility for on-site dry storage of spent fuel. With the
existing storage pools and the addition of the new facility, spent fuel storage
or disposal methods will be available for use by Palo Verde to allow its
continued operation through the term of the plant license.
Environmental Matters
Legislative and regulatory activities in the areas of air and water pollution,
waste management, hazardous chemical use, noise abatement, land use, aesthetics,
and nuclear control continue to result in the imposition of numerous
restrictions on SCE's operation of existing facilities, on the timing, cost,
location, design, construction, and operation by SCE of new facilities, and on
the cost of mitigating the effect of past operations on the environment. These
activities substantially affect future planning and will continue to require
modifications of SCE's existing facilities and operating procedures. SCE is
unable to predict the extent to which additional regulations may affect its
operations and capital expenditure requirements.
In California, pursuant to federal, state and regional Clean Air Act programs,
SCE generating stations were required to reduce emissions of oxides of nitrogen
and certain other pollutants. During 1998, SCE sold all of its oil- and
gas-fueled generating stations within the Mohave Desert Air Quality Management
District, Ventura County Air Pollution Control District, and in the Santa
Barbara County Air Pollution Control District. SCE has sold all but one of its
oil- and gas-fired generating stations within the South Coast Air Quality
Management District. The remaining plant, the small diesel-fired Pebbly Beach
Generating Station, supplies power to Santa Catalina Island.
SCE also owns a 56% undivided interest in the Mohave Generating Station (Mohave
Station) located in Laughlin, Nevada, which is subject to certain air quality
programs. In 1998, several environmental groups filed suit against the co-owners
of the Mohave Station regarding alleged violations of emissions limits. In order
to accelerate resolution of key environmental issues regarding the plant, the
parties filed, in concurrence with SCE and the other station owners, a consent
decree, which was approved by the Court in December 1999. The decree was
designed also to address concerns raised by two EPA programs regarding
visibility and regional haze. The EPA issued its final rulemaking regarding
regional haze regulations on July 1, 1999. The final rule is not expected to
impose any additional emissions control requirements on the Mohave Station
beyond meeting the provisions of the consent decree. The EPA and SCE also
participated in a study to determine the specific impact of air contaminant
emissions from the Mohave Station on visibility in Grand Canyon National Park.
The final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave Station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
Station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. Finally, in
June, 1999, the EPA issued an advanced notice of proposed rulemaking regarding
assessment of visibility impairment at the Grand Canyon. SCE filed
22
comments on the proposed rulemaking in November 1999. In July 2000, EPA
published a proposed rule and on August 21, 2000, SCE provided comments to the
proposed rule. In a letter to SCE, the EPA has expressed its belief that the
controls provided in the consent decree will likely resolve the potential Clean
Air Act visibility concerns. The Agency is considering incorporating the decree
into the visibility provisions of its Federal Implementation Plan for Nevada.
The Clean Air Act also requires the EPA to carry out a three-year study of risk
to public health from the emissions of toxic air contaminants from electric
utility steam generating plants, and to regulate such emissions if the
Administrator makes certain findings. The study's final report to Congress
concluded that mercury from coal-fired utilities is the hazardous air pollutant
of greatest potential concern and merits additional research and monitoring to
better understand the risks of mercury exposure. Other pollutants that may
potentially need further study are dioxins and arsenic from coal-fired plants,
and nickel from oil-fired plants. The EPA concluded that the impacts from
emissions from gas-fired utilities are negligible and that there is no need for
further evaluation of the risks of hazardous air pollutants emitted from such
plants.
On November 3, 1999, the United States Department of Justice filed suit against
a number of electric utilities for alleged violations of the Clean Air Act's
"new source review" requirements related to modifications of air emissions
sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In
addition, the EPA has also issued administrative notices of violation alleging
similar violations at additional power plants owned by some of the same
utilities named as defendants in the Department of Justice lawsuit, as well as
other utilities, and also issued an administrative order to the Tennessee Valley
Authority for similar violations at certain of its power plants. The EPA has
also issued requests for information pursuant to the Clean Air Act to numerous
other electric utilities seeking to determine whether these utilities also
engaged in activities that may have been in violation of the Clean Air Act's new
source review requirements.
To date, one utility--the Tampa Electric Company--has reached a formal agreement
with the United States (February 2000) to resolve alleged new source review
violations. Two other utilities, the Virginia Electric Power Co. and Cinergy
Corp., have reached agreements in principle with the EPA (November and December
2000, respectively). In each case, the settling party has agreed to incur over
$1 billion in expenditures over several years for the installation of additional
pollution control, the retirement or repowering of coal-fired generating units,
supplemental environmental projects and civil penalties. These agreements
provide for a phased approach to achieving required emission reductions over the
next 10 to 15 years. The settling utilities have also agreed to pay civil
penalties ranging from $3.5 million to $8.5 million.
On June 27, 2000, the EPA issued a Request For Information (RFI) for the Four
Corners plant. SCE owns a 48% share of Four Corners' Units 4 and 5 and on
September 1, 2000, replied to the RFI. To date, no further action has been taken
with respect to Four Corners.
In December 2000, the EPA announced its intentions to regulate mercury emissions
from coal-fired and oil-fired electric power plants under Section 112 of the
Clean Air Act and indicated that it would propose a rule to regulate these
emissions by no later than December 15, 2003. EPA expects to finalize this rule
by December 15, 2004. Because SCE does not know what the EPA may require with
respect to this issue, SCE is presently unable to evaluate the impact of
potential mercury regulations on the operations of its facilities.
Regulations under the Clean Water Act require permits for the discharge of
certain pollutants into U.S. waters. Under this act, the EPA issues effluent
limitation guidelines, pretreatment standards, and new source performance
standards for the control of certain pollutants. Individual states may impose
more stringent limitations. SCE incurs additional expenses and capital
expenditures in order to comply with guidelines and standards applicable to
steam electric power plants. SCE presently has discharge permits for all
applicable facilities.
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The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure to
individuals of chemicals known to the State of California to cause cancer or
reproductive harm and the discharge of such listed chemicals into potential
sources of drinking water. Additional chemicals are continuously being put on
the State's list, requiring constant monitoring.
The Resource Conservation and Recovery Act provides the statutory authority for
the EPA to implement a regulatory program for the safe treatment, recycling,
storage, and disposal of solid and hazardous waste. An unresolved issue remains
regarding the degree to which coal waste should be regulated under the act.
Currently, coal waste has been determined to be non-hazardous. Increased
regulation may result in increased expenses relating to the operation of the
Mohave Station.
The Toxic Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use, and disposal of listed
compounds, such as polychlorinated biphenyls, a toxic substance used in certain
electrical equipment. Current costs for disposal of this substance are
immaterial.
SCE records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site using
currently available information, including existing technology, presently
enacted laws and regulations, experience gained at similar sites, and the
probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring, and site closure. Unless
there is a probable amount, SCE records the lower end of this reasonably likely
range of costs (classified as other long-term liabilities at discounted
amounts).
SCE's recorded estimated minimum liability to remediate its 44 currently
identified sites is $114 million. The ultimate costs to clean up SCE's
identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: (1) the extent and
nature of contamination; (2) the scarcity of reliable data for identified sites;
(3) the varying costs of alternative cleanup methods; (4) developments resulting
from investigatory studies; (5) the possibility of identifying additional sites;
and (6) the time periods over which site remediation is expected to occur. SCE
believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $272 million. The
upper limit of this range of costs was estimated using assumptions least
favorable to SCE among a range of reasonably possible outcomes. SCE has sold all
of its gas- and oil-fueled generation plants (except the Pebbly Beach Generating
Station) and has retained some liability associated with the divested
properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism (SCE may seek to include additional sites). Under this mechanism, SCE
will recover 90% of cleanup costs through customer rates; shareholders fund the
remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $75 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates. SCE's identified sites include
several sites for which there is a lack of currently available information,
including the nature and magnitude of contamination, and the extent, if any,
that SCE may be held responsible for contributing to any costs incurred for
remediating these sites. Thus, no reasonable estimate of cleanup costs can be
made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$5 million to $15 million. Recorded costs for 2000 were $13 million.
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Based on currently available information, SCE believes that it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or its financial position. There is no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
SCE's projected environmental capital expenditures are $1.2 billion for the
2001-2005 period, mainly for undergrounding certain transmission and
distribution lines.
Item 2. Properties
Existing Generating Facilities
SCE owns and operates one diesel-fueled generating plant located on Santa
Catalina Island, 37 hydroelectric plants, and an undivided 75.05% interest
(1,614 MW net) in San Onofre Units 2 and 3. These plants are located in Central
and Southern California.
SCE also owns a 15.8% (590 MW net) share of Palo Verde which is located near
Phoenix, Arizona. SCE owns a 48% undivided interest (754 MW net) in Units 4 and
5 at the Four Corners, which is a coal-fueled steam electric generating plant
located in New Mexico. Palo Verde and Four Corners are operated by other
utilities. In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde
and its 48% interest in Four Corners Generation Station to Pinacle West Energy
for $550 million, subject to certain adjustments. The transaction remained
subject to the approval of the CPUC, the Nuclear Regulatory Commission, the FERC
and other state and federal entities, and to the receipt of a favorable ruling
from the Internal Revenue Service. Under the sales agreement, competing offers
could be solicited by SCE, subject to certain conditions, and any superior
offers received were subject to certain matching rights by PWE. In late 2000,
SCE received a superior offer for its Four Corners Generating Station, which PWE
elected not to match. In January 2001, California state legislation was enacted
which bars the sale of utility generating facilities, including SCE's Palo Verde
and Four Corners generating facilities, until 2006. Under the MOU, SCE would
continue to own its share of these generating assets, which would be subject to
cost-based ratemaking, through 2010.
SCE operates and owns a 56% undivided interest (885 MW) in the Mohave Station,
which consists of two coal-fueled steam electric generating units in Clark
County, Nevada. In April 2000, the CPUC approved SCE's proposed auction process
to sell its 56% interest in Mohave Generating Station. In May 2000, SCE agreed
to sell its interest in Mohave to AES Corporation for approximately $533
million. The transaction was subject to final approval by the CPUC and various
federal regulatory agencies. In June 2000, SCE submitted a compliance filing
with the CPUC seeking approval of the auction results and the sale to AES. In
January 2001, California state legislation was enacted which bars the sale of
utility generating facilities, including SCE's Mohave plant, until 2006. Under
the MOU, SCE would continue to own its generating assets, which would be subject
to cost-based ratemaking, through 2010.
At year-end 2000, the existing SCE-owned generating capacity (summer effective
rating) was divided approximately as follows: 44.6% nuclear, 31.8% coal, 23.4%
hydroelectric, and 0.2% diesel. San Onofre, Four Corners, certain of SCE's
substations and portions of its transmission, distribution and communication
systems are located on lands of the U. S. or others under (with minor
exceptions) licenses, permits, easements or leases, or on public streets or
highways pursuant to franchises. Certain of such documents obligate SCE, under
specified circumstances and at its expense, to relocate transmission,
distribution, and communication facilities located on lands owned or controlled
by federal, state, or local governments.
The 37 hydroelectric plants (some with related reservoirs) have an effective
operating capacity of 1,156 MW, and are, with five exceptions, located in whole
or in part on lands of the U.S. pursuant to,
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30- to 50-year governmental licenses that expire at various times between 2001
and 2029. Such licenses impose numerous restrictions and obligations on SCE,
including the right of the United States to acquire projects upon payment of
specified compensation. When existing licenses expire, the FERC has the
authority to issue new licenses to third parties, but only if their license
application is superior to SCE's and then only upon payment of specified
compensation to SCE. Any new licenses issued to SCE are expected to be issued
under terms and conditions less favorable than those of the expired licenses.
SCE's applications for the relicensing of certain hydroelectric projects with an
aggregate dependable operating capacity of about 112.67 MW are pending. Annual
licenses have been issued to SCE hydroelectric projects that are undergoing
relicensing and whose long-term licenses have expired. The annual licenses will
be renewed until the long-term licenses are issued. SCE filed an application
with the CPUC on December 15, 1999, seeking authorization to market value and
retain the ownership and operation of the hydroelectric plants pursuant to the
State's electric industry restructuring legislation. In 1999, SCE filed an
application with the CPUC establishing for purposes of the application a market
value for its hydroelectric generation-related assets at approximately $1.0
billion (almost twice the assets' book value) and proposing to retain and
operate the hydroelectric assets under a performance-based, revenue-sharing
mechanism. The application has broad-based support from labor, ratepayer and
environmental groups. If approved by the CPUC, SCE would be allowed to recover
an authorized, inflation-indexed operations and maintenance allowance, as well
as a reasonable return on capital investment. A revenue-sharing arrangement
would be activated if revenue from the sale of hydroelectricity exceeds or falls
short of the authorized revenue requirement. SCE would then refund 90% of the
excess revenue to ratepayers or recover 90% of any shortfalls from ratepayers. A
final CPUC decision is expected in 2001. Under the MOU, SCE would withdraw this
application, and would continue to own the hydroelectric assets, which would be
subject to cost-based ratemaking, through 2010. In June 2000, SCE credited the
TCBA with the proposed excess of market value over book value of its
hydroelectric generation assets and simultaneously recorded the same amount in
the GABA, pursuant to a CPUC decision. This balance was to remain in GABA until
final market valuation of the hydroelectric assets. If there were a difference
in the final market value, it would have been credited to or recovered from
customers through the TCBA. Due to the various unresolved regulatory and
legislative issues (as discussed in Significant Developments in California
Electric Utility Restructuring), the GABA transaction was reclassified back to
the TCBA, and the TCBA balance (as recalculated based on a March 27, 2001, CPUC
interim decision) was written off as of December 31, 2000.
The capacity factors in 2000 for SCE's principal generation resources were:
45.1% for SCE's hydroelectric plants (lower than average due to below-normal
water conditions); 96.4% for San Onofre; 77.9% for the Mohave Station; 79.2% for
Four Corners Units 4 and 5; and 93% for Palo Verde.
Substantially all of SCE's properties are subject to the lien of a trust
indenture securing First and Refunding Mortgage Bonds (Trust Indenture), of
which approximately $2 billion in principal amount was outstanding on December
31, 2000. Such lien and SCE's title to its properties are subject to the terms
of franchises, licenses, easements, leases, permits, contracts, and other
instruments under which properties are held or operated, certain statutes and
governmental regulations, liens for taxes and assessments, and liens of the
trustees under the Trust Indenture. In addition, such lien and SCE's title to
its properties are subject to certain other liens, prior rights and other
encumbrances, none of which, with minor or insubstantial exceptions, affect
SCE's right to use such properties in its business, unless the matters with
respect to SCE's interest in Four Corners and the related easement and lease
referred to below may be so considered.
SCE's rights in Four Corners, which is located on land of The Navajo Nation of
Indians under an easement from the U. S. and a lease from The Navajo Nation, may
be subject to possible defects. These defects include possible conflicting
grants or encumbrances not ascertainable because of the absence of, or
inadequacies in, the applicable recording law and the record systems of the
Bureau of Indian Affairs and The Navajo Nation, the possible inability of SCE to
resort to legal process to enforce its rights against The Navajo Nation without
Congressional consent, possible impairment or termination under certain
circumstances of the easement and lease by The Navajo Nation, Congress, or the
Secretary of the
26
Interior, and the possible invalidity of the Trust Indenture lien against SCE's
interest in the easement, lease, and improvements on Four Corners.
As discussed above, the MOU between the CDWR and SCE calls for the State's
purchase of SCE's transmission lines for an estimated price of $2.76 billion
(2.3 times book value). The sale is subject to execution of a definitive sale
agreement and other conditions. If a sale of the transmission assets is not
completed under certain circumstances, the MOU calls for SCE's hydroelectric
assets, and potentially additional rights to output from its other generating
stations, to be sold to the State.
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $1.6 billion in 2000,
$984 million in 1999, and $861 million in 1998. Construction expenditures for
the 2001-2005 period are forecasted at $4.5 billion, but may have to be scaled
back unless regulatory or legislative changes make SCE creditworthy again.
In addition to cash required for construction expenditures for the next five
years as discussed above, $3.4 billion is needed to meet requirements for
long-term debt maturities and sinking fund redemption requirements.
SCE's estimates of cash available for operations for the five years through 2005
assume, among other things, satisfactory reimbursement of cost incurred during
the California Energy Crisis, the receipt of adequate and timely rate relief and
the realization of its assumptions regarding cost increases, including the cost
of capital. SCE's estimates and underlying assumptions are subject to continuous
review and periodic revision.
The timing, type, and amount of all additional long-term financing are also
influenced by market conditions, rate relief, and other factors, including
limitations imposed by SCE's Articles of Incorporation and Trust Indenture.
Because of its current liquidity and credit problems, SCE is unable to obtain
financing of any kind. Similarly, as a result of investor's concerns regarding
the California energy crisis' effect on SCE's liquidity and overall financial
condition, SCE has repurchased $849 million of pollution-control bonds that
could not be remarketed in accordance with their terms. These bonds may be
remarketed in the future if SCE's credit status improves sufficiently. In
January 2001, Fitch, Standard and Poor's, and Moody's Investors Service lowered
their credit ratings of SCE to substantially below investment grade. In
mid-April, Moody's removed SCE's credit ratings from review for possible
downgrade. The ratings remain under review for possible downgrade by the other
agencies.
Under the MOU among the CDWR, SCE and Edison International, Edison International
and SCE would commit to make capital investments in SCE's regulated businesses
of at least $3 billion through 2006, or a lesser amount approved by the CPUC.
The equity component of the investments would be funded from SCE's retained
earnings or, if necessary, from equity investments by Edison International.
Nuclear Power Matters
SCE's nuclear facilities have been reliable sources of inexpensive,
non-polluting power for SCE's customers for more than a decade. Throughout the
operating life of these facilities, SCE's customers have supported the revenue
requirements of SCE's capital investment in these facilities and for their
incremental costs through traditional cost-of-service ratemaking.
In 1996, the CPUC adopted SCE's San Onofre Unit 2 and 3 proposal under which SCE
would have recovered its remaining investment in the San Onofre Units at a
reduced rate of return of 7.35%, but on an accelerated basis during the
eight-year period from the effective date in 1996 through December 31, 2003.
California's restructuring legislation, however, requires the recovery of the
San Onofre investment to be completed by December 31, 2001. In addition, the
traditional cost-of-service ratemaking for San Onofre Units 2 and 3 was
superseded by an incentive pricing plan in which SCE's customers pay a preset
price
27
for each kWh of energy generated at San Onofre during the eight-year period. The
restructuring legislation allows for the continuation of the incentive pricing
plan through December 31, 2003. SCE is compensated for the incremental costs
required for the continued operation of San Onofre Units 2 and 3 with revenue
earned through the incentive pricing plan. SCE also retained the ability to
request recovery of the cost of replacement energy for periods in which San
Onofre will not generate power through ECAC filings and, beginning in 1998, as
part of the TCBA mechanism. These rate-making plans and the TCBA mechanism will
continue for rate-making purposes through the end of the rate freeze period.
However, due to the various unresolved regulatory and legislative issues (see
discussion in the Significant Developments in California Electric Utility
Restructuring above), SCE is not able to conclude that the unamortized nuclear
investment regulatory assets are probable of recovery through the rate-making
process. As a result, these balances were written off as a charge to earnings as
of December 31, 2000. The restructuring legislation also allows SCE to continue
to collect funds for decommissioning expenses through traditional ratemaking
treatment. If the MOU is implemented, or a rate mechanism provided by
legislation or regulatory authority is established that makes recovery from
regulated rates probable as to all or a portion of the amount that has been
charged against earnings, a regulatory asset would be correspondingly reinstated
with a corresponding increase in earnings.
On July 16, 1997, the CPUC approved SCE's request to transfer the recorded net
investment in San Onofre Units 2 and 3 step-up transformers to San Onofre Units
2 and 3 sunk costs for recovery by December 31, 2001, at a reduced rate of
return of 7.35%.
On August 21, 1997, the CPUC approved San Diego Gas & Electric's (SDG&E) and
SCE's Joint Petition to Modify, requesting continued recovery of certain
corporate administrative and general costs allocable to San Onofre Units 2 and
3, at rates of 0.28(cent) and 0.21(cent) per kWh, respectively, for the period
January 1, 1998, through December 31, 2003.
In 1996, SCE filed its Palo Verde Proposal Application requesting adoption of a
new rate mechanism for Palo Verde consistent with that of San Onofre Units 2 and
3. On November 15, 1996, SCE, the ORA, and TURN entered into a settlement
agreement, which was approved by the CPUC on December 20, 1996. The agreement
allows SCE to recover its remaining investment in the Palo Verde units by
December 31, 2001, at a reduced rate of return of 7.35% consistent with the
restructuring legislation. The settling parties agreed that SCE would recover
its share of Palo Verde incremental operating costs, except if those costs
exceed 95% of the levels forecast by SCE in its application by more than 30% in
any given year. In such cases, SCE must demonstrate that the aggregate amount of
the costs exceeding the forecast in that year is reasonable. If the annual Palo
Verde site gross capacity factor is less than 55% in a calendar year, SCE will
bear the burden of proof to demonstrate that the site's operations causing the
gross capacity factor to fall below 55% were reasonable in that year. If
operations are determined to be unreasonable by the CPUC, SCE's replacement
power purchases associated with that period of Palo Verde operations below 55%
gross capacity factor may be disallowed.
Beginning in 2002, the net benefits of future operation of Palo Verde Units 1,
2, and 3 will be shared equally between shareholders and customers. Likewise,
beginning in 2004, the benefits of future operation of San Onofre Units 2 and 3
will be shared equally between shareholders and customers. If the MOU is
implemented, the sharing of net benefits received from the post-2001 operation
of Palo Verde and post-2003 operation of San Onofre Units 2 and 3 equally
between shareholders and ratepayers would be eliminated, but these units would
continue to be subject to cost-based ratemaking through December 31, 2010.
San Onofre Nuclear Generating Station
In 1992, the CPUC approved a settlement agreement between SCE and the ORA to
discontinue operation of Unit 1 at the end of its then-current fuel cycle. In
November 1992, SCE discontinued operation of Unit 1. As part of the agreement,
SCE recovered its remaining investment over a four-year period ending August
1996. On December 21, 1998, SCE filed an application with the CPUC requesting
authorization to
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access its nuclear decommissioning trust funds for Unit 1 for the purpose of
commencing decommissioning of Unit 1 in 2000. On March 8, 1999, SCE, SDG&E, the
ORA and TURN entered into a settlement agreement that provided for SCE to access
its nuclear decommissioning trust funds for Unit 1 decommissioning. On June 3,
1999, the CPUC adopted the settlement agreement. On December 6, 1999, SCE
applied for a coastal permit to demolish and remove San Onofre Unit 1 buildings
and other structures and to construct a temporary used fuel storage facility,
also referred to as an independent spent fuel storage installation, as part of
the San Onofre Unit 1 decommissioning project. On February 15, 2000, the
California Coastal Commission approved SCE's application. Decommissioning of
Unit 1 is now underway and it is anticipated that decommissioning will continue
through 2008. At that time, San Onofre Unit 1 will be completely dismantled and
only the spent nuclear fuel will remain on-site in an independent spent fuel
storage installation. All of SCE's reasonable San Onofre Unit 1 decommissioning
costs will be paid from its nuclear decommissioning trust funds.
San Onofre Unit 3 is in a forced outage because of the failure of an electrical
component in the non-nuclear portion of the plant resulting in a fire on
February 3, 2001. The electrical circuit breaker failure and resultant fire had
significant consequences beyond just the damage to the electrical components and
cabling. Loss of electrical power supply in the secondary side of the plant also
resulted in loss of lubricating oil to the turbine generator system while it was
still rotating. This caused severe and extensive damage to the turbine generator
rotors, bearings and other components. SCE presently expects that repair costs
will be covered by applicable insurance except for an approximate $1.9 million
deductible. SCE loses about $800,000 per day of revenue for each day of the
outage under the currently effective San Onofre Units 2 and 3 Incremental Cost
Incentive Pricing plan. The unit is expected to return to service at the end of
June. It is estimated that the lost revenue due to this repair outage will be
approximately $100 million.
The San Onofre Units 2 and 3 steam generator design allows for the removal of up
to 10% of the tubes before the rated capacity of the unit must be reduced.
Increased tube degradation was found during routine inspections in 1997. To
date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from
service. A decreasing (favorable) trend in degradation has been observed in more
recent inspections.
Additionally, in the summer of 2000, SCE applied for a coastal permit to
construct a dry cask spent fuel storage installation for Units 2 and 3. This
permit application was approved, with certain conditions, by the California
Coastal Commission at its meeting on March 13, 2001.
Palo Verde Nuclear Generating Station
In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48%
interest in Four Corners Generation Station to Pinacle West Energy (PWE) for
$550 million, subject to certain adjustments. The transaction remained subject
to the approval of the CPUC, the Nuclear Regulatory Commission, the FERC and
other state and federal entities, and to the receipt of a favorable ruling from
the Internal Revenue Service. Under the sales agreement, competing offers could
be solicited by SCE, subject to certain conditions, and any superior offers
received were subject to certain matching rights by PWE. In late 2000, SCE
received a superior offer for its Four Corners Generating Station, which PWE
elected not to match. In January 2001, California state legislation was enacted
which bars the sale of utility generating facilities, including SCE's Palo Verde
and Four Corners generating facilities, until 2006. Under the MOU, SCE would
continue to own its generating assets, which would be subject to cost-based
ratemaking, through 2010.
Nuclear Facility Decommissioning
Decommissioning of San Onofre Unit 1 (shutdown in 1992 per CPUC agreement)
started in 1999 and will continue through 2008. All of SCE's San Onofre Unit 1
decommissioning costs will be paid from its nuclear decommissioning funds. On
March 9, 2000, the NRC amended the operating licenses for San Onofre Units 2 and
3 so that the operating licenses for both units expire in 2022. Prior to that
amendment, the San Onofre Units 2 and 3 operating licenses expired in 2013. The
Palo Verde operating
29
licenses currently expire in 2026 and 2028, respectively. SCE plans to
decommission San Onofre Units 2 and 3 as early as 2013 and Palo Verde at the end
of each unit's operating license by a removal method authorized by the NRC.
Decommissioning is estimated to cost $2.1 billion in current-year dollars based
on site-specific studies performed in 1998 for San Onofre and Palo Verde. This
estimate considers the total cost of decommissioning and dismantling the plant,
including labor, material, burial, and other costs. The site-specific studies
are updated approximately every three years. Changes in the estimated costs,
timing of decommissioning, or the assumptions underlying these estimates could
cause material revisions to the estimated total cost to decommission in the
near-term. SCE estimates that it will spend approximately $8.6 billion through
2060 to decommission its nuclear facilities.
Decommissioning expenses were $106 million in 2000, $124 million in 1999 and
$164 million in 1998. The accumulated provision for decommissioning excluding
San Onofre Unit 1 and unrealized holding gains was $1.4 billion at December 31,
2000, $1.3 billion at December 31, 1999, and $1.2 billion at December 31, 1998.
The estimated costs (recorded as a liability) to decommission San Onofre Unit 1
is approximately $342 million as of December 31, 2000.
Decommissioning funds collected in rates are placed in independent trust
accounts which, together with accumulated earnings, will be utilized solely for
decommissioning.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The NRC exempted San Onofre Unit 1 from this secondary level,
effective June 1994. The maximum deferred premium for each nuclear incident is
$88 million per reactor, but not more than $10 million per reactor may be
charged in any one year for each incident. Based on its ownership interests, SCE
could be required to pay a maximum of $175 million per nuclear incident. It
would have to pay, however, no more than $20 million per incident in any one
year. Such amounts include a 5% surcharge if additional funds are needed to
satisfy public liability claims and are subject to adjustment for inflation. If
the public liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible additional
assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million has also been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued by a mutual insurance company owned by
utilities with nuclear facilities. If losses at any nuclear facility covered by
the arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up to $19
million per year. Insurance premiums are charged to operating expense.
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Item 3. Legal Proceedings
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties routinely vented highly toxic hydrogen
sulfide gas from unmonitored release points beginning in 1990 and continuing
through at least 1994, in violation of applicable federal, state, and local
environmental law. According to SCE, these violations constituted material
breaches by the Coso parties of their obligations under their contracts with SCE
and applicable law. SCE seeks damages for excess power purchase payments made to
the Coso parties and other relief. The Coso parties' motion to transfer venue to
Inyo County Superior Court was granted on August 31, 1997.
The Coso parties filed a cross-complaint against SCE, The Mission Group, and
Mission Power Engineering Company (Mission parties), which contains claims for
breach of contract, unfair competition, interference with contract, defamation,
breach of an earlier settlement agreement between the Mission parties and the
Coso parties, and other claims. As against SCE, the cross-complaint seeks
restitution, compensatory damages in excess of $115 million, punitive damages in
an amount not less than $400 million, interest, attorney's fees, declaratory
relief, and injunctive relief. As against the Mission parties, the
cross-complaint seeks damages for breach of warranty of authority with respect
to the settlement agreement, and for equitable indemnity. Edison International
was named as a cross-defendant, allegedly as an alter ego of SCE and the Mission
parties. The Coso parties voluntarily dismissed the claims against Edison
International.
Three of the Coso Parties also filed a separate action in the Inyo County
Superior Court against SCE and Edison International, alleging claims for unfair
competition, false advertising and for violations of Public Utilities Code ss.
2106, and seeking injunctive relief, restitution, and punitive damages. The
Court ordered this action consolidated with the SCE action.
Effective February 8, 2000, the parties entered into confidential agreements
resolving all claims in the consolidated action and calling for dismissals with
prejudice and releases. The settlement is subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings
during the period required to obtain CPUC approval. On April 26, 2000, SCE filed
an application to obtain such approval. The Commission approved the settlement
at its November 21, 2000 meeting, and issued its decision on November 22, 2000.
That decision became final (no longer subject to appeal) on December 22, 2000.
Performance of one of the Coso Parties' settlement obligations has not occurred,
delaying the filing and entry of the dismissals. The case has not yet been
dismissed pending completion of certain obligations under the settlement
agreements.
San Onofre Personal Injury Litigation
SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. In addition, a fourth
lawsuit claiming personal injuries from exposure to radiation at San Onofre has
recently been filed but has not yet been served on SCE.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District Court for the Southern
District of California. Plaintiffs also named Combustion Engineering and the
Institute of Nuclear Power Operations as defendants. All trial court proceedings
were stayed pending ruling of the Ninth Circuit Court of Appeal, on an appeal of
a lower court's judgment in favor of SCE in two earlier cases raising similar
allegations. On May 28, 1998, the Court of Appeal affirmed these judgments.
Pursuant to an agreement of the parties as described below, all proceedings in
this matter have been stayed.
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On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District
Court for the Southern District of California. Plaintiffs also named Combustion
Engineering. The trial in this case resulted in a jury verdict for both
defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed
an appeal of the trial court's judgment to the Ninth Circuit Court of Appeal.
Briefing on the appeal was completed in January 1999, oral argument took place
on February 10, 2000, and the matter was taken under submission. On July 20,
2000, the Ninth Circuit Court of Appeals issued an opinion reversing the
District Court judgment and ordering a retrial as to both defendants. On August
10, 2000, SCE filed a petition for rehearing with the Ninth Circuit Court of
Appeals. On January 2, 2001, the Court granted SCE's rehearing petition as to
certain issues and ordered further briefing on those rehearing issues within 30
days. This further briefing was filed on February 1, 2001. On February 20, 2001,
the Court issued an order setting oral argument on the rehearing issues for
April 26, 2001. A decision on the rehearing is not expected for at least several
weeks.
On November 28, 1995, a former contract worker at San Onofre, her husband, and
her son, sued SCE in the U.S. District Court for the Southern District of
California. Plaintiffs also named Combustion Engineering. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in the matter have been stayed.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the
cases at the U.S. District Court level to stay all proceedings including trial,
pending the results of the case currently before the Ninth Circuit Court of
Appeal. The parties agreed that if the plaintiffs do not receive a favorable
determination on appeal then the two cases at the District Court level will be
dismissed. If, however, those plaintiffs receive a favorable determination on
their appeal, then the two District Court cases will be set for trial. On March
23, 1999, the District Court approved the parties' stay agreement in both cases.
The stay will remain in effect until the conclusion of the appellate process,
including filing and disposition of any petitions for rehearing in the Ninth
Circuit or petitions for certiorari in the United States Supreme Court.
On March 1, 2001, a former contract worker at San Onofre and his wife sued SCE
in the U.S. District Court for the Southern District of California. Plaintiffs
also named Combustion Engineering and Bechtel Construction Company, the employer
of the former San Onofre worker. This lawsuit has not yet been served upon SCE
or, to SCE's knowledge, upon the other defendants.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot be determined
at this time.
Navajo Nation Litigation
On June 18, 1999, SCE, was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to the Mohave
Station. The complaint claims that the defendants' actions prevented the Navajo
Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount,
and punitive damages of not less than $1 billion, as well as a declaration that
Peabody's lease and contract rights to mine coal on Navajo Nation lands should
be terminated. SCE joined Peabody's motion to strike the Navajo Nation's
complaint. In addition, SCE and the other defendants have filed motions to
dismiss.
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The Navajo Nation had previously filed suit in the Court of Claims against the
United States Department of Interior, alleging that the Government had breached
its fiduciary duty concerning the above-referenced contract negotiations. On
February 4, 2000 the Court of Claims issued a decision in the Government's
favor, finding that while there had been a breach, there was no available
redress from the Government. In its decision, the Court indicated that it was
making no statements regarding, or findings in, the above federal civil court
action. That decision is on appeal. On February 28, 2000, the Hopi Tribe filed a
motion to intervene in the pending litigation, alleging that the royalty
payments set for their interest in the coal leases with Peabody had been
impacted by the events at issue in the Navajo case. The defendants filed an
opposition to the motion, and the Court calendared all pending motions for
hearing on March 15, 2001.
On March 15, 2001, the District Court heard arguments, granted the Hopi Tribe's
motion to intervene and denied Peabody and SCE's motions to dismiss. The parties
are preparing a discovery plan and the Court set a scheduling conference for
June 15, 2001.
Shareholder Litigation
These purported class actions both involve securities fraud claims arising from
alleged improper accounting by Edison International and SCE of undercollections
in SCE's TRA.
On October 30, 2000, a purported class action lawsuit (the "Stubblefield
Action") was filed in federal district court in Los Angeles against SCE and
Edison International. On December 28, 2000, plaintiffs, without requiring a
response to the original complaint, filed a first amended complaint. In February
2001, the Court approved a stipulation of the parties providing that, in lieu of
a motion to dismiss directed to the first amended complaint, plaintiffs would
voluntarily file a second amended complaint. Pursuant to this stipulation, on
March 5, 2001, plaintiffs filed a second amended complaint. The second amended
complaint alleges that the companies are engaging in securities fraud by
over-reporting income and improperly accounting for the TRA undercollections.
The second amended complaint purports to be filed on behalf of a class of
persons who purchased Edison International common stock beginning June 1, 2000,
and continuing until such time as TRA-related undercollections are recorded as a
loss on SCE's income statements. The second amended complaint seeks compensatory
damages caused by the alleged fraud as well as punitive damages. The response to
the second amended complaint was due April 2, 2001. As discussed below,
plaintiff's counsel has agreed with counsel for Edison International and SCE
that the date for Edison International and SCE to respond to the second amended
complaint may be deferred.
On March 15, 2001, a purported class action lawsuit (the "King Action") was
filed in federal district court in Los Angeles, California, against Edison
International and SCE and certain of their officers. The complaint alleges that
the defendants engaged in securities fraud by misrepresenting and/or failing to
disclose material facts concerning the financial condition of Edison
International and SCE, including that the defendants allegedly overreported
income and improperly accounted for the TRA undercollections. The complaint
purports to be filed on behalf of a class of persons who purchased all
publicly-traded securities of Edison International between May 12, 2000, and
December 22, 2000. Plaintiffs seek damages, in an unstated amount, in connection
with their purchase of securities during the class period.
Plaintiffs in the King Action have filed motions to consolidate this action with
the Stubblefield Action, to have the named plaintiffs in both cases be appointed
"lead plaintiffs' in the consolidated matter and for leave to file a
consolidated complaint. Plaintiffs' and defendants' counsel in the King and
Stubblefield Actions have agreed, subject to the approval of the Court, that
defendants' time for responding to the Stubblefield and King Action complaints
may be deferred pending resolution of motions for consolidation and to appoint
lead plaintiffs, and pending the filing of a consolidated complaint. The parties
have filed stipulations with the Court memorializing this agreement and seeking
the Court's approval.
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Power Generator Litigation
SCE is involved in seventeen separate legal actions brought by various QFs
alleging SCE's failure to timely pay for power deliveries made beginning in
November 2000.
On February 9, 2001, SCE was served with a complaint that was filed against it,
Edison International and unnamed parties in the South (Long Beach) district of
the Los Angeles Superior Court. In this complaint, plaintiff City of Long Beach
alleges that SCE failed to pay the City's biomass project for power deliveries
made by the project in November and December 2000. The City states causes of
action for breach of contract, account stated and unjust enrichment and claims
damages in an amount not less than $4,933,489.78. The City also seeks an
accounting from SCE of the amounts due for power deliveries for November and
December 2000. On March 30, 2001, SCE responded to the complaint by asserting a
general denial and a number of affirmative defenses.
On February 20, 2001, eight geothermal generators that purport to be QFs and
which are each affiliated with CE Generation commenced an action against SCE and
unnamed additional defendants in the Imperial County Superior Court. In their
complaint, the generators allege that SCE has breached the power purchase
agreements applicable to the eight projects by failing to pay the projects for
energy and capacity delivered in November and December 2000. The generators
contend that their collective compensatory damages for these two months are in
the range of $45,000,000 and that they expect to be owed additional monies for
deliveries made in months following December 2000 for which payment is not
timely made by SCE. The generators also contend that SCE's alleged wrongful
failures to pay monies owed to the generators constitutes a willful violation of
one or more CPUC orders and/or other applicable laws, entitling them to
exemplary damages. The complaint also seeks a declaration from the Court that
SCE is obligated to make immediate payment for the November and December 2000
deliveries and that SCE is further obligated to reimburse the generators for all
incidental and other damages resulting from the alleged breaches of contract.
Finally, the generators seek declaratory and injunctive relief to restrain SCE
from preventing the generators from selling their energy and capacity to third
parties during such time as SCE remains noncurrent on its alleged payment
obligations.
On March 9, 2001, SCE filed an answer denying the material allegations of the
complaint and raising a number of affirmative defenses, including, among others,
that the Court lacks subject matter jurisdiction over the lawsuit because the
formula for determining the energy price to be paid to at least seven of the
eight projects for the months in question is the subject of a proceeding before
the CPUC, and, accordingly, SCE contends that the CPUC has exclusive
jurisdiction over the lawsuit. In addition, SCE contends that the generators are
barred from recovering the monies owed because of their own "unclean hands,"
arising from alleged unlawful price manipulation in the natural gas market by an
affiliate of the generators, which manipulation allegedly caused the price of
electricity to be improperly inflated. Furthermore, SCE filed a cross-complaint
alleging that four of the affected projects have operated in a manner contrary
to the terms of their contracts, by not having "stand alone" facilities for
processing geothermal brine (the resource powering the projects' generators) and
by wrongfully diverting electricity between the projects instead of delivering
that electricity directly to SCE. SCE alleges that it has sustained damages as a
result of these breaches of contract in an as-yet undetermined amount.
The generators obtained Court orders permitting them to file and to have heard
on an expedited basis motions for summary adjudication with respect to several
of the causes of action of their complaint. As a result of the first of such
motions, which was heard on March 22, 2001, the generators obtained an order
permitting them to sell energy and capacity to third parties during such time as
SCE remains noncurrent on its alleged payment obligations, and providing that
any such interim suspension of deliveries by the generators to SCE and resale to
third parties will not result in the termination or modification of the
generators' contracts with SCE. SCE has requested in a motion set for hearing on
April 16, 2001, that the order be lifted in light of the CPUC's March 27, 2001,
decision requiring SCE to resume payments to QFs. The second of the motions,
which was scheduled for hearing on April 2, 2001, seeks summary adjudication of
the generators' claims that SCE has breached each of the eight contracts by
failing to
34
make payment for deliveries over the period from November 1, 2000, to and
including February 28, 2001, that SCE owes approximately $101 million for such
deliveries, and that the generators are entitled to recover all incidental and
other damages for the suspended deliveries and any future deliveries for which
payment is not paid and that the generators have the right to file and prosecute
additional breach of contract actions in response to any SCE nonpayment for
future deliveries. SCE filed opposition to this motion on March 23, 2001,
contending, among other things, that SCE has defenses and/or affirmative claims
which constitute offsets to the generators' nonpayment claims, including the
defenses and cross-claims noted above. The hearing has been continued to April
16, 2001, due to SCE's intention to seek coordination of this case with other
actions that QFs have commenced in various California courts on the payment
issue.
On March 2, 2001, SCE was served with a lawsuit filed against it in the United
States District Court, District of Nevada, by two related plaintiffs (Beowawe
Power, L.L.C. and Caithness Dixie Valley L.L.C.) that hold interests in two
power purchase contracts with SCE. The plaintiffs, each of which purports to be
a QF as defined under federal law, operate a geothermal generating facility in
Nevada. The complaint seeks damages in excess of $20,000,000, based upon SCE's
failure to make timely payment for energy deliveries made beginning in November
2000. Plaintiffs are also seeking a prejudgment attachment of SCE's undivided
56% interest in the Mohave generating facility, a coal-fired plant located in
Nevada. A hearing on an order to show cause why the attachment should not issue
took place on March 12, 2001. On March 14, 2001, the Court issued an order
granting the requested attachment subject to the plaintiffs posting required
security. On March 23, 2001, plaintiffs served an amended complaint which
repeats the allegations of the original complaint and which adds three new
claims for declaratory relief. Specifically, the amended complaint asks the
Court to declare: (1) that SCE is obligated to make immediate payments to
plaintiffs for deliveries in November and December 2000 and January 2001; (2)
that plaintiffs may sell the output of their projects to third parties while SCE
is not paying for deliveries; and (3) that plaintiffs are entitled to incidental
damages, as well as compensatory damages, arising out of SCE's alleged breach.
SCE has not yet responded to the amended complaint. Plaintiffs have also filed a
summary judgment motion. On April 11, 2001, SCE filed its opposition to
plaintiffs' motion. No hearing date has been set. SCE has requested oral
argument, but the request has not been granted.
On March 5, 2001, SCE was served with a lawsuit filed against it in Los Angeles
Superior Court by seven related plaintiffs that collectively hold interests in
twelve power purchase contracts with SCE. The plaintiffs each purport to be a QF
as defined under federal law. The complaint seeks "several million dollars" in
damages for breach of each of the twelve contracts based on SCE's alleged
failure to make timely payment for energy deliveries made beginning November
2000. It also seeks a declaration that SCE is obligated to pay for past and
future power deliveries under these contracts, including payments of several
million dollars for deliveries in November and December 2000 and January 2001.
Concurrently with serving their complaint, the plaintiffs also served
applications for writs of attachment against SCE's property within the State of
California. On March 28, 2001, the Court denied the applications. On April 4,
2001, SCE responded to the complaint by asserting a general denial and a number
of affirmative defenses.
On March 28, 2001, SCE was served with a complaint filed against it in the San
Bernardino Superior Court (Barstow District) by IMC Chemicals Inc., a QF
cogeneration project located in Trona, California. The complaint alleges that
SCE failed to pay plaintiff for power deliveries under the contract from
November 2000 through February 2001 and seeks damages of at least $2.8 million
for such alleged failure under four different causes of action: breach of the
power purchase contract between plaintiff and SCE, breach of the covenant of
good faith and fair dealing and two common counts (quantum meruit and quantum
valebant). The complaint also seeks declarations that (1) SCE is obligated to
pay plaintiff all amounts owed for power deliveries under the contract and (2)
plaintiff is entitled to suspend power deliveries and resell such power to third
parties so long as SCE is unable or unwilling to pay for such deliveries and
that such suspension does not terminate or modify the contract. Finally, the
complaint requests an injunction that would restrain SCE from demanding further
deliveries of energy from plaintiff and prohibiting plaintiff from selling power
to third parties. SCE has not yet responded to this complaint.
35
On March 28, 2001, SCE was served with a complaint filed in the Los Angeles
Superior Court by NP Cogen, a QF with which SCE has a power purchase contract.
The complaint alleges that SCE has failed to pay NP Cogen for power deliveries
made under the contract in November and December 2000 and January and February
2001 and, based on this alleged failure to pay, seeks damages for breach of
contract, breach of the covenant of good faith and fair dealing; quantum
valebant, open book account, under California Commercial Code section 2709,
indebitatus assumpsit and unjust enrichment. Although the prayer does not
specify the amount of damages sought, several of these causes of action allege
that the amount presently owing is approximately $8,000,000. The complaint also
seeks a declaration that SCE has effectively repudiated the contract and NP
Cogen is therefore excused from further performance thereunder. SCE has not yet
responded to this complaint.
On April 2, 2001, SCE was served with a complaint filed in Los Angeles County
superior court by Watson Cogeneration Company, a QF. In its complaint, Watson
alleges that SCE has failed to pay Watson for power deliveries between November
2000 and February 2001 under a power purchase contract between SCE and Watson.
Watson seeks at least $150,000,000 for the alleged failure to pay pursuant to
causes of action including breach of contract, breach of the implied covenant of
good faith and fair dealing and common counts (quantum meruit and quantum
valebant). In addition, Watson seeks declarations that (1) SCE must immediately
pay Watson all amounts due for power deliveries under the contract for each
month since November 2000; (2) Watson is entitled to suspend power deliveries
and resell such power to third parties so long as SCE does not pay for such
deliveries and that such suspension does not terminate or modify the contract;
and (3) Watson is entitled to recover all commercially reasonable costs incurred
in reselling power to third parties. Watson also seeks an injunction that
prohibits SCE from requiring Watson to continue power deliveries under the
contract; from interfering with Watson's right to suspend such deliveries and
resell such power to third parties; and from hindering Watson's use of
interconnection facilities and related services. Moreover, under Public
Utilities Code section 2106 Watson seeks exemplary damages and an injunction
that would restrain SCE and its parents and affiliates from converting to its
own use, and failing to pay Watson for power delivered from, amounts collected
from ratepayers. Finally, under California Business and Profession Code section
17200 et seq., Watson seeks an order that it is entitled to an injunction that
would prohibit SCE from continuing the unfair business practices of unfairly
interfering with the operating and continued success of Watson's generating
facility. Watson also claims attorneys' fees and costs under this cause of
action. SCE has not yet responded to this complaint.
On April 3, 2001, SCE was served with a lawsuit filed against it in the Los
Angeles County Superior Court by four plaintiffs, O.L.S. Energy -Chino, O.L.S.
Energy - Camarillo, Carson Cogeneration Company and Mojave Cogeneration Company,
L.P. Each plaintiff is a QF that holds a power purchase contract with SCE. The
complaint alleges that SCE has failed to pay for power deliveries under each of
the four contracts in November and December 2000 and January and February 2001.
The complaint seeks damages of at least $42,324,539.08 for breach of the four
contracts ($8,863,888.52 for the Chino contract; $9,770,153.86 for the Camarillo
contract; $12,465,578.58 for the Carson contract; and $11,216,918.12 for the
Mojave contract) and under common counts for quantum meruit and quantum
valebant. The complaint also seeks declarations that (1) SCE is obligated to pay
each plaintiff for power delivered from November 2000 through February 2001; (2)
plaintiffs are entitled to suspend power deliveries to SCE and sell to third
parties so long as SCE is unable or unwilling to pay for such deliveries and
this suspension shall not modify or terminate the contracts; (3) plaintiffs are
entitled to terminate the contracts; (4) plaintiffs are entitled to all
incidental and other damages incurred in suspending their power deliveries and
sell to third parties; and (5) plaintiffs have independently negotiated
contracts with SCE that are not subject to CPUC decision 01-03-067. Finally,
plaintiffs seek an injunction that would restrain SCE from demanding further
power deliveries and refusing to permit plaintiffs to sell to third parties.
On April 3, 2001, SCE was served with a complaint filed in the Ventura County
Superior Court by E.F. Oxnard, a QF with which SCE has a power purchase
contract. The complaint alleges that SCE has failed to pay Oxnard for deliveries
under the contract in November and December 2000 and January and February 2001.
It seeks unspecified damages for breach of contract, anticipatory breach of
contract and breach of the implied covenant of good faith and fair dealing and
damages of $13,561,773 for common
36
counts (open book account, quantum meruit and quantum valebant ), all arising
from the alleged nonpayment. SCE has not yet responded to this complaint.
On April 5, 2001, Brea Power Partners, L.P. filed a complaint in the Los Angeles
County Superior Court against SCE. Brea Power Partners L.P. is a QF that has a
power purchase contract with SCE. The complaint alleges that SCE has made
reduced payments for power delivered under the contract from June 2000 through
October 2000 and has failed to make any payments for power delivered under the
contract from November 2000 through March 2001. Based on these allegations, the
complaint seeks damages under causes of action for breach of contract ($1.65
million), anticipatory breach of contract and breach of the covenant of good
faith and fair dealing (each, $12 million). The complaint also seeks a
declaration that SCE has breached the contract and is not entitled to demand
further performance thereunder and that plaintiff may sell its power to third
parties. Finally, the complaint seeks an injunction restraining SCE from
unlawful and unfair conduct described in the complaint, which allegedly includes
not paying plaintiff and refusing to permit sales to third parties. SCE has not
yet been officially served with or responded to this complaint.
On April 5, 2001, SCE submitted to the Chairperson of the California Judicial
Counsel a petition requesting the coordination before a single judge of each of
the foregoing Power Generator cases except the Beowawe Power case (due to the
fact it is in Nevada) and the Brea Power Partners case (due to the fact that SCE
was at that time unaware of this case). The petition requests an immediate stay
of the actions identified in the petition while the coordination issue is being
decided. On April 9, 2001, SCE filed an amended petition for the purpose of
adding the Brea Power Partners case to the petition. SCE is seeking coordination
of all of the QF-related lawsuits that have commenced in various California
courts. On April 13, 2001, the Chair of the Judicial Council of California
issued an order assigning the Supervising Judge of the Los Angeles County
Complex Civil Case Litigation Program to sit as coordination motion judge to
determine whether the actions SCE sought to coordinate are complex, and if so,
whether coordination of the included actions is appropriate. The hearing on the
motion is set for May 30, 2001.
On April 9, 2001, Inland Paperboard and Packaging, Inc. (Inland), filed a
lawsuit in the United States District Court, Central District of California, Los
Angeles Division, against SCE and the California Independent System Operator.
Plaintiff is a QF that sells power to SCE under a power purchase contract. In
its complaint, plaintiff alleges that SCE materially breached the contract by
failing to pay for power deliveries thereunder, beginning with deliveries made
in November 2000. The complaint also seeks declarations that plaintiff has
terminated the contract by reason of SCE's alleged material breach of same but
that the interconnection agreement between SCE and plaintiff remains in full
force and effect. The complaint also alleges the SCE and the ISO violated 16
U.S.C. ss.824d(b), and SCE violated California Business & Professions Code
ss.16720 et seq and interfered with prospective economic advantage by refusing
to deliver power from plaintiff's project to the California energy market.
Finally, plaintiff also alleges a quantum meruit cause of action against SCE for
power deliveries after plaintiff allegedly terminated the contract. (The
complaint also seeks a declaration that the ISO is obligated to provide
plaintiff with access to the California energy market.) In addition to the
declarations described in this paragraph, plaintiff prays for actual damages not
less than $5,300,000, restitution, lost profits and actual and treble damages
under the California Business and Professions Code.
Also on April 9, 2001, Inland filed an application for a temporary restraining
order and preliminary injunction that would prevent SCE and the ISO from
refusing to deliver plaintiff's power for sale into the California energy
market. SCE filed opposition to this application on April 10, 2001. The matter
is under submission before Judge Stephen Wilson.
On April 10, 2001, Mammoth Pacific L.P. (Mammoth) filed a lawsuit against SCE in
the Mono County Superior Court. Mammoth has an interest in three QF projects
that sell power to SCE under three power purchase contracts. Mammoth seeks
damages of at least $16,700,000 for SCE's alleged breach of the power purchase
contracts by failing to pay for power deliveries beginning with deliveries made
in November 2000, under causes of action for breach of contract, quantum meruit
and quantum valebant.
37
The complaint also alleges causes of action for breach of the implied covenant
of good faith and fair dealing and unfair competition under California Business
& Professions Code ss.17203. Mammoth seeks a temporary restraining order and a
preliminary and permanent injunction to prevent SCE from taking power from
Mammoth's projects without paying for it and accepting payment from customers
for sales of power generated by Mammoth's projects without using such funds for
any purpose other than paying Mammoth. Finally, Mammoth seeks declarations that
SCE is obligated to perform under Mammoth's contracts by paying Mammoth for
power delivered since November 2000; that Mammoth is entitled to suspend
deliveries until 90 days after SCE has paid all amounts due under the contracts
and has also demonstrated its ability and willingness to continue to pay; and
that this suspension does not modify or amend the contracts. Mammoth also seeks
attorneys' fees. SCE has not yet responded to this complaint.
On April 10, 2001, Heber Geothermal Company (Heber) and Second Imperial
Geothermal Company (Second Imperial) filed a lawsuit against SCE in the Imperial
County Superior Court. Both Heber and Second Imperial are QFs that sell power to
SCE under power purchase contracts. Plaintiffs seek damages of at least
$35,600,000 for SCE's alleged breach of their power purchase contracts by
failing to pay for power deliveries beginning with deliveries made in November
2000, under causes of action for breach of contract, quantum meruit and quantum
valebant. The complaint also alleges causes of action for breach of the implied
covenant of good faith and fair dealing and unfair competition under California
Business & Professions Code ss.17203. Plaintiffs seeks a temporary restraining
order and a preliminary and permanent injunction to prevent SCE from taking
power from plaintiffs without paying for it and accepting payment from customers
for sales of power generated by plaintiffs without using such funds for any
purpose other than paying plaintiffs. Finally, plaintiffs seek declarations that
SCE is obligated to perform under plaintiffs' contracts by paying plaintiffs for
power delivered since November 2000; that plaintiffs are entitled to suspend
deliveries until 90 days after SCE has paid all amounts due under the contracts
and has also demonstrated its ability and willingness to continue to pay; and
that this suspension does not modify or amend the contracts. Plaintiffs also
seek attorneys' fees. SCE has not yet responded to this complaint.
On April 10, 2001, SCE was served with a complaint filed against it by Southern
California Sunbelt Developers Inc. in the Riverside County Superior Court, Indio
District. This complaint alleges three causes of action for breach of the power
purchase agreement between Sunbelt and SCE. In the first cause of action,
Sunbelt alleges that SCE breached the contract by failing to pay for power
deliveries made in November 2000; in the second cause of action, Sunbelt alleges
that SCE breached the contract by failing to pay for power deliveries made in
December 2000; and in the third cause of action, Sunbelt alleges that SCE
breached the contract by failing to pay for power deliveries made in January
2001. Sunbelt prays for damages of at least $158,781.51. SCE has not yet
responded to this complaint.
On April 11, 2001, Corona Energy Partners, Ltd. served SCE with a complaint
filed against SCE in Riverside County Superior Court. Corona is a QF that holds
a power purchase contract with SCE. The complaint alleges that SCE breached the
contract by failing to pay for power deliveries from November 2000 through
February 2001. Based on this alleged failure, Corona states causes of action for
breach of contract, breach of the implied covenant of good faith and fair
dealing, quantum meruit, quantum valebant and action for the price, and seeks
damages of at least $13,361,096 thereunder. Under the breach of contract cause
of action, Corona also alleged entitlement to unspecified amounts allegedly
recoverable under Uniform Commercial Code sections 2701, 2702, 2703, 2706, 2709
and 2710. Corona also seeks declarations that it need not resume deliveries to
SCE until SCE pays all amounts due and "demonstrates an unequivocal commitment
and ability to pay for deliveries going forward," that Corona is entitled to
resell its energy to other purchasers during this time, and SCE cannot interfere
with such sales; and the suspension and reselling shall not modify or amend the
contract. Finally, Corona seeks an injunction that would restrain SCE from
requiring Corona to deliver to SCE while SCE is still allegedly in default of
the contract; from interfering with Corona's alleged right to resell its energy
to third parties; and from refusing to pay Corona while allegedly collecting
billions of dollars from ratepayers. SCE has not yet responded to this
complaint.
38
On April 11, 2001, SCE was served with a complaint filed against it by Kern
River Cogeneration Company ("KRCC") and Sycamore Cogeneration Company
("Sycamore") in the Kern County Superior Court. Each plaintiff is a QF that
holds a power purchase contract with SCE. Each plaintiff is also an affiliate of
SCE. In the complaint, each plaintiff alleges a cause of action against SCE for
breach of contract, arising from SCE's alleged failure to pay for energy
deliveries from November 2000 through March 2001 (the latter month is on
information and belief, since the March payment is not yet due). KRCC seeks at
least $112,033,000 in damages for the alleged breach, and Sycamore seeks at
least $120,407,000. Plaintiffs jointly allege a cause of action for breach of
the implied covenant of good faith and fair dealing, and seek compensatory and
exemplary damages therefor. Plaintiffs additionally allege violations of CPUC
Code section 2106 and unfair business practices for allegedly failing to pay
plaintiffs for power deliveries when SCE allegedly received tens of millions of
dollars from ratepayers and seek an injunction enjoining this alleged behavior
under both causes of action and reasonably attorneys fees under the unfair
business practices cause of action. Finally, plaintiffs seek a declaration that
each of them is entitled to suspend power deliveries until SCE makes cash
payments for all past due amounts and demonstrates that it is solvent,
creditworthy and able to make payments when due on an ongoing basis; that each
plaintiff is entitled to resell its power without hindrance from SCE; that SCE
is required to provide each plaintiff with interconnection service without
charge during the suspension; and that the suspension does not breach, modify or
terminate the contracts. These plaintiffs have also brought a motion for summary
adjudication of the cause of action for declaratory relief. It is scheduled for
hearing on May 2, 2001. SCE's opposition papers are due on April 24, 2001.
On April 12, 2001, the Proctor & Gamble Paper Products Company filed a lawsuit
against SCE in the Ventura County Superior Court. Plaintiff is a QF that holds a
power purchase contract with SCE. In its complaint, plaintiff alleges causes of
action for breach of contract, quantum meruit and quantum valebant, arising from
SCE's alleged failure to pay for power deliveries made from November 2000
through February 2001. Plaintiff seeks at least $19,770,202.97 in damages under
these causes of action. Plaintiff also seeks declarations that SCE must
immediately pay all sums allegedly owed for power deliveries; that SCE has
materially breached the contract; that plaintiff is entitled to suspend
deliveries under the contract and may use its present interconnection to SCE's
system, without charge, to sell power to solvent third parties; that plaintiff
is entitled to terminate the contract upon giving notice of same; and that
plaintiff is entitled to damages equal to the commercially reasonable amount of
suspending deliveries and reselling its power and that such suspension and
resale does not modify or terminate the contract. Finally, plaintiff seeks an
injunction that would restrain SCE from demanding further deliveries of energy
and capacity and preventing plaintiff from selling to third parties. SCE has not
yet responded to this complaint.
PX Performance Bond Litigation
On January 19, 2001, American Home Assurance Company (American Home) notified
SCE that due to SCE's failure to comply with its payment obligations to the PX,
the PX issued a demand to American Home on a $20,000,000 pool performance bond.
American Home demanded payment from SCE by January 29, 2001, of $20,000,000
under an indemnity agreement between SCE and American Home.
SCE has exercised its right under the indemnity agreement to assume the defense
of American Home against claims arising from the pool performance bond. As
required by the indemnity agreement, SCE has agreed to deposit $20,000,000, plus
a reasonable amount for interest and expenses, in an account in trust to be
available to satisfy any judgment, should there be one, against American Home
under the pool performance bond.
SCE has further instituted the alternative dispute resolution provisions
provided for in the applicable PX Tariff, which provide for negotiation followed
by mediation and, if unsuccessful, arbitration.
39
Item 4. Submission of Matters to a Vote of Security Holders
Inapplicable
Pursuant to Form 10-K's General Instruction (General Instruction) G(3), the
following information is included as an additional item in Part I:
Executive Officers(1) of the Registrant
Age at
Executive Officer December 31, 2000 Company Position
----------------- ----------------- ----------------
Stephen E. Frank 59 Chairman of the Board, President, Chief Executive
Officer and Director
Harold B. Ray 60 Executive Vice President, Generation Business Unit
Pamela A. Bass 53 Senior Vice President, Customer Service Business Unit
John R. Fielder 55 Senior Vice President, Regulatory Policy and Affairs
Robert G. Foster 53 Senior Vice President, Public Affairs
Richard M. Rosenblum 50 Senior Vice President, Transmission and Distribution
Business Unit
Mahvash Yazdi 49 Senior Vice President and Chief Information Officer
Bruce C. Foster 48 Vice President, Regulatory Affairs
Thomas M. Noonan 49 Vice President and Controller
Stephen E. Pickett 50 Vice President and General Counsel
W. James Scilacci 45 Vice President and Chief Financial Officer
(1) Executive Officers are defined by Rule 3b-7 of the General Rules and
Regulations under the Securities Exchange Act of 1934, as amended.
40
None of SCE's executive officers are related to each other by blood or marriage.
As set forth in Article IV of SCE's Bylaws, the elected officers of SCE are
chosen annually by and serve at the pleasure of SCE's Board of Directors and
hold their respective offices until their resignation, removal, other
disqualification from service, or until their respective successors are elected.
All of the executive officers have been actively engaged in the business of SCE
for more than five years except for Mahvash Yazdi. Those officers who have not
held their present position for the past five years had the following business
experience.
Executive Officer Company Position Effective Dates
- ----------------- ---------------- ---------------
Stephen E. Frank Chairman of the Board, President, Chief January 2000 to present
Executive Officer and Director
President, Chief Operating Officer and June 1995 to December 1999
Director
Pamela A. Bass Senior Vice President, Customer Service March 1999 to present
Business Unit
Vice President, Customer Solutions Business June 1996 to February 1999
Unit
Vice President, Shared Services January 1996 to May 1996
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present
Affairs
Vice President, Regulatory Policy and Affairs February 1992 to February 1998
Robert G. Foster Senior Vice President, Public Affairs November 1996 to present
Vice President, Public Affairs November 1993 to October 1996
Richard M. Rosenblum Senior Vice President, Transmission and February 1998 to present
Distribution Business Unit January 1996 to February 1998
Vice President, Distribution Business Unit June 1993 to December 1995
Vice President, Nuclear Engineering and
Technical Services
Mahvash Yazdi Senior Vice President and Chief Information January 2000 to present
Officer
Vice President and Chief Information Officer May 1997 to December 1999
Vice President of Information Technology and September 1995 to May 1997
Chief Information Officer, Hughes Aircraft
Company1
Thomas M. Noonan Vice President and Controller March 1999 to present
Assistant Controller September 1993 to February 1999
Stephen E. Pickett Vice President and General Counsel January 2000 to present
Associate General Counsel November 1993 to December 1999
W. James Scilacci Vice President and Chief Financial Officer January 2000 to present
Director, 2002 General Rate Case August 1999 to December 1999
Director, Qualifying Facility Resources January 1995 to August 1999
(1) This entity is not a parent, subsidiary or other affiliate of SCE.
41
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Certain information responding to Item 5 with respect to frequency and amount of
cash dividends is included in SCE's Annual Report to Shareholders for the year
ended December 31, 2000 (Annual Report), under Quarterly Financial Data on page
59 and is incorporated by reference pursuant to General Instruction G(2). As a
result of the formation of a holding company described above in Item 1, all of
the issued and outstanding common stock of SCE is owned by Edison International
and there is no market for such stock.
Item 6. Selected Financial Data
Information responding to Item 6 is included in the Annual Report under Selected
Financial and Operating Data: 1996 - 2000 on page 1 and is incorporated herein
by reference pursuant to General Instruction G(2).
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition
Information responding to Item 7 is included in the Annual Report under
Management's Discussion and Analysis of Results of Operations and Financial
Condition on pages 2 through 24 and is incorporated herein by reference pursuant
to General Instruction G(2).
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 7A is included in the Annual Report under
Management's Discussion and Analysis of Results of Operations and Financial
Condition on pages 11 through 12 incorporated herein by reference pursuant to
General Instruction G(2), and in Part I, Item 1 of this report on page 15 under
Market Risk Exposures.
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in Part IV.
Other information responding to Item 8 is included in the Annual Report on pages
25 through 59, and is incorporated herein by reference pursuant to General
Instruction G(2).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information concerning executive officers of SCE is set forth in Part I in
accordance with General Instruction G(3), pursuant to Instruction 3 to Item
401(b) of Regulation S-K. Other information responding to Item 10 will be
incorporated by reference from SCE's definitive Joint Proxy Statement (Proxy
Statement) filed with the SEC in connection with SCE's Annual Meeting to be held
on May 14, 2001, under the heading, Election of Directors and Section 16(a)
Beneficial Ownership Reporting Compliance, and is incorporated herein by
reference pursuant to General Instruction G(3).
42
Item 11. Executive Compensation
Information responding to Item 11 will be incorporated by reference from SCE's
definitive Proxy Statement under the headings Board Compensation, Executive
Compensation, Summary Compensation Table, Option/SAR Grants in 2000, Aggregated
Option/SAR Exercises in 2000 and FY-End Option/SAR Values, Long-Term Incentive
Plan Awards in Last Fiscal Year, Pension Plan Table, Other Retirement Benefits,
Employment Contracts and Termination of Employment Arrangements, and
Compensation and Executive Personnel Committees' Interlocks and Insider
Participation, and is incorporated herein by reference pursuant to General
Instruction G(3).
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information responding to Item 12 will be incorporated by reference from SCE's
definitive Proxy Statement under the headings Stock Ownership of Directors and
Executive Officers and Stock Ownership of Certain Shareholders, and is
incorporated herein by reference pursuant to General Instruction G(3).
Item 13. Certain Relationships and Related Transactions
Information responding to Item 13 will be incorporated by reference from SCE's
definitive Proxy Statement under the heading Certain Relationships and
Transactions of Nominees and Executive Officers and Other Management
Transactions, and is incorporated herein by reference pursuant to General
Instruction G(3).
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) Financial Statements
The following items contained in the Annual Report are found on pages 2 through
61, and incorporated by reference in this report.
Management's Discussion and Analysis of Results of Operations and
Financial Condition
Consolidated Statements of Income - Years Ended December 31, 2000,
1999 and 1998
Consolidated Statements of Comprehensive Income - Years Ended
December 31, 2000, 1999, and 1998
Consolidated Balance Sheets - December 31, 2000, and 1999
Consolidated Statements of Cash Flows - Years Ended December 31, 2000,
1999, and 1998
Consolidated Statements of Changes in Common Shareholder's Equity - Years Ended
December 31, 2000, 1999, and 1998
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(a)(2) Report of Independent Public Accountants and Schedules
Supplementing Financial Statements
The following documents may be found in this report at the indicated page
numbers.
Page
----
Report of Independent Public Accountants on Supplemental Schedules 45
Schedule II - Valuation and Qualifying Accounts for the Years
Ended December 31, 2000, 1999, and 1998 46
Schedules I through V, inclusive, except those referred to above, are omitted as
not required or not applicable.
43
(a)(3) Exhibits
See Exhibit Index beginning on page 50 of this report.
The Company will furnish a copy of any exhibit listed in the accompanying
Exhibit Index upon written request and upon payment to the Company of its
reasonable expenses of furnishing such exhibit, which shall be limited to
photocopying charges and, if mailed to the requesting party, the cost of
first-class postage.
(b) Reports on Form 8-K
October 17, 2000 TRA Undercollections
November 3, 2000 $1.3B Notes
December 22, 2000 TRA Undercollections and Other Events
44
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited, in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements included in the 2000 Annual
Report to Shareholders of Southern California Edison Company (SCE) incorporated
by reference in this Form 10-K, and have issued our report thereon dated April
12, 2001. Our report on the financial statements includes an explanatory
paragraph with respect to SCE's ability to continue as a going concern as
discussed in Notes 2 and 3 to the financial statements. Our audits were made for
the purpose of forming an opinion on those consolidated financial statements
taken as a whole. The supplemental schedules listed in Part IV of this Form 10-K
are the responsibility of SCE's management and are presented for purposes of
complying with the Securities and Exchange Commission's rules and regulations,
and are not part of the consolidated financial statements. These supplemental
schedules have been subjected to the auditing procedures applied in the audits
of the consolidated financial statements and, in our opinion, fairly state in
all material respects the financial data required to be set forth therein in
relation to the consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
April 12, 2001
45
Southern California Edison Company
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 2000
Additions
-----------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
- ----------------------------------------------------------------------------------------------------------------------
(In thousands)
Group A:
Uncollectible accounts
Customers $ 21,656 $ 24,017 $ -- $ 25,880 $ 19,793
All other 3,009 1,201 -- 783 3,427
- ---------------------------------------------------------------------------------------------------------------------
Total $ 24,665 $ 25,218 $ -- $ 26,663(a) $ 23,220
- ---------------------------------------------------------------------------------------------------------------------
Group B:
DOE Decontamination
and Decommissioning $ 34,590 $ -- $ (219)(b) $ 4,451(c) $ 29,920
Purchased-power settlements 563,459 17,188 -- 114,415(d) 466,232
Pension and benefits 232,901 44,244 24,101(e) 4,968(f) 296,278
Insurance, casualty and other 68,880 42,749 -- 47,571(g) 64,058
- ---------------------------------------------------------------------------------------------------------------------
Total $ 899,830 $ 104,181 $ 23,882 $ 171,405 $ 856,488
- ---------------------------------------------------------------------------------------------------------------------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
46
Southern California Edison Company
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1999
Additions
----------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
- ----------------------------------------------------------------------------------------------------------------------------------
(In thousands)
Group A:
Uncollectible accounts
Customers $ 19,596 $ 21,968 $ -- $ 19,908 $ 21,656
All other 2,634 1,288 -- 913 3,009
- -------------------------------------------------------------------------------------------------------------------------------
Total $ 22,230 $ 23,256 $ -- $ 20,821(a) $ 24,665
- -------------------------------------------------------------------------------------------------------------------------------
Group B:
DOE Decontamination
and Decommissioning $ 39,419 $ -- $ (134)(b) $ 4,695(c) $ 34,590
Purchased-power settlements 129,697 466,043 -- 32,281(d) 563,459
Pension and benefits 239,668 48,894 21,674(e) 77,335(f) 232,901
Insurance, casualty and other 73,249 37,674 -- 42,043(g) 68,880
- -------------------------------------------------------------------------------------------------------------------------------
Total $ 482,033 $ 552,611 $ 21,540 $ 156,354 $ 899,830
- -------------------------------------------------------------------------------------------------------------------------------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
47
Southern California Edison Company
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
Additions
---------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
- ---------------------------------------------------------------------------------------------------------------------------------
(In thousands)
Group A:
Uncollectible accounts
Customers $ 24,245 $ 19,808 $ -- $ 24,457 $ 19,596
All other 2,208 2,273 -- 1,847 2,634
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 26,453 $ 22,081 $ -- $ 26,304(a) $ 22,230
- --------------------------------------------------------------------------------------------------------------------------------
Group B:
DOE Decontamination
and Decommissioning $ 44,336 $ -- $ (89)(b) $ 4,828(c) $ 39,419
Purchased-power settlements 145,640 -- -- 15,943(d) 129,697
Pension and benefits 211,200 170,743 18,988(e) 161,263(f) 239,668
Insurance, casualty and other 78,461 69,275 -- 74,487(g) 73,249
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 479,637 $ 240,018 $ 18,899 $ 256,521 $ 482,033
- --------------------------------------------------------------------------------------------------------------------------------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
48
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
By:
KENNETH S. STEWART
------------------------------------
KENNETH S. STEWART
Assistant General Counsel
Date: April 17, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
Principal Executive Officer:
Stephen E. Frank* Chairman of the Board, President, April 17, 2001
Chief Executive Officer and Director
Principal Financial Officer:
W. James Scilacci* Vice President and
Chief Financial Officer April 17, 2001
Controller or Principal Accounting Officer:
Thomas M. Noonan* Vice President and Controller April 17, 2001
Board of Directors:
Warren Christopher* Director April 17, 2001
Stephen E. Frank* Director April 17, 2001
Joan C. Hanley* Director April 17, 2001
Carl F. Huntsinger* Director April 17, 2001
Charles D. Miller* Director April 17, 2001
Luis G. Nogales* Director April 17, 2001
Ronald L. Olson* Director April 17, 2001
James M. Rosser* Director April 17, 2001
Robert H. Smith* Director April 17, 2001
Thomas C. Sutton* Director April 17, 2001
Daniel M. Tellep* Director April 17, 2001
Edward Zapanta* Director April 17, 2001
*By:
KENNETH S. STEWART
- -----------------------------
KENNETH S. STEWART
Assistant General Counsel
49
EXHIBIT INDEX
Exhibit
Number Description
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE
effective June 1, 1993 (File No. 1-2313, Form 10-K for the year ended
December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE
dated effective August 21, 1997 (File No. 1-2313, Form 10-Q for the quarter
ended September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the
Board of Directors on February 15, 2001
4.1 SCE First Mortgage Bond Trust Indenture, dated as of October 1, 1923
(Registration No. 2-1369)*
4.2 Supplemental Indenture, dated as of March 1, 1927 (Registration No.
2-1369)*
4.3 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No.
2-1602)*
4.4 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration
No. 2-4522)*
4.5 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No.
2-4522)*
4.6 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration
No. 2-4522)*
4.7 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration
No. 2-7610)*
4.8 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964
(Registration No. 2-22056)*
4.9 Eighty-Eighth Supplemental Indenture, dated as of July 15 1992 (File No.
1-2313, Form 8-K dated July 22, 1992)*
4.10 Indenture dated as of January 15, 1993 (File No. 1-2313, Form 8-K dated
January 28, 1993)*
4.11 Indenture dated as of May 1, 1995 (File No. 1-2313, Form 8-K dated May 24,
1995)*
10.1 1981 Deferred Compensation Agreement (File No. 1-2313, filed as Exhibit
10.2 to Form 10-K for the year ended December 31, 1981)*
10.2 1985 Deferred Compensation Agreement for Executives (File No. 1-2313, filed
as Exhibit 10.3 to Form 10-K for the year ended December 31, 1986)*
10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313, filed
as Exhibit 10.4 to Form 10-K for the year ended December 31, 1986)*
10.4 Director Deferred Compensation Plan (File No. 1-2313, filed as Exhibit 10.3
to Form 10-Q for the quarter ended June 30, 1998)*
10.5 Director Grantor Trust Agreement (File No. 1-2313, filed as Exhibit 10.10
to Form 10-K for the year ended December 31, 1995)*
10.6 Executive Deferred Compensation Plan (File No. 1-2313, filed as Exhibit
10.2 to Form 10-Q for the quarter ended March 31, 1998)*
10.7 Executive Grantor Trust Agreement (File No. 1-2313, filed as Exhibit 10.12
to Form 10-K for the year ended December 31, 1995)*
10.8 Executive Supplemental Benefit Program (File No. 1-2313, filed as Exhibit
10.2 to Form 10-Q for the quarter ended September 30, 1999)*
10.9 Dispute resolution amendment of 1981 Executive Deferred Compensation Plan,
1985 Executive and Director Deferred Compensation Plans and Executive
Supplemental Benefit Program (File No. 1-2313, filed as Exhibit 10.21 to
Form 10-K for the year ended December 31, 1998)*
10.10 Executive Retirement Plan (File No. 1-2313, filed as Exhibit 10.1 to Form
10-Q for the quarter ended September 30, 1999)*
10.11 Executive Incentive Compensation Plan (File No. 1-2313, filed as Exhibit
10.12 to Form 10-K for the year ended December 31, 1997)*
10.12 Executive Disability and Survivor Benefit Program (File No. 1-2313, filed
as Exhibit 10.22 to Form 10-K for the year ended December 31, 1994)*
10.13 Retirement Plan for Directors (File No. 1-2313, filed as Exhibit 10.2 to
Form 10-Q for the quarter ended June 30, 1998)*
50
Exhibit
Number Description
10.14 Officer Long-Term Incentive Compensation Plan (File No. 1-2313, filed as
Exhibit 10.3 to Form 10-Q for the quarter ended March 31, 1998)*
10.15 Equity Compensation Plan (File No. 1-2313, filed as Exhibit 10.1 to Form
10-Q for the quarter ended June 30, 1998)*
10.15.1 Amendment No. 1 to the Equity Compensation Plan (File No. 1-2313, filed
as Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2000)*
10.16 2000 Equity Plan (File No. 1-2313, filed as Exhibit 10.1 to Form 10-Q for
the quarter ended June 30, 2000)*
10.17 Forms of Agreement for long-term compensation awards under the Officer
Long-Term Incentive Compensation Plan, the Equity Compensation Plan or the
2000 Equity Plan (File No. 1-2313, for 1991-1995 awards filed as Exhibit
10.21.1 to Form 10-K for the year ended December 31, 1995, for 1996 awards
filed as Exhibit 10.16.2 to Form 10-K for the year ended December 31, 1996,
for 1997 awards filed as Exhibit 10.16.3 to Form 10-K for the year ended
December 31, 1997, for 1998 awards filed as Exhibit 10.4 to Form 10-Q for
the quarter ended June 30, 1998, for 1999 awards filed as Exhibit 10.1 to
Form 10-Q for the quarter ended March 31, 1999, for January 2000 awards
filed as Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2000,
and for May 2000 awards filed as Exhibit 10.2 to Form 10-Q for the quarter
ended June 30, 2000)*
10.18 Form of Agreement for 2000 Director Awards under the Equity Compensation
Plan (File No. 1-2313, filed as Exhibit 10.3 to Form 10-Q for the quarter
ended June 30, 2000)*
10.19 Estate and Financial Planning Program as amended April 1, 1999 (File No.
1-2313, filed as Exhibit 10.2 to Form 10-Q for the quarter ended June 30,
1999)*
10.20 Option Gain Deferral Plan as restated September 15, 2000
10.21 Employment Letter Agreement with Bryant C. Danner (File No. 1-2313, filed
as Exhibit 10.27 to Form 10-K for the year ended December 31, 1992)*
10.22 Employment Letter Agreement with Stephen E. Frank (File No. 1-2313, filed
as Exhibit 10.25 to Form 10-K for the year ended December 31, 1995)*
10.23 Election Terms for Warren Christopher (File No. 1-2313, filed as Exhibit
10.21 to Form 10-K for the year ended December 31, 1997)*
10.24 Dispute resolution amendment of 1981 Executive Deferred Compensation Plan,
1985 Executive and Director Deferred Compensation Plans and Executive
Supplemental Benefit Program (File No. 1-2313, filed as Exhibit 10.20 to
Form 10-K for the year ended December 31, 1998)*
10.25 Memorandum of Understanding with Governor Davis's Transmittal Letter dated
April 9, 2001
12. Computation of Ratios of Earnings to Fixed Charges
13. Annual Report to Shareholders for year ended December 31, 2000
23. Consent of Independent Public Accountants - Arthur Andersen LLP
24.1 Power of Attorney
24.2 Certified copy of Resolution of Board of Directors Authorizing Signature
* Incorporated by reference pursuant to Rule 12b-32.
To Holders of the Company's Bylaws:
Effective February 15, 2001, Article II, Section 2 was
amended to change the date of the 2001 annual
shareholders' meeting, and
Article III, Sections 6 and 7 were amended
to change the regular Board meeting schedule.
BEVERLY P. RYDER
Corporate Secretary
BYLAWS
OF
SOUTHERN CALIFORNIA EDISON COMPANY
AS AMENDED TO AND INCLUDING
FEBRUARY 15, 2001
INDEX
Page
ARTICLE I - PRINCIPAL OFFICE
Section 1. Principal Office................................................1
ARTICLE II - SHAREHOLDERS
Section 1. Meeting Locations..............................................1
Section 2. Annual Meetings................................................1
Section 3. Special Meetings...............................................2
Section 4. Notice of Annual or Special Meeting............................2
Section 5. Quorum.........................................................4
Section 6. Adjourned Meeting and Notice Thereof...........................4
Section 7. Voting.........................................................4
Section 8. Record Date....................................................6
Section 9. Consent of Absentees...........................................7
Section 10. Action Without Meeting..........................................7
Section 11. Proxies.........................................................8
Section 12. Inspectors of Election..........................................8
ARTICLE III - DIRECTORS
Section 1. Powers.........................................................9
Section 2. Number of Directors...........................................10
Section 3. Election and Term of Office...................................10
Section 4. Vacancies.....................................................10
Section 5. Place of Meeting..............................................11
Section 6. Organization Meeting..........................................11
Section 7. Special Meetings and Other Regular Meetings...................11
Section 8. Quorum........................................................12
Section 9. Participation in Meetings by Conference Telephone.............12
Section 10. Waiver of Notice...............................................12
Section 11. Adjournment....................................................13
Section 12. Fees and Compensation..........................................13
Section 13. Action Without Meeting.........................................13
Section 14. Rights of Inspection...........................................13
Section 15. Committees.....................................................13
ARTICLE IV - OFFICERS
Section 1. Officers......................................................14
Section 2. Election......................................................15
Section 3. Eligibility of Chairman or President..........................15
Section 4. Removal and Resignation.......................................15
Section 5. Appointment of Other Officers.................................15
Section 6. Vacancies.....................................................15
Section 7. Salaries......................................................16
Section 8. Furnish Security for Faithfulness.............................16
Section 9. Chairman's Duties; Succession to
Such Duties in Chairman's Absence or Disability.......16
Section 10. President's Duties.............................................16
Section 11. Chief Financial Officer........................................17
Section 12. Vice Presidents' Duties........................................17
Section 13. General Counsel's Duties.......................................17
Section 14. Associate General Counsel's and Assistant General
Counsel's Duties......................................17
Section 15. Controller's Duties............................................17
Section 16. Assistant Controllers' Duties..................................17
Section 17. Treasurer's Duties.............................................18
Section 18. Assistant Treasurers' Duties...................................18
Section 19. Secretary's Duties.............................................18
Section 20. Assistant Secretaries' Duties..................................19
Section 21. Secretary Pro Tempore..........................................19
Section 22. Election of Acting Treasurer or Acting Secretary...............19
Section 23. Performance of Duties..........................................20
ARTICLE V - OTHER PROVISIONS
Section 1. Inspection of Corporate Records...............................20
Section 2. Inspection of Bylaws..........................................21
Section 3. Contracts and Other Instruments, Loans, Notes
and Deposits of Funds.................................21
Section 4. Certificates of Stock.........................................22
Section 5. Transfer Agent, Transfer Clerk and Registrar..................22
Section 6. Representation of Shares of Other Corporations................22
Section 7. Stock Purchase Plans..........................................23
Section 8. Fiscal Year and Subdivisions..................................23
Section 9. Construction and Definitions..................................23
ARTICLE VI - INDEMNIFICATION
Section 1. Indemnification of Directors and Officers.....................24
Section 2. Indemnification of Employees and Agents.......................25
Section 3. Right of Directors and Officers to Bring Suit.................26
Section 4. Successful Defense............................................26
Section 5. Non-Exclusivity of Rights.....................................26
Section 6. Insurance.....................................................26
Section 7. Expenses as a Witness.........................................27
Section 8. Indemnity Agreements..........................................27
Section 9. Separability..................................................27
Section 10. Effect of Repeal or Modification...............................27
ARTICLE VII - EMERGENCY PROVISIONS
Section 1. General.......................................................27
Section 2. Unavailable Directors.........................................28
Section 3. Authorized Number of Directors................................28
Section 4. Quorum........................................................28
Section 5. Creation of Emergency Committee...............................28
Section 6. Constitution of Emergency Committee...........................29
Section 7. Powers of Emergency Committee.................................29
Section 8. Directors Becoming Available..................................29
Section 9. Election of Board of Directors................................29
Section 10. Termination of Emergency Committee.............................30
ARTICLE VIII - AMENDMENTS
Section 1. Amendments....................................................30
BYLAWS
Bylaws for the regulation, except as otherwise provided
by statute or its Articles of Incorporation
of
SOUTHERN CALIFORNIA EDISON COMPANY
AS AMENDED TO AND INCLUDING
FEBRUARY 15, 2001
ARTICLE I - PRINCIPAL OFFICE
Section 1. Principal Office.
The Edison General Office, situated at 2244 Walnut Grove Avenue, in the
City of Rosemead, County of Los Angeles, State of California, is hereby fixed as
the principal office for the transaction of the business of the corporation.
ARTICLE II - SHAREHOLDERS
Section 1. Meeting Locations.
All meetings of shareholders shall be held at the principal office of
the corporation or at such other place or places within or without the State of
California as may be designatd by the Board of Directors (the "Board"). In the
event such places shall prove inadequate in capacity for any meeting of
shareholders, an adjournment may be taken to and the meeting held at such other
place of adequate capacity as may be designated by the officer of the
corporation presiding at such meeting.
Section 2. Annual Meetings.
The 2001 annual meeting of shareholders shall be held on May 14, 2001, and
all annual meetings of shareholders thereafter shall be held on the third
Thursday of the month of April of each year at such time as the Chairman of the
Board shall designate on said day to elect directors to hold office for the year
next ensuing and until their successors shall be elected, and to consider and
act upon such other matters as may lawfully be presented to such meeting;
provided, however, that should said day fall upon a legal holiday, then any such
annual meeting of shareholders shall be held at such designated time and place
on the next day thereafter ensuing which is not a legal holiday.
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Section 3. Special Meetings.
Special meetings of the shareholders may be called at any time by the
Board, the Chairman of the Board, the President, or upon written request of any
three members of the Board, or by the holders of shares entitled to cast not
less than ten percent of the votes at such meeting. Upon request in writing to
the Chairman of the Board, the President, any Vice President or the Secretary by
any person (other than the Board) entitled to call a special meeting of
shareholders, the officer forthwith shall cause notice to be given to the
shareholders entitled to vote that a meeting will be held at a time requested by
the person or persons calling the meeting, not less than thirty-five nor more
than sixty days after the receipt of the request. If the notice is not given
within twenty days after receipt of the request, the persons entitled to call
the meeting may give the notice.
Section 4. Notice of Annual or Special Meeting.
Written notice of each annual or special meeting of shareholders shall be
given not less than ten (or if sent by third-class mail, thirty) nor more than
sixty days before the date of the meeting to each shareholder entitled to vote
thereat. Such notice shall state the place, date, and hour of the meeting and
(i) in the case of a special meeting, the general nature of the business to be
transacted, and no other business may be transacted, or (ii) in the case of an
annual meeting, those matters which the Board, at the time of the mailing of the
notice, intends to present for action by the shareholders, but, subject to the
provisions of applicable law and these Bylaws, any proper matter may be
presented at an annual meeting for such action. The notice of any special or
annual meeting at which directors are to be elected shall include the names of
nominees intended at the time of the notice to be presented by the Board for
election. For any matter to be presented by a shareholder at an annual meeting
held after December 31, 1993, but on or before December 31, 1999, including the
nomination of any person (other than a person nominated by or at the direction
of the Board) for election to the Board, written notice must be received by the
Secretary of the corporation from the shareholder not less than sixty nor more
than one hundred twenty days prior to the date of the annual meeting specified
in these Bylaws and to which the shareholder's notice relates; provided however,
that in the event the annual meeting to which the shareholder's written notice
relates is to be held on a date which is more than thirty days earlier than the
date of the annual meeting specified in these Bylaws, the notice from a
shareholder must be received by the Secretary not later than the close of
business on the tenth day following the date on which public disclosure of the
date of the annual meeting was made or given to the shareholders. For any matter
to be presented by a shareholder at an annual meeting held after December 31,
1999, including the nomination of any person (other than a person nominated by
or at the direction of the Board) for election to the Board, written notice must
be received
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by the Secretary of the corporation from the shareholder not more than one
hundred eighty days nor less than one hundred twenty days prior to the date on
which the proxy materials for the prior year's annual meeting were first
released to shareholders by the corporation; provided however, that in the event
the annual meeting to which the shareholder's written notice relates is to be
held on a date which is more than thirty days earlier or later than the date of
the annual meeting specified in these Bylaws, the notice from a shareholder must
be received by the Secretary not earlier than two hundred twenty days prior to
the date of the annual meeting to which the shareholder's notice relates nor
later than one hundred sixty days prior to the date of such annual meeting,
unless less than one hundred seventy days' prior public disclosure of the date
of the meeting is made by the earliest possible quarterly report on Form 10-Q,
or, if impracticable, any means reasonably calculated to inform shareholders
including without limitation a report on Form 8-K, a press release or
publication once in a newspaper of general circulation in the county in which
the principal office is located, in which event notice by the shareholder to be
timely must be received not later than the close of business on the tenth day
following the date of such public disclosure. The shareholder's notice to the
Secretary shall set forth (a) a brief description of each matter to be presented
at the annual meeting by the shareholder; (b) the name and address, as they
appear on the corporation's books, of the shareholder; (c) the class and number
of shares of the corporation which are beneficially owned by the shareholder;
and (d) any material interest of the shareholder in the matters to be presented.
Any shareholder who intends to nominate a candidate for election as a director
shall also set forth in such a notice (i) the name, age, business address and
residence address of each nominee that he or she intends to nominate at the
meeting, (ii) the principal occupation or employment of each nominee, (iii) the
class and number of shares of capital stock of the corporation beneficially
owned by each nominee, and (iv) any other information concerning the nominee
that would be required under the rules of the Securities and Exchange Commission
in a proxy statement soliciting proxies for the election of the nominee. The
notice shall also include a consent, signed by the shareholder's nominees, to
serve as a director of the corporation if elected. Notwithstanding anything in
these Bylaws to the contrary, and subject to the provisions of any applicable
law, no business shall be conducted at a special or annual meeting except in
accordance with the procedures set forth in this Section 4.
Notice of a shareholders' meeting shall be given either personally or by
first-class mail (or, if the outstanding shares of the corporation are held of
record by 500 or more persons on the record date for the meeting, by third-class
mail) or by other means of written communication, addressed to the shareholder
at the address of such shareholder appearing on the books of the corporation or
given by the shareholder to the corporation for the purpose of notice; or, if no
such address appears or is given, at the place where the principal office of the
corporation is located or by publication at least once in a newspaper of general
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circulation in the county in which the principal office is located. Notice by
mail shall be deemed to have been given at the time a written notice is
deposited in the United States mails, postage prepaid. Any other written notice
shall be deemed to have been given at the time it is personally delivered to the
recipient or is delivered to a common carrier for transmission, or actually
transmitted by the person giving the notice by electronic means, to the
recipient.
Section 5. Quorum.
A majority of the shares entitled to vote, represented in person or by
proxy, shall constitute a quorum at any meeting of shareholders. The affirmative
vote of a majority of the shares represented and voting at a duly held meeting
at which a quorum is present (which shares voting affirmatively also constitute
at least a majority of the required quorum) shall be the act of the
shareholders, unless the vote of a greater number or voting by classes is
required by law or the Articles; provided, however, that the shareholders
present at a duly called or held meeting at which a quorum is present may
continue to do business until adjournment, notwithstanding the withdrawal of
enough shareholders to have less than a quorum, if any action taken (other than
adjournment) is approved by at least a majority of the shares required to
constitute a quorum.
Section 6. Adjourned Meeting and Notice Thereof.
Any shareholders' meeting, whether or not a quorum is present, may be
adjourned from time to time by the vote of a majority of the shares, the holders
of which are either present in person or represented by proxy thereat, but in
the absence of a quorum (except as provided in Section 5 of this Article) no
other business may be transacted at such meeting.
It shall not be necessary to give any notice of the time and place of the
adjourned meeting or of the business to be transacted thereat, other than by
announcement at the meeting at which such adjournment is taken. At the adjourned
meeting, the corporation may transact any business which might have been
transacted at the original meeting. However, when any shareholders' meeting is
adjourned for more than forty-five days or, if after adjournment a new record
date is fixed for the adjourned meeting, notice of the adjourned meeting shall
be given as in the case of an original meeting.
Section 7. Voting.
The shareholders entitled to notice of any meeting or to vote at any such
meeting shall be only persons in whose name shares stand on the stock records of
the corporation on the record date determined in accordance with Section 8 of
this Article.
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Voting shall in all cases be subject to the provisions of Chapter 7 of the
California General Corporation Law, and to the following provisions:
(a) Subject to clause (g), shares held by an administrator, executor,
guardian, conservator or custodian may be voted by such holder either in person
or by proxy, without a transfer of such shares into the holder's name; and
shares standing in the name of a trustee may be voted by the trustee, either in
person or by proxy, but no trustee shall be entitled to vote shares held by such
trustee without a transfer of such shares into the trustee's name.
(b) Shares standing in the name of a receiver may be voted by such
receiver; and shares held by or under the control of a receiver may be voted by
such receiver without the transfer thereof into the receiver's name if authority
to do so is contained in the order of the court by which such receiver was
appointed.
(c) Subject to the provisions of Section 705 of the California General
Corporation Law and except where otherwise agreed in writing between the
parties, a shareholder whose shares are pledged shall be entitled to vote such
shares until the shares have been transferred into the name of the pledgee, and
thereafter the pledgee shall be entitled to vote the shares so transferred.
(d) Shares standing in the name of a minor may be voted and the corporation
may treat all rights incident thereto as exercisable by the minor, in person or
by proxy, whether or not the corporation has notice, actual or constructive, of
the non-age unless a guardian of the minor's property has been appointed and
written notice of such appointment given to the corporation.
(e) Shares standing in the name of another corporation, domestic or
foreign, may be voted by such officer, agent or proxyholder as the bylaws of
such other corporation may prescribe or, in the absence of such provision, as
the Board of Directors of such other corporation may determine or, in the
absence of such determination, by the chairman of the board, president or any
vice president of such other corporation, or by any other person authorized to
do so by the chairman of the board, president or any vice president of such
other corporation. Shares which are purported to be voted or any proxy purported
to be executed in the name of a corporation (whether or not any title of the
person signing is indicated) shall be presumed to be voted or the proxy executed
in accordance with the provisions of this subdivision, unless the contrary is
shown.
(f) Shares of the corporation owned by any of its subsidiaries shall not be
entitled to vote on any matter.
5
(g) Shares of the corporation held by the corporation in a fiduciary
capacity, and shares of the corporation held in a fiduciary capacity by any of
its subsidiaries, shall not be entitled to vote on any matter, except to the
extent that the settlor or beneficial owner possesses and exercises a right to
vote or to give the corporation binding instructions as to how to vote such
shares.
(h) If shares stand of record in the names of two or more persons, whether
fiduciaries, members of a partnership, joint tenants, tenants in common, husband
and wife as community property, tenants by the entirety, voting trustees,
persons entitled to vote under a shareholder voting agreement or otherwise, or
if two or more persons (including proxyholders) have the same fiduciary
relationship respecting the same shares, unless the secretary of the corporation
is given written notice to the contrary and is furnished with a copy of the
instrument or order appointing them or creating the relationship wherein it is
so provided, their acts with respect to voting shall have the following effect:
(i) If only one votes, such act binds all;
(ii) If more than one vote, the act of the majority so voting binds all;
(iii) If more than one vote, but the vote is evenly split on any particular
matter, each faction may vote the securities in question
proportionately.
If the instrument so filed or the registration of the shares shows that any
such tenancy is held in unequal interests, a majority or even split for the
purpose of this section shall be a majority or even split in interest.
No shareholder of any class of stock of this corporation shall be entitled
to cumulate votes at any election of directors of this corporation.
Elections for directors need not be by ballot; provided, however, that all
elections for directors must be by ballot upon demand made by a shareholder at
the meeting and before the voting begins.
In any election of directors, the candidates receiving the highest number
of votes of the shares entitled to be voted for them up to the number of
directors to be elected by such shares are elected.
Section 8. Record Date.
The Board may fix, in advance, a record date for the determination of the
shareholders entitled to notice of any meeting or to vote or entitled to receive
payment of any dividend or other distribution, or any allotment of rights, or to
6
exercise rights in respect of any other lawful action. The record date so fixed
shall be not more than sixty days nor less than ten days prior to the date of
the meeting nor more than sixty days prior to any other action. When a record
date is so fixed, only shareholders of record at the close of business on that
date are entitled to notice of and to vote at the meeting or to receive the
dividend, distribution, or allotment of rights, or to exercise the rights, as
the case may be, notwithstanding any transfer of shares on the books of the
corporation after the record date, except as otherwise provided by law or these
Bylaws. A determination of shareholders of record entitled to notice of or to
vote at a meeting of shareholders shall apply to any adjournment of the meeting
unless the Board fixes a new record date for the adjourned meeting. The Board
shall fix a new record date if the meeting is adjourned for more than forty-five
days.
If no record date is fixed by the Board, the record date for determining
shareholders entitled to notice of or to vote at a meeting of shareholders shall
be at the close of business on the business day next preceding the day on which
notice is given or, if notice is waived, at the close of business on the
business day next preceding the day on which the meeting is held. The record
date for determining shareholders for any purpose other than as set forth in
this Section 8 or Section 10 of this Article shall be at the close of business
on the day on which the Board adopts the resolution relating thereto, or the
sixtieth day prior to the date of such other action, whichever is later.
Section 9. Consent of Absentees.
The transactions of any meeting of shareholders, however called and
noticed, and wherever held, are as valid as though had at a meeting duly held
after regular call and notice, if a quorum is present either in person or by
proxy, and if, either before or after the meeting, each of the persons entitled
to vote, not present in person or by proxy, signs a written waiver of notice or
a consent to the holding of the meeting or an approval of the minutes thereof.
All such waivers, consents or approvals shall be filed with the corporate
records or made a part of the minutes of the meeting. Neither the business to be
transacted at nor the purpose of any regular or special meeting of shareholders
need be specified in any written waiver of notice, consent to the holding of the
meeting or approval of the minutes thereof, except as provided in Section 601
(f) of the California General Corporation Law.
Section 10. Action Without Meeting.
Subject to Section 603 of the California General Corporation Law, any
action which, under any provision of the California General Corporation Law, may
be taken at any annual or special meeting of shareholders may be taken without a
meeting and without prior notice if a consent in writing, setting forth the
7
action so taken, shall be signed by the holders of outstanding shares having not
less than the minimum number of votes that would be necessary to authorize or
take such action at a meeting at which all shares entitled to vote thereon were
present and voted. Unless a record date for voting purposes be fixed as provided
in Section 8 of this Article, the record date for determining shareholders
entitled to give consent pursuant to this Section 10, when no prior action by
the Board has been taken, shall be the day on which the first written consent is
given.
Section 11. Proxies.
Every person entitled to vote shares has the right to do so either in
person or by one or more persons, not to exceed three, designated by a proxy
authorized by such shareholder or the shareholder's attorney in fact and filed
with the corporation, in accordance with Cal. Corp. Code ss.178. Subject to the
following sentence, any proxy duly authorized continues in full force and effect
until revoked by the person authorizing it prior to the vote pursuant thereto by
a writing delivered to the corporation stating that the proxy is revoked or by a
subsequent proxy authorized by the person authorizing the prior proxy and
presented to the meeting, or by attendance at the meeting and voting in person
by the person authorizing the proxy; provided, however, that a proxy is not
revoked by the death or incapacity of the maker unless, before the vote is
counted, written notice of such death or incapacity is received by this
corporation. No proxy shall be valid after the expiration of eleven months from
the date of its authorization unless otherwise provided in the proxy.
Section 12. Inspectors of Election.
In advance of any meeting of shareholders, the Board may appoint any
persons other than nominees as inspectors of election to act at such meeting and
any adjournment thereof. If inspectors of election are not so appointed, or if
any persons so appointed fail to appear or refuse to act, the chairman of any
such meeting may, and on the request of any shareholder or shareholder's proxy
shall, make such appointments at the meeting. The number of inspectors shall be
either one or three. If appointed at a meeting on the request of one or more
shareholders or proxies, the majority of shares present shall determine whether
one or three inspectors are to be appointed.
The duties of such inspectors shall be as prescribed by Section 707 (b) of
the California General Corporation Law and shall include: determining the number
of shares outstanding and the voting power of each, the shares represented at
the meeting, the existence of a quorum, and the authenticity, validity and
effect of proxies; receiving votes, ballots or consents; hearing and determining
all challenges and questions in any way arising in connection with the right to
vote; counting and tabulating all votes or consents; determining when
8
ARTICLE III
the polls shall close; determining the result; and doing such acts as may be
proper to conduct the election or vote with fairness to all shareholders. If
there are three inspectors of election, the decision, act or certificate of a
majority is effective in all respects as the decision, act or certificate of
all. Any report or certificate made by the inspectors of election is prima facie
evidence of the facts stated therein.
ARTICLE III - DIRECTORS
Section 1. Powers.
Subject to limitations of the Articles, of these Bylaws and of the
California General Corporation Law relating to action required to be approved by
the shareholders or by the outstanding shares, the business and affairs of the
corporation shall be managed and all corporate powers shall be exercised by or
under the direction of the Board. The Board may delegate the management of the
day-to-day operation of the business of the corporation provided that the
business and affairs of the corporation shall be managed and all corporate
powers shall be exercised under the ultimate direction of the Board. Without
prejudice to such general powers, but subject to the same limitations, it is
hereby expressly declared that the Board shall have the following powers in
addition to the other powers enumerated in these Bylaws:
(a) To select and remove all the other officers, agents and employees of
the corporation, prescribe the powers and duties for them as may not be
inconsistent with law, with the Articles or these Bylaws, fix their compensation
and require from them security for faithful service.
(b) To conduct, manage and control the affairs and business of the
corporation and to make such rules and regulations therefor not inconsistent
with law, or with the Articles or these Bylaws, as they may deem best.
(c) To adopt, make and use a corporate seal, and to prescribe the forms of
certificates of stock, and to alter the form of such seal and of such
certificates from time to time as in their judgment they may deem best.
(d) To authorize the issuance of shares of stock of the corporation from
time to time, upon such terms and for such consideration as may be lawful.
(e) To borrow money and incur indebtedness for the purposes of the
corporation, and to cause to be executed and delivered therefor, in the
corporate name, promissory notes, bonds, debentures, deeds of trust, mortgages,
pledges, hypothecations or other evidences of debt and securities therefor.
9
Section 2. Number of Directors.
The authorized number of directors shall be not less than nine nor more
than seventeen until changed by amendment of the Articles or by a Bylaw duly
adopted by the shareholders. The exact number of directors shall be fixed,
within the limits specified, by the Board by adoption of a resolution or by the
shareholders in the same manner provided in these Bylaws for the amendment
thereof.
Section 3. Election and Term of Office.
The directors shall be elected at each annual meeting of the shareholders,
but if any such annual meeting is not held or the directors are not elected
thereat, the directors may be elected at any special meeting of shareholders
held for that purpose. Each director shall hold office until the next annual
meeting and until a successor has been elected and qualified.
Section 4. Vacancies.
Any director may resign effective upon giving written notice to the
Chairman of the Board, the President, the Secretary or the Board, unless the
notice specifies a later time for the effectiveness of such resignation. If the
resignation is effective at a future time, a successor may be elected to take
office when the resignation becomes effective.
Vacancies in the Board, except those existing as a result of a removal of a
director, may be filled by a majority of the remaining directors, though less
than a quorum, or by a sole remaining director, and each director so elected
shall hold office until the next annual meeting and until such director's
successor has been elected and qualified. Vacancies existing as a result of a
removal of a director may be filled by the shareholders as provided by law.
A vacancy or vacancies in the Board shall be deemed to exist in case of the
death, resignation or removal of any director, or if the authorized number of
directors be increased, or if the shareholders fail, at any annual or special
meeting of shareholders at which any director or directors are elected, to elect
the full authorized number of directors to be voted for at that meeting.
The Board may declare vacant the office of a director who has been declared
of unsound mind by an order of court or convicted of a felony.
The shareholders may elect a director or directors at any time to fill any
vacancy or vacancies not filled by the directors. Any such election by written
consent other than to fill a vacancy created by removal requires the consent of
a
10
majority of the outstanding shares entitled to vote. If the Board accepts the
resignation of a director tendered to take effect at a future time, the Board or
the shareholders shall have power to elect a successor to take office when the
resignation is to become effective.
No reduction of the authorized number of directors shall have the effect of
removing any director prior to the expiration of the director's term of office.
Section 5. Place of Meeting.
Regular or special meetings of the Board shall be held at any place within
or without the State of California which has been designated from time to time
by the Board or as provided in these Bylaws. In the absence of such designation,
regular meetings shall be held at the principal office of the corporation.
Section 6. Organization Meeting.
Promptly following each annual meeting of shareholders the Board shall hold
a regular meeting for the purpose of organization, election of officers and the
transaction of other business.
Section 7. Special Meetings and Other Regular Meetings.
Special meetings and regular meetings other than organization meetings of
the Board for any purpose or purposes may be called at any time by the Chairman
of the Board, the President, any Vice President, the Secretary or by any two
directors.
Such meetings of the Board shall be held upon four days' notice by mail or
forty-eight hours' notice delivered personally or by telephone, including a
voice messaging system or other system or technology designed to record and
communicate messages, telegraph, telex, facsimile, electronic mail or other
similar means of communication. Any such notice shall be addressed or delivered
to each director at such director's address, telephone number, telex number,
facsimile number, E-mail address, or other designated location(s), as shown upon
the records of the corporation or as may have been given to the corporation by
the director for purposes of notice or, if such information is not shown on such
records or is not readily ascertainable, at the place in which the meetings of
the directors are regularly held. The notice need not specify the purpose of
such meeting.
Notice by mail shall be deemed to have been given at the time a written
notice is deposited in the United States mail, postage prepaid. Any other
written notice shall be deemed to have been given at the time it is personally
delivered to the recipient or is delivered to a common carrier for transmission,
or actually transmitted by the person giving the notice by electronic means to
the recipient.
11
Oral notice shall be deemed to have been given at the time it is communicated,
in person or by telephone, wireless, or other similar means, to the recipient or
to a person at the office of the recipient who the person giving the notice has
reason to believe will promptly communicate it to the recipient, or actually
transmitted to the recipient by the person giving the notice by a system or
technology designed to record and communicate messages.
Section 8. Quorum.
One-third of the number of authorized directors constitutes a quorum of the
Board for the transaction of business, except to adjourn as provided in Section
ll of this Article. Every act or decision done or made by a majority of the
directors present at a meeting duly held at which a quorum is present shall be
regarded as the act of the Board, unless a greater number is required by law or
by the Articles; provided, however, that a meeting at which a quorum is
initially present may continue to transact business notwithstanding the
withdrawal of directors, if any action taken is approved by at least a majority
of the required quorum for such meeting.
Section 9. Participation in Meetings by Conference Telephone.
Members of the Board may participate in a meeting through use of conference
telephone or similar communications equipment, so long as all members
participating in such meeting can hear one another. Such participation
constitutes presence in person at such meeting.
Section 10. Waiver of Notice.
The transactions of any meeting of the Board, however called and noticed or
wherever held, are as valid as though had at a meeting duly held after regular
call and notice if a quorum is present and if, either before or after the
meeting, each of the directors not present signs a written waiver of notice, a
consent to holding such meeting or an approval of the minutes thereof. All such
waivers, consents or approvals shall be filed with the corporate records or made
a part of the minutes of the meeting.
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Section 11. Adjournment.
A majority of the directors present, whether or not a quorum is present,
may adjourn any directors' meeting to another time and place. Notice of the time
and place of holding an adjourned meeting need not be given to absent directors
if the time and place is fixed at the meeting adjourned. If the meeting is
adjourned for more than twenty-four hours, notice of any adjournment to another
time or place shall be given prior to the time of the adjourned meeting to the
directors who were not present at the time of the adjournment.
Section 12. Fees and Compensation.
Directors and members of committees may receive such compensation, if any,
for their services, and such reimbursement for expenses, as may be fixed or
determined by the Board.
Section 13. Action Without Meeting.
Any action required or permitted to be taken by the Board may be taken
without a meeting if all members of the Board shall individually or collectively
consent in writing to such action. Such written consent or consents shall have
the same force and effect as a unanimous vote of the Board and shall be filed
with the minutes of the proceedings of the Board.
Section 14. Rights of Inspection.
Every director shall have the absolute right at any reasonable time to
inspect and copy all books, records and documents of every kind and to inspect
the physical properties of the corporation and also of its subsidiary
corporations, domestic or foreign. Such inspection by a director may be made in
person or by agent or attorney and includes the right to copy and make extracts.
Section 15. Committees.
The Board may appoint one or more committees, each consisting of two or
more directors, to serve at the pleasure of the Board. The Board may delegate to
such committees any or all of the authority of the Board except with respect to:
(a) The approval of any action for which the California General Corporation
Law also requires shareholders' approval or approval of the outstanding shares;
(b) The filling of vacancies on the Board or in any committee;
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ARTICLE IV
(c) The fixing of compensation of the directors for serving on the Board
or on any committee;
(d) The amendment or repeal of Bylaws or the adoption of new Bylaws;
(e) The amendment or repeal of any resolution of the Board which by its
express terms is not so amendable or repealable;
(f) A distribution to the shareholders of the corporation except at a rate
or in a periodic amount or within a price range determined by the
Board; or
(g) The appointment of other committees of the Board or the members
thereof.
Any such committee, or any member or alternate member thereof, must be
appointed by resolution adopted by a majority of the exact number of authorized
directors as specified in Section 2 of this Article. The Board shall have the
power to prescribe the manner and timing of giving of notice of regular or
special meetings of any committee and the manner in which proceedings of any
committee shall be conducted. In the absence of any such prescription, such
committee shall have the power to prescribe the manner in which its proceedings
shall be conducted. Unless the Board or such committee shall otherwise provide,
the regular and special meetings and other actions of any such committee shall
be governed by the provisions of this Article applicable to meetings and actions
of the Board. Minutes shall be kept of each meeting of each committee.
ARTICLE IV - OFFICERS
Section 1. Officers.
The officers of the corporation shall be a Chairman of the Board, a
President, a Chief Financial Officer, one or more Vice Presidents, a General
Counsel, one or more Associate General Counsel, one or more Assistant General
Counsel, a Controller, one or more Assistant Controllers, a Treasurer, one or
more Assistant Treasurers, a Secretary and one or more Assistant Secretaries,
and such other officers as may be elected or appointed in accordance with
Section 5 of this Article. The Board, the Chairman of the Board or the President
may confer a special title upon any Vice President not specified herein. Any
number of offices of the corporation may be held by the same person.
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Section 2. Election.
The officers of the corporation, except such officers as may be elected or
appointed in accordance with the provisions of Section 5 or Section 6 of this
Article, shall be chosen annually by, and shall serve at the pleasure of the
Board, and shall hold their respective offices until their resignation, removal,
or other disqualification from service, or until their respective successors
shall be elected.
Section 3. Eligibility of Chairman or President.
No person shall be eligible for the office of Chairman of the Board or
President unless such person is a member of the Board of the corporation; any
other officer may or may not be a director.
Section 4. Removal and Resignation.
Any officer may be removed, either with or without cause, by the Board at
any time or by any officer upon whom such power or removal may be conferred by
the Board. Any such removal shall be without prejudice to the rights, if any, of
the officer under any contract of employment of the officer.
Any officer may resign at any time by giving written notice to the
corporation, but without prejudice to the rights, if any, of the corporation
under any contract to which the officer is a party. Any such resignation shall
take effect at the date of the receipt of such notice or at any later time
specified therein and, unless otherwise specified therein, the acceptance of
such resignation shall not be necessary to make it effective.
Section 5. Appointment of Other Officers.
The Board may appoint such other officers as the business of the
corporation may require, each of whom shall hold office for such period, have
such authority, and perform such duties as are provided in the Bylaws or as the
Board may from time to time determine.
Section 6. Vacancies.
A vacancy in any office because of death, resignation, removal,
disqualification or any other cause shall be filled at any time deemed
appropriate by the Board in the manner prescribed in these Bylaws for regular
election or appointment to such office.
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Section 7. Salaries.
The salaries of the Chairman of the Board, President, Chief Financial
Officer, Vice Presidents, General Counsel, Controller, Treasurer and Secretary
of the corporation shall be fixed by the Board. Salaries of all other officers
shall be as approved from time to time by the chief executive officer.
Section 8. Furnish Security for Faithfulness.
Any officer or employee shall, if required by the Board, furnish to the
corporation security for faithfulness to the extent and of the character that
may be required.
Section 9. Chairman's Duties; Succession to Such Duties in
Chairman's Absence or Disability.
The Chairman of the Board shall be the chief executive officer of the
corporation and shall preside at all meetings of the shareholders and of the
Board. Subject to the Board, the Chairman of the Board shall have charge of the
business of the corporation, including the construction of its plants and
properties and the operation thereof. The Chairman of the Board shall keep the
Board fully informed, and shall freely consult them concerning the business of
the corporation.
In the absence or disability of the Chairman of the Board, the President
shall act as the chief executive officer of the corporation; in the absence or
disability of the Chairman of the Board and the President, the next in order of
election by the Board of the Vice Presidents shall act as chief executive
officer of the corporation.
In the absence or disability of the Chairman of the Board, the President
shall act as Chairman of the Board at meetings of the Board; in the absence or
disability of the Chairman of the Board and the President, the next, in order of
election by the Board, of the Vice Presidents who is a member of the Board shall
act as Chairman of the Board at any such meeting of the Board; in the absence or
disability of the Chairman of the Board, the President, and such Vice Presidents
who are members of the Board, the Board shall designate a temporary Chairman to
preside at any such meeting of the Board.
Section 10. President's Duties.
The President shall perform such other duties as the Chairman of the Board
shall delegate or assign to such officer.
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Section 11. Chief Financial Officer.
The Chief Financial Officer of the corporation shall be the chief
consulting officer in all matters of financial import and shall have control
over all financial matters concerning the corporation.
Section 12. Vice Presidents' Duties.
The Vice Presidents shall perform such other duties as the chief
executive officer shall designate.
Section 13. General Counsel's Duties.
The General Counsel shall be the chief consulting officer of the
corporation in all legal matters and, subject to the chief executive officer,
shall have control over all matters of legal import concerning the corporation.
Section 14. Associate General Counsel's and Assistant General
Counsel's Duties.
The Associate General Counsel shall perform such of the duties of the
General Counsel as the General Counsel shall designate, and in the absence
or disability of the General Counsel, the Associate General Counsel, in order of
election to that office by the Board at its latest organizational meeting, shall
perform the duties of the General Counsel. The Assistant General Counsel shall
perform such duties as the General Counsel shall designate.
Section 15. Controller's Duties.
The Controller shall be the chief accounting officer of the Corporation
and, subject to the Chief Financial Officer, shall have control over all
accounting matters concerning the Corporation and shall perform such other
duties as the Chief Executive Officer shall designate.
Section 16. Assistant Controllers' Duties.
The Assistant Controllers shall perform such of the duties of the
Controller as the Controller shall designate, and in the absence or disability
of the Controller, the Assistant Controllers, in order of election to that
office by the Board at its latest organizational meeting, shall perform the
duties of the Controller.
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Section 17. Treasurer's Duties.
It shall be the duty of the Treasurer to keep in custody or control all
money, stocks, bonds, evidences of debt, securities and other items of value
that may belong to, or be in the possession or control of, the corporation, and
to dispose of the same in such manner as the Board or the chief executive
officer may direct, and to perform all acts incident to the position of
Treasurer.
Section 18. Assistant Treasurers' Duties.
The Assistant Treasurers shall perform such of the duties of the Treasurer
as the Treasurer shall designate, and in the absence or disability of the
Treasurer, the Assistant Treasurers, in order of election to that office by the
Board at its latest organizational meeting, shall perform the duties of the
Treasurer, unless action is taken by the Board as contemplated in Article IV,
Section 22.
Section 19. Secretary's Duties.
The Secretary shall keep or cause to be kept full and complete records of
the proceedings of shareholders, the Board and its committees at all meetings,
and shall affix the corporate seal and attest by signing copies of any part
thereof when required.
The Secretary shall keep, or cause to be kept, a copy of the Bylaws of the
corporation at the principal office in accordance with Section 213 of the
California General Corporation Law.
The Secretary shall be the custodian of the corporate seal and shall affix
it to such instruments as may be required.
The Secretary shall keep on hand a supply of blank stock certificates of
such forms as the Board may adopt.
The Secretary shall serve or cause to be served by publication or
otherwise, as may be required, all notices of meetings and of other corporate
acts that may by law or otherwise be required to be served, and shall make or
cause to be made and filed in the principal office of the corporation, the
necessary certificate or proofs thereof.
An affidavit of mailing of any notice of a shareholders' meeting or of any
report, in accordance with the provisions of Section 601 (b) of the California
General Corporation Law, executed by the Secretary shall be prima facie evidence
of the fact that such notice or report had been duly given.
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The Secretary may, with the Chairman of the Board, the President, or a Vice
President, sign certificates of ownership of stock in the corporation, and shall
cause all certificates so signed to be delivered to those entitled thereto.
The Secretary shall keep all records required by the California General
Corporation Law.
The Secretary shall generally perform the duties usual to the office of
secretary of corporations, and such other duties as the chief executive officer
shall designate.
Section 20. Assistant Secretaries' Duties.
Assistant Secretaries shall perform such of the duties of the Secretary as
the Secretary shall designate, and in the absence or disability of the
Secretary, the Assistant Secretaries, in the order of election to that office by
the Board at its latest organizational meeting, shall perform the duties of the
Secretary, unless action is taken by the Board as contemplated in Article IV,
Sections 21 and 22 of these Bylaws.
Section 21. Secretary Pro Tempore.
At any meeting of the Board or of the shareholders from which the Secretary
is absent, a Secretary pro tempore may be appointed and act.
Section 22. Election of Acting Treasurer or Acting Secretary.
The Board may elect an Acting Treasurer, who shall perform all the duties
of the Treasurer during the absence or disability of the Treasurer, and who
shall hold office only for such a term as shall be determined by the Board.
The Board may elect an Acting Secretary, who shall perform all the duties
of the Secretary during the absence or disability of the Secretary, and who
shall hold office only for such a term as shall be determined by the Board.
Whenever the Board shall elect either an Acting Treasurer or Acting
Secretary, or both, the officers of the corporation as set forth in Article IV,
Section 1 of these Bylaws, shall include as if therein specifically set out, an
Acting Treasurer or an Acting Secretary, or both.
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ARTICLE V
Section 23. Performance of Duties.
Officers shall perform the duties of their respective offices as stated in
these Bylaws, and such additional duties as the Board shall designate.
ARTICLE V - OTHER PROVISIONS
Section 1. Inspection of Corporate Records.
(a) A shareholder or shareholders holding at least five percent in the
aggregate of the outstanding voting shares of the corporation or who hold at
least one percent of such voting shares and have filed a Schedule 14B with the
United States Securities and Exchange Commission relating to the election of
directors of the corporation shall have an absolute right to do either or both
of the following:
(i) Inspect and copy the record of shareholders' names and addresses and
shareholdings during usual business hours upon five business days'
prior written demand upon the corporation; or
(ii) Obtain from the transfer agent, if any, for the corporation, upon five
business days' prior written demand and upon the tender of its usual
charges for such a list (the amount of which charges shall be stated
to the shareholder by the transfer agent upon request), a list of the
shareholders' names and addresses who are entitled to vote for the
election of directors and their shareholdings, as of the most recent
record date for which it has been compiled or as of a date specified
by the shareholder subsequent to the date of demand.
(b) The record of shareholders shall also be open to inspection and copying
by any shareholder or holder of a voting trust certificate at any time during
usual business hours upon written demand on the corporation, for a purpose
reasonably related to such holder's interest as a shareholder or holder of a
voting trust certificate.
(c) The accounting books and records and minutes of proceedings of the
shareholders and the Board and committees of the Board shall be open to
inspection upon written demand on the corporation of any shareholder or holder
of a voting trust certificate at any reasonable time during usual business
hours, for a purpose reasonably related to such holder's interests as a
shareholder or as a holder of such voting trust certificate.
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(d) Any such inspection and copying under this Article may be made in
person or by agent or attorney.
Section 2. Inspection of Bylaws.
The corporation shall keep in its principle office the original or a copy
of these Bylaws as amended to date, which shall be open to inspection by
shareholders at all reasonable times during office hours.
Section 3. Contracts and Other Instruments, Loans, Notes and
Deposits of Funds.
The Chairman of the Board, the President, or a Vice President, either alone
or with the Secretary or an Assistant Secretary, or the Secretary alone, shall
execute in the name of the corporation such written instruments as may be
authorized by the Board and, without special direction of the Board, such
instruments as transactions of the ordinary business of the corporation may
require and, such officers without the special direction of the Board may
authenticate, attest or countersign any such instruments when deemed
appropriate. The Board may authorize any person, persons, entity, entities,
attorney, attorneys, attorney-in-fact, attorneys-in-fact, agent or agents, to
enter into any contract or execute and deliver any instrument in the name of and
on behalf of the corporation, and such authority may be general or confined to
specific instances.
No loans shall be contracted on behalf of the corporation and no evidences
of such indebtedness shall be issued in its name unless authorized by the Board
as it may direct. Such authority may be general or confined to specific
instances.
All checks, drafts, or other similar orders for the payment of money,
notes, or other such evidences of indebtedness issued in the name of the
corporation shall be signed by such officer or officers, agent or agents of the
corporation and in such manner as the Board or chief executive officer may
direct.
Unless authorized by the Board or these Bylaws, no officer, agent, employee
or any other person or persons shall have any power or authority to bind the
corporation by any contract or engagement or to pledge its credit or to render
it liable for any purpose or amount.
All funds of the corporation not otherwise employed shall be deposited from
time to time to the credit of the corporation in such banks, trust companies, or
other depositories as the Board may direct.
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Section 4. Certificates of Stock.
Every holder of shares of the corporation shall be entitled to have a
certificate signed in the name of the corporation by the Chairman of the Board,
the President, or a Vice President and by the Treasurer or an Assistant
Treasurer or the Secretary or an Assistant Secretary, certifying the number of
shares and the class or series of shares owned by the shareholder. Any or all of
the signatures on the certificate may be facsimile. In case any officer,
transfer agent or registrar who has signed or whose facsimile signature has been
placed upon a certificate shall have ceased to be such officer, transfer agent
or registrar before such certificate is issued, it may be issued by the
corporation with the same effect as if such person were an officer, transfer
agent or registrar at the date of issue.
Certificates for shares may be used prior to full payment under such
restrictions and for such purposes as the Board may provide; provided, however,
that on any certificate issued to represent any partly paid shares, the total
amount of the consideration to be paid therefor and the amount paid thereon
shall be stated.
Except as provided in this Section, no new certificate for shares shall be
issued in lieu of an old one unless the latter is surrendered and canceled at
the same time. The Board may, however, if any certificate for shares is alleged
to have been lost, stolen or destroyed, authorize the issuance of a new
certificate in lieu thereof, and the corporation may require that the
corporation be given a bond or other adequate security sufficient to indemnify
it against any claim that may be made against it (including expense or
liability) on account of the alleged loss, theft or destruction of such
certificate or the issuance of such new certificate.
Section 5. Transfer Agent, Transfer Clerk and Registrar.
The Board may, from time to time, appoint transfer agents, transfer clerks,
and stock registrars to transfer and register the certificates of the capital
stock of the corporation, and may provide that no certificate of capital stock
shall be valid without the signature of the stock transfer agent or transfer
clerk, and stock registrar.
Section 6. Representation of Shares of Other Corporations.
The chief executive officer or any other officer or officers authorized by
the Board or the chief executive officer are each authorized to vote, represent
and exercise on behalf of the corporation all rights incident to any and all
shares of any other corporation or corporations standing in the name of the
corporation.
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The authority herein granted may be exercised either by any such officer in
person or by any other person authorized so to do by proxy or power of attorney
duly executed by said officer.
Section 7. Stock Purchase Plans.
The corporation may adopt and carry out a stock purchase plan or agreement
or stock option plan or agreement providing for the issue and sale for such
consideration as may be fixed of its unissued shares, or of issued shares
acquired, to one or more of the employees or directors of the corporation or of
a subsidiary or to a trustee on their behalf and for the payment for such shares
in installments or at one time, and may provide for such shares in installments
or at one time, and may provide for aiding any such persons in paying for such
shares by compensation for services rendered, promissory notes or otherwise.
Any such stock purchase plan or agreement or stock option plan or agreement
may include, among other features, the fixing of eligibility for participation
therein, the class and price of shares to be issued or sold under the plan or
agreement, the number of shares which may be subscribed for, the method of
payment therefor, the reservation of title until full payment therefor, the
effect of the termination of employment and option or obligation on the part of
the corporation to repurchase the shares upon termination of employment,
restrictions upon transfer of the shares, the time limits of and termination of
the plan, and any other matters, not in violation of applicable law, as may be
included in the plan as approved or authorized by the Board or any committee of
the Board.
Section 8. Fiscal Year and Subdivisions.
The calendar year shall be the corporate fiscal year of the corporation.
For the purpose of paying dividends, for making reports and for the convenient
transaction of the business of the corporation, the Board may divide the fiscal
year into appropriate subdivisions.
Section 9. Construction and Definitions.
Unless the context otherwise requires, the general provisions, rules of
construction and definitions contained in the General Provisions of the
California Corporations Code and in the California General Corporation Law shall
govern the construction of these Bylaws.
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ARTICLE VI
ARTICLE VI - INDEMNIFICATION
Section 1. Indemnification of Directors and Officers.
Each person who was or is a party or is threatened to be made a party to or
is involved in any threatened, pending or completed action, suit or proceeding,
formal or informal, whether brought in the name of the corporation or otherwise
and whether of a civil, criminal, administrative or investigative nature
(hereinafter a "proceeding"), by reason of the fact that he or she, or a person
of whom he or she is the legal representative, is or was a director or officer
of the corporation or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation or of a partnership,
joint venture, trust or other enterprise, including service with respect to
employee benefit plans, whether the basis of such proceeding is an alleged
action or inaction in an official capacity or in any other capacity while
serving as a director or officer, shall, subject to the terms of any agreement
between the corporation and such person, be indemnified and held harmless by the
corporation to the fullest extent permissible under California law and the
corporation's Articles of Incorporation, against all costs, charges, expenses,
liabilities and losses (including attorneys' fees, judgments, fines, ERISA
excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith, and such
indemnification shall continue as to a person who has ceased to be a director or
officer and shall inure to the benefit of his or her heirs, executors and
administrators; provided, however, that (A) the corporation shall indemnify any
such person seeking indemnification in connection with a proceeding (or part
thereof) initiated by such person only if such proceeding (or part thereof) was
authorized by the Board of the corporation; (B) the corporation shall indemnify
any such person seeking indemnification in connection with a proceeding (or part
thereof) other than a proceeding by or in the name of the corporation to procure
a judgment in its favor only if any settlement of such a proceeding is approved
in writing by the corporation; (C) that no such person shall be indemnified (i)
except to the extent that the aggregate of losses to be indemnified exceeds the
amount of such losses for which the director or officer is paid pursuant to any
directors' and officers' liability insurance policy maintained by the
corporation; (ii) on account of any suit in which judgment is rendered against
such person for an accounting of profits made from the purchase or sale by such
person of securities of the corporation pursuant to the provisions of Section
16(b) of the Securities Exchange Act of 1934 and amendments thereto or similar
provisions of any federal, state or local statutory law; (iii) if a court of
competent jurisdiction finally determines that any indemnification hereunder is
unlawful; and (iv) as to circumstances in which indemnity is expressly
prohibited by Section 317 of the General Corporation Law of California (the
"Law"); and (D) that no such person shall be indemnified with regard to any
action brought by or in the right of the corporation for breach of duty to the
corporation and its
24
shareholders (a) for acts or omissions involving intentional misconduct or
knowing and culpable violation of law; (b) for acts or omissions that the
director or officer believes to be contrary to the best interests of the
corporation or its shareholders or that involve the absence of good faith on the
part of the director or officer; (c) for any transaction from which the director
or officer derived an improper personal benefit; (d) for acts or omissions that
show a reckless disregard for the director's or officer's duty to the
corporation or its shareholders in circumstances in which the director or
officer was aware, or should have been aware, in the ordinary course of
performing his or her duties, of a risk of serious injury to the corporation or
its shareholders; (e) for acts or omissions that constitute an unexcused pattern
of inattention that amounts to an abdication of the director's or officer's
duties to the corporation or its shareholders; and (f) for costs, charges,
expenses, liabilities and losses arising under Section 310 or 316 of the Law.
The right to indemnification conferred in this Article shall include the right
to be paid by the corporation expenses incurred in defending any proceeding in
advance of its final disposition; provided, however, that if the Law permits the
payment of such expenses incurred by a director or officer in his or her
capacity as a director or officer (and not in any other capacity in which
service was or is rendered by such person while a director or officer,
including, without limitation, service to an employee benefit plan) in advance
of the final disposition of a proceeding, such advances shall be made only upon
delivery to the corporation of an undertaking, by or on behalf of such director
or officer, to repay all amounts to the corporation if it shall be ultimately
determined that such person is not entitled to be indemnified.
Section 2. Indemnification of Employees and Agents.
A person who was or is a party or is threatened to be made a party to or is
involved in any proceeding by reason of the fact that he or she is or was an
employee or agent of the corporation or is or was serving at the request of the
corporation as an employee or agent of another enterprise, including service
with respect to employee benefit plans, whether the basis of such action is an
alleged action or inaction in an official capacity or in any other capacity
while serving as an employee or agent, may, subject to the terms of any
agreement between the corporation and such person, be indemnified and held
harmless by the corporation to the fullest extent permitted by California law
and the corporation's Articles of Incorporation, against all costs, charges,
expenses, liabilities and losses, (including attorneys' fees, judgments, fines,
ERISA excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith.
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Section 3. Right of Directors and Officers to Bring Suit.
If a claim under Section 1 of this Article is not paid in full by the
corporation within 30 days after a written claim has been received by the
corporation, the claimant may at any time thereafter bring suit against the
corporation to recover the unpaid amount of the claim and, if successful in
whole or in part, the claimant shall also be entitled to be paid the expense of
prosecuting such claim. Neither the failure of the corporation (including its
Board, independent legal counsel, or its shareholders) to have made a
determination prior to the commencement of such action that indemnification of
the claimant is permissible in the circumstances because he or she has met the
applicable standard of conduct, if any, nor an actual determination by the
corporation (including its Board, independent legal counsel, or its
shareholders) that the claimant has not met the applicable standard of conduct,
shall be a defense to the action or create a presumption for the purpose of an
action that the claimant has not met the applicable standard of conduct.
Section 4. Successful Defense.
Notwithstanding any other provision of this Article, to the extent that a
director or officer has been successful on the merits or otherwise (including
the dismissal of an action without prejudice or the settlement of a proceeding
or action without admission of liability) in defense of any proceeding referred
to in Section 1 or in defense of any claim, issue or matter therein, he or she
shall be indemnified against expenses (including attorneys' fees) actually and
reasonably incurred in connection therewith.
Section 5. Non-Exclusivity of Rights.
The right to indemnification provided by this Article shall not be
exclusive of any other right which any person may have or hereafter acquire
under any statute, bylaw, agreement, vote of shareholders or disinterested
directors or otherwise.
Section 6. Insurance.
The corporation may maintain insurance, at its expense, to protect itself
and any director, officer, employee or agent of the corporation or another
corporation, partnership, joint venture, trust or other enterprise against any
expense, liability or loss, whether or not the corporation would have the power
to indemnify such person against such expense, liability or loss under the Law.
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ARTICLE VII
ARTICLE VII
Section 7. Expenses as a Witness.
To the extent that any director, officer, employee or agent of the
corporation is by reason of such position, or a position with another entity at
the request of the corporation, a witness in any action, suit or proceeding, he
or she shall be indemnified against all costs and expenses actually and
reasonably incurred by him or her on his or her behalf in connection therewith.
Section 8. Indemnity Agreements.
The corporation may enter into agreements with any director, officer,
employee or agent of the corporation providing for indemnification to the
fullest extent permissible under the Law and the corporation's Articles of
Incorporation.
Section 9. Separability.
Each and every paragraph, sentence, term and provision of this Article is
separate and distinct so that if any paragraph, sentence, term or provision
hereof shall be held to be invalid or unenforceable for any reason, such
invalidity or unenforceability shall not affect the validity or enforceability
of any other paragraph, sentence, term or provision hereof. To the extent
required, any paragraph, sentence, term or provision of this Article may be
modified by a court of competent jurisdiction to preserve its validity and to
provide the claimant with, subject to the limitations set forth in this Article
and any agreement between the corporation and claimant, the broadest possible
indemnification permitted under applicable law.
Section 10. Effect of Repeal or Modification.
Any repeal or modification of this Article shall not adversely affect any
right of indemnification of a director or officer existing at the time of such
repeal or modification with respect to any action or omission occurring prior to
such repeal or modification.
ARTICLE VII - EMERGENCY PROVISIONS
Section 1. General.
The provisions of this Article shall be operative only during a national
emergency declared by the President of the United States or the person
performing the President's functions, or in the event of a nuclear, atomic or
other attack on the United States or a disaster making it impossible or
impracticable for the corporation to conduct its business without recourse to
the provisions of this
27
Article. Said provisions in such event shall override all other Bylaws of the
corporation in conflict with any provisions of this Article, and shall remain
operative so long as it remains impossible or impracticable to continue the
business of the corporation otherwise, but thereafter shall be inoperative;
provided that all actions taken in good faith pursuant to such provisions shall
thereafter remain in full force and effect unless and until revoked by action
taken pursuant to the provisions of the Bylaws other than those contained in
this Article.
Section 2. Unavailable Directors.
All directors of the corporation who are not available to perform their
duties as directors by reason of physical or mental incapacity or for any other
reason or who are unwilling to perform their duties or whose whereabouts are
unknown shall automatically cease to be directors, with like effect as if such
persons had resigned as directors, so long as such unavailability continues.
Section 3. Authorized Number of Directors.
The authorized number of directors shall be the number of directors
remaining after eliminating those who have ceased to be directors pursuant to
Section 2, or the minimum number required by law, whichever number is greater.
Section 4. Quorum.
The number of directors necessary to constitute a quorum shall be one-third
of the authorized number of directors as specified in the foregoing Section, or
such other minimum number as, pursuant to the law or lawful decree then in
force, it is possible for the Bylaws of a corporation to specify.
Section 5. Creation of Emergency Committee.
In the event the number of directors remaining after eliminating those who
have ceased to be directors pursuant to Section 2 is less than the minimum
number of authorized directors required by law, then until the appointment of
additional directors to make up such required minimum, all the powers and
authorities which the Board could by law delegate, including all powers and
authorities which the Board could delegate to a committee, shall be
automatically vested in an emergency committee, and the emergency committee
shall thereafter manage the affairs of the corporation pursuant to such powers
and authorities and shall have all other powers and authorities as may by law or
lawful decree be conferred on any person or body of persons during a period of
emergency.
28
Section 6. Constitution of Emergency Committee.
The emergency committee shall consist of all the directors remaining after
eliminating those who have ceased to be directors pursuant to Section 2,
provided that such remaining directors are not less than three in number. In the
event such remaining directors are less than three in number the emergency
committee shall consist of three persons, who shall be the remaining director or
directors and either one or two officers or employees of the corporation, as the
remaining director or directors may in writing designate. If there is no
remaining director, the emergency committee shall consist of the three most
senior officers of the corporation who are available to serve, and if and to the
extent that officers are not available, the most senior employees of the
corporation. Seniority shall be determined in accordance with any designation of
seniority in the minutes of the proceedings of the Board, and in the absence of
such designation, shall be determined by rate of remuneration. In the event that
there are no remaining directors and no officers or employees of the corporation
available, the emergency committee shall consist of three persons designated in
writing by the shareholder owning the largest number of shares of record as of
the date of the last record date.
Section 7. Powers of Emergency Committee.
The emergency committee, once appointed, shall govern its own procedures
and shall have power to increase the number of members thereof beyond the
original number, and in the event of a vacancy or vacancies therein, arising at
any time, the remaining member or members of the emergency committee shall have
the power to fill such vacancy or vacancies. In the event at any time after its
appointment all members of the emergency committee shall die or resign or become
unavailable to act for any reason whatsoever, a new emergency committee shall be
appointed in accordance with the foregoing provisions of this Article.
Section 8. Directors Becoming Available.
Any person who has ceased to be a director pursuant to the provisions of
Section 2 and who thereafter becomes available to serve as a director shall
automatically become a member of the emergency committee.
Section 9. Election of Board of Directors.
The emergency committee shall, as soon after its appointment as is
practicable, take all requisite action to secure the election of a board of
directors,
29
ARTICLE VIII
and upon such election all the powers and authorities of the emergency
committee shall cease.
Section 10. Termination of Emergency Committee.
In the event, after the appointment of an emergency committee, a
sufficient number of persons who ceased to be directors pursuant to Section 2
become available to serve as directors, so that if they had not ceased to be
directors as aforesaid, there would be enough directors to constitute the
minimum number of directors required by law, then all such persons shall
automatically be deemed to be reappointed as directors and the powers and
authorities of the emergency committee shall be at an end.
ARTICLE VIII - AMENDMENTS
Section 1. Amendments.
These Bylaws may be amended or repealed either by approval of the
outstanding shares or by the approval of the Board; provided, however, that a
Bylaw specifying or changing a fixed number of directors or the maximum or
minimum number or changing from a fixed to a variable Board or vice versa may
only be adopted by approval of the outstanding shares. The exact number of
directors within the maximum and minimum number specified in these Bylaws may be
amended by the Board alone.
EXHIBIT 10.20
EDISON INTERNATIONAL
OPTION GAIN DEFERRAL PLAN
Reinstated
September 15, 2000
OPTION GAIN DEFERRAL PLAN
TABLE OF CONTENTS
Section Title Page
- ------- ----- ----
1. PURPOSE AND AUTHORIZED SHARES.............................................1
1.1 Purposes..............................................................1
1.2 Shares Available......................................................1
1.3 Relationship to Incentive Plans.......................................2
2. DEFINITIONS...............................................................2
3. PARTICIPATION.............................................................6
3.1 General Participation Requirements....................................6
3.2 Manner and Timing of Election.........................................6
3.3 Execution of Alternative Exercise Agreement by the Company............6
4. ALTERNATIVE EXERCISE OF OPTIONS...........................................6
4.1 Form of Agreement.....................................................6
4.2 Limited Ability to Exercise Option....................................6
4.3 Termination of Alternative Exercise Agreements........................7
4.4 Other Terms of Alternative Exercise Agreements........................7
5. STOCK UNIT ACCOUNTS.......................................................7
5.1 Crediting of Stock Units..............................................8
5.2 Dividend Equivalent Credits to Stock Unit Accounts....................8
5.3 Vesting.............................................................. 8
5.4 Distribution of Benefits..............................................8
5.5 Adjustments in Case of Changes in Common Stock.......................11
5.6 Company's Right to Withhold..........................................11
6. ADMINISTRATION...........................................................12
6.1 The Administrator....................................................12
6.2 Committee Action.....................................................12
6.3 Rights and Duties....................................................12
6.4 Indemnity and Liability..............................................13
6.5 Claims Procedure.....................................................13
OPTION GAIN DEFERRAL PLAN
TABLE OF CONTENTS
Section Title Page
- ------- ----- ----
7. PLAN CHANGES AND TERMINATION.............................................14
7.1 Amendments...........................................................14
7.2 Term.................................................................14
8. MISCELLANEOUS............................................................15
8.1 Limitation on Participant Rights.....................................15
8.2 Beneficiary Designation..............................................15
8.3 Payments to Minors or Persons Under Incapacity.......................16
8.4 Stock Units and Other Benefits Not Assignable;
Obligations Binding Upon Successors..................................16
8.5 Employment Taxes.....................................................16
8.6 Governing Law; Severability..........................................16
8.7 Compliance With Laws.................................................16
8.8 Plan Construction....................................................17
8.9 Headings Not Part of Plan............................................17
EDISON INTERNATIONAL
OPTION GAIN DEFERRAL PLAN
Restated September 15, 2000
1.
PURPOSE AND AUTHORIZED SHARES
1.1 Purposes
The purpose of this Plan is to promote the ownership and retention of Shares by
Eligible Persons and to enable Eligible Persons to defer compensation that would
otherwise be realized upon exercise of a Qualifying Option and ultimately
receive the deferred compensation in the form of Shares.
1.2 Shares Available
The number of Shares that may be issued under each of the Management Plan, the
Officer Plan, the 1998 Plan (except as provided below) and the 2000 Equity Plan
as part of this Plan is limited to the aggregate number of Shares that were the
subject of the Qualifying Options granted under such Plan that are exercised
pursuant to Article IV in exchange for the crediting of Stock Units under this
Plan. If the number of Shares payable under this Plan would exceed one or more
of the limits described in the preceding sentence because of the accumulation of
Stock Units in respect of Dividend Equivalents, such excess Shares shall be
issued and charged against the Share limits under the 1998 Plan or the 2000
Equity Plan. If insufficient Shares remain under the 1998 Plan or the 2000
Equity Plan for the accumulation of Dividend Equivalents under the Management
Plan, the Officer Plan, the 1998 Plan or the 2000 Equity Plan, such excess
Shares shall be issued under other authority of the Board, or, in absence of
such other authority, may be paid (in the sole discretion of the Committee) in
cash. Shares not exceeding the number of Already-Owned Shares used under this
Plan to exercise a Qualifying Stock Option granted under the Management Plan may
be used in respect of Dividend Equivalents on the Stock Units credited with
respect to Alternatively Exercised Qualifying Options granted under the
Management Plan, but may not be used for other awards under the Incentive Plans.
Shares not exceeding the number of Already-Owned Shares used under this Plan to
exercise a Qualifying Stock Option granted under the Officer Plan may be used in
respect of Dividend Equivalents on the Stock Units credited with respect to
Alternatively Exercised Qualifying Options granted under the Officer Plan, but
may not be used for other awards under the Incentive Plans. Shares not exceeding
the number of Already-Owned Shares used under this Plan to exercise a Qualifying
Stock Option granted under the 1998 Plan or the 2000 Equity Plan may be used in
respect of Dividend Equivalents on the Stock
1
Units credited with respect to an Alternatively Exercised Qualifying Option
granted under any one of the Incentive Plans, but may not be used for other
awards under the Incentive Plans.
1.3 Relationship to Incentive Plans
This Plan constitutes a deferred compensation plan providing alternative
settlements under and as contemplated by the Incentive Plans in respect of
nonqualified stock options granted thereunder. This Plan also contemplates the
grant of Stock Units under and as contemplated by the 1998 Plan. This Plan and
all rights under it are provided under and shall be subject to and construed
consistently with the other terms of the Management Plan, the Officer Plan, the
1998 Plan or the 2000 Equity Plan, as the case may be, except as the context
otherwise requires.
2.
DEFINITIONS
Whenever the following terms are used in this Plan, they shall have the meaning
specified below unless the context clearly indicates to the contrary:
"ALREADY-OWNED SHARES" shall mean Shares owned by an Eligible Person; provided,
however, that Shares acquired by an Eligible Person from the Company under an
option or other employee benefit plan maintained by the Company or otherwise
must be held by the Eligible Person for at least six months in order to qualify
as Already-Owned Shares and, if Shares are used to pay the exercise price of an
option or other award, such Shares may not be reused as payment of the exercise
price of another option or award within six months of such prior use.
"ALTERNATIVE EXERCISE" shall mean the exercise of all or a portion of a
Qualifying Stock Option using Already-Owned Shares in exchange for a combination
of Shares and Stock Units under this Plan.
"ALTERNATIVE EXERCISE AGREEMENT" shall mean an agreement entered into between
the Company and an Eligible Person in accordance with Article IV of this Plan
pursuant to which the Eligible Person elects to defer that portion of the
proceeds of the exercise of the Qualifying Option equal to the spread in the
form of Stock Units.
"BENEFICIARY" or "BENEFICIARIES" shall mean the person, persons, trust or trusts
(or similar entity), personal representative, or other fiduciary, last
designated in writing by a Participant in accordance with the provisions of
Section 8.2 to receive the benefits specified hereunder in the event of the
Participant's death. If there is no valid Beneficiary designation in effect that
complies with the provisions of Section 8.2, or if there is no surviving
designated Beneficiary, then the Participant's surviving spouse shall be the
Beneficiary. If there is no surviving spouse to receive any benefits payable in
accordance with the preceding sentence, the duly appointed and currently acting
personal representative of the Participant's estate (which shall include either
the Participant's probate estate or living trust) shall be the Beneficiary. In
any case where there is no such
2
personal representative of the Participant's estate duly appointed and acting in
that capacity within 90 days after the Participant's death (or such extended
period as the Committee determines is reasonably necessary to allow such
personal representative to be appointed, but not to exceed 180 days after the
Participant's death), then Beneficiary or Beneficiaries shall mean the person or
persons who can verify by affidavit or court order to the satisfaction of the
Committee that they are legally entitled to receive the benefits specified
hereunder.
"BOARD" shall mean the Board of Directors of the Company.
"CHANGE IN CONTROL EVENT" shall mean any of the following:
(a) The dissolution or liquidation of the Company;
(b) The reorganization, merger or consolidation of the Company with one or more
corporations as a result of which the Company is not the surviving corporation;
(c) The sale of all or substantially all of the property of the Company;
(d) A reorganization, merger, consolidation, or other corporate transaction
which is consummated following the related occurrence of a Distribution Date (as
such term is defined in the Rights Agreement approved by the Board on November
20, 1996) and as a result of which the Company is not the surviving corporation.
"CODE" shall mean the Internal Revenue Code of 1986, as amended.
"COMMITTEE" shall mean those members of the Compensation and Executive Personnel
Committee of the Board of the Company determined under Article VI. "COMMON
STOCK" shall mean the Common Stock of the Company, subject to adjustment
pursuant to Section 5.5 of this Plan, Section 16 of the Management Plan, Section
16 of the Officer Plan, and Section 3.4 of the 1998 Plan, as the case may be.
"COMPANY" shall mean Edison International, a California corporation, and its
successors and assigns.
"CONVERSION DATE" shall mean the date that the Eligible Person exercises all or
a portion of a Qualifying Option in accordance with the Alternative Exercise
procedures under this Plan.
"DISABILITY" shall mean the permanent and total disability of the Participant as
determined by the Committee.
"DISTRIBUTION SUBACCOUNT" shall mean any subaccount established and maintained
under a Participant's Stock Unit Account to separately account for Stock Units
which are subject to different distribution elections made by the Participant.
"DIVIDEND EQUIVALENT" shall mean the amount of cash dividends or other cash
distributions paid by the Company on that number of Shares equal to the number
of Stock Units credited to a Participant's Stock Unit Account as of the
applicable record date for the dividend or other distribution, which amount
shall be credited in the form of additional Stock
3
Units to the Stock Unit Account of the Participant, as provided in Section 5.2.
"EFFECTIVE DATE" shall mean January 1, 1998.
"ELIGIBLE PERSON" shall mean any employee of the Company, Southern California
Edison Company or any other Subsidiary who is eligible to defer compensation
under the terms of the Company Executive Deferred Compensation Plan.
"EXCHANGE ACT" shall mean the Securities Exchange Act of 1934, as amended from
time to time.
"FAIR MARKET VALUE" shall mean on any date the average of the highest and lowest
sale prices of the Common Stock on the Composite Tape, as published in the
Western Edition of The Wall Street Journal, of the principal securities exchange
or market on which the Common Stock is so listed, admitted to trade, or quoted
on such date, or, if there is no trading of (or no available highest and lowest
sale prices of) the Common Stock on such date, then the average of the highest
and lowest sale prices of the Common Stock as quoted on such Composite Tape on
the next preceding date on which there was trading in such shares. If the Common
Stock is not so listed, admitted or quoted, the Committee may designate such
other exchange, market or source of data as it deems appropriate for determining
such value for purposes of this Plan.
"FINANCIAL HARDSHIP" shall mean an unexpected and unforeseen financial
disruption arising from an illness, casualty loss, sudden financial reversal, or
other such unforeseeable occurrence as determined by the Committee. Needs
arising from foreseeable events such as the purchase of a residence or education
expenses for children shall not, alone, be considered a "financial hardship."
"INCENTIVE PLANS" shall mean the Management Plan, the Officer Plan, the 1998
Plan and the 2000 Equity Plan.
"INTEREST RATE" shall mean the rate (quoted as an annual rate) that is 120% of
the federal long-term rate for compounding on a quarterly basis, determined and
published by the Secretary of the United States Department of Treasury under
Section 1274(d) of the Code, for the month for which the interest is credited.
"MANAGEMENT PLAN" shall mean the Company's Management Long-Term Incentive
Compensation Plan.
"1998 PLAN" shall mean the Company's Equity Compensation Plan.
"OFFICER PLAN" shall mean the Company's Officer Long-Term Incentive Compensation
Plan.
"PARTICIPANT" shall mean any person who has Stock Units credited to a Stock Unit
Account under this Plan. "PLAN" shall mean this Edison International Option Gain
Deferral Plan, as it may be amended from time to time.
"QUALIFYING OPTION" or "QUALIFYING STOCK OPTION" shall mean a nonqualified
4
stock option granted under one of the Incentive Plans and evidenced in writing
that provides (or is amended to provide) that the option may be Alternatively
Exercised under this Plan; provided, however, that an option shall not be a
Qualifying Stock Option if it will expire, by its terms, before the end of the
six-month period commencing with the date that the Alternative Exercise
Agreement is submitted to and received by the Company.
"RETIREMENT" shall mean a separation from service under terms constituting a
retirement for purposes of the nonqualified executive retirement plan covering
the Participant.
"RULE 16b-3" shall mean Rule 16b-3 promulgated under the Exchange Act.
"SCHEDULED WITHDRAWAL" shall mean a distribution of all or a portion of the
Stock Units credited to the Participant as elected by the Participant pursuant
to the provisions of Section 5.4(g) of the Plan.
"SHARE" shall mean a share of Common Stock.
"STOCK UNIT" or "UNIT" shall mean a non-voting unit of measurement which is
deemed solely for bookkeeping purposes to be equivalent to one outstanding Share
(subject to Section 5.5) solely for purposes of this Plan.
"STOCK UNIT ACCOUNT" shall mean the bookkeeping account maintained by the
Company on behalf of each Participant which is credited with Stock Units in
accordance with Section 5.1(a) and Dividend Equivalents thereon in accordance
with Section 5.2.
"SUBSIDIARY" shall mean any company that is a "subsidiary company" as defined in
Section 424(f) of the Code.
"TERMINATION FOR CAUSE" shall mean the Termination of Employment of the
Participant upon willful failure by the Participant to substantially perform his
or her duties for the Company or one of its Subsidiaries or the willful engaging
by the Participant in conduct which is injurious to the Company or one of its
Subsidiaries, monetarily or otherwise.
"TERMINATION OF EMPLOYMENT" shall mean the voluntary or involuntary cessation of
the Participant's employment with the Company or a Subsidiary for any reason
other than death or Retirement. Termination of Employment shall not be deemed to
have occurred for purposes of this Plan if the Participant is re-employed by the
Company or a Subsidiary within thirty days of ceasing work with the Company or a
Subsidiary.
"UNSCHEDULED WITHDRAWAL" shall mean a distribution of all or a portion of the
Stock Units credited to the Participant under the Plan as requested by the
Participant pursuant to the provisions of Section 5.4(h) of the Plan.
5
3.
PARTICIPATION
3.1 General Participation Requirements.
An Eligible Person may elect to exercise all or a portion of a Qualifying Option
under and subject to the Alternative Exercise provisions set forth herein and to
receive a credit of Stock Units under this Plan.
3.2 Manner and Timing of Election
An election must be made by the Eligible Person by completing and executing a
form of Alternative Exercise Agreement which meets the requirements of Article
IV and submitting such form to the Company after the Effective Date. Such an
election shall be irrevocable.
3.3 Execution of Alternative Exercise Agreement by the Company.
The Company, acting through any of its officers, shall execute the Alternative
Exercise Agreement form submitted by such Eligible Person and deliver a copy of
such fully executed Alternative Exercise Agreement to him or her.
4.
ALTERNATIVE EXERCISE OF OPTIONS
4.1 Form of Agreement.
Each Alternative Exercise Agreement with respect to a Qualifying Stock Option
shall be in the form approved by the Committee. Each such Alternative Exercise
Agreement shall specify the portion of the Qualifying Stock Option or Qualifying
Stock Options that the Eligible Person elects to exercise under this Plan and
shall provide that (i) the Eligible Person will exercise all or the specified
portion of such Qualifying Stock Option(s) by paying the exercise price with
Already-Owned Shares having an aggregate Fair Market Value equal to the exercise
price for the number of Shares with respect to which the Qualifying Stock Option
is exercised and (ii), upon exercise, the Company will (A) deliver to the
Eligible Person the same number of Shares used by the Eligible Employee to pay
the exercise price of the Qualifying Stock Option and (B), in lieu of the
remainder of the Shares which would otherwise be delivered to the Eligible
Person (the "Gain Shares"), credit to a Stock Unit Account established for the
Eligible Person Stock Units equal in number to the number of Gain Shares.
Subject to applicable law and the intent of this Plan, the Committee may provide
for or permit an alternative method of delivering or tendering Already-Owned
Shares to pay the exercise price of a Qualifying Stock Option.
4.2 Limited Ability to Exercise Option.
Any Qualifying Option (or portion thereof) which is subject to an Alternative
Exercise Agreement may not be exercised at all during the six-month period
following the date the Company receives the Eligible Person's Alternative
Exercise election.
6
4.3 Termination of Alternative Exercise Agreements.
If, prior to the end of the six-month period described in Section 4.2, (a) an
Eligible Person's employment with the Company (including any Subsidiary) is
terminated or (b), unless the Committee otherwise provides, a Change in Control
Event occurs, the Eligible Person's Alternative Exercise Agreement shall
terminate and the related Qualifying Option may be exercised for actual Shares
in accordance with the terms of the Qualifying Option without regard to the
Alternative Exercise Agreement. If the Company unilaterally refuses to honor an
Alternative Exercise of a Qualifying Option pursuant to Section 8.7, the
Alternative Exercise Agreement with respect to such Qualifying Option shall
terminate and such Qualifying Option shall be exercisable for actual Shares in
accordance with its terms without regard to the Alternative Exercise Agreement
or the terms of the Qualifying Option regarding Alternative Exercise.
4.4 Other Terms of Alternative Exercise Agreements.
No Alternative Exercise Agreement shall have the effect of extending the term or
otherwise changing the terms of any Qualifying Option (except as expressly
contemplated hereby in respect of the consequences of exercise). No Alternative
Exercise Agreement may be amended or terminated except as specifically provided
herein.
5.
STOCK UNIT ACCOUNTS
5.1 Crediting of Stock Units.
(a) Crediting of Stock Units. As of the applicable Conversion Date of a
Qualifying Stock Option, an Eligible Person's Stock Unit Account shall be
credited with the number of Stock Units attributable to the Gain Shares, as
described in Section 4.1(a).
(b) Distribution Subaccounts. The Committee shall establish separate
Distribution Subaccounts under a Participant's Stock Unit Account as necessary
to separately account for Stock Units that are subject to different distribution
elections made by the Participant.
(c) Limitations on Rights Associated With Units. A Participant's Stock Unit
Account shall be a memorandum account on the books of the Company. The Units
credited to a Participant's Stock Unit Account shall be used solely as a device
for the determination of the number of Shares to be eventually distributed to
such Participant in accordance with this Plan. The Units shall not be treated as
property or as a trust fund of any kind. No Participant shall be entitled to any
voting or other stockholder rights with respect to Units granted or credited
under this Plan. The number of Units credited (and the Shares to which the
Participant is entitled under this Plan) shall be subject to adjustment in
accordance with Section 5.5 of this Plan, and Section 16 of the Management Plan
or Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan or Section 3.4
of the 2000 Equity Plan, as the case may be.
7
5.2 Dividend Equivalent Credits to Stock Unit Accounts.
As of any applicable dividend or distribution payment date, a Participant's
Stock Unit Account shall be credited with additional Units in an amount equal to
the amount of the Dividend Equivalents divided by the Fair Market Value of a
Share as of the applicable dividend payment date. If the limit on the number of
Shares available under this Plan in respect of Dividend Equivalents is reached,
the Company may in its discretion credit or settle such amounts in cash.
5.3 Vesting.
All Units (including Stock Units credited as Dividend Equivalents) credited to a
Participant's Stock Unit Account shall be at all times fully vested.
5.4 Distribution of Benefits.
(a) Form of Distribution. Stock Units credited to a Participant's Stock Unit
Account shall be distributed in an equivalent whole number of Shares. Fractional
share interests shall be disregarded, but, in the Committee's discretion, may be
accumulated and paid in cash.
(b) Retirement Benefits. No later than sixty days following a Participant's
Retirement, the Committee shall distribute or begin to distribute Shares in
an amount equal to the number of Stock Units credited to the Participant's
Stock Unit Account pursuant to the election made by the Participant in his
or her Alternative Exercise Agreement. The Participant may elect in his or
her Alternative Exercise Agreement to have the Retirement Benefit paid in
one of the following forms:
(i) in a lump sum,
(ii) in installments paid annually over a period of five, ten or fifteen
years, or
(iii) in a lump sum of a portion of the Shares upon Retirement with the
balance in installments paid annually over a period of five, ten or
fifteen years.
If no valid election is made, the Committee shall distribute the Retirement
Benefits in a lump sum. Notwithstanding the foregoing or anything to the
contrary in Section 5.4(c) below, the Committee may, in its sole discretion:
(iv) distribute the benefits in a single lump sum if the sum of Shares to
be distributed to the Participant is less than or equal to 1,000, or
(v) reduce the number of installments elected by the Participant to
produce an annual distribution of at least 100 Shares.
(c) Termination Benefits. No later than 60 days after Termination of Employment,
the Committee shall distribute or commence to distribute Shares in an amount
equal to the number of Units credited to the Participant's Stock Unit Account.
The Shares shall be distributed in a single lump sum unless the Participant
elected three annual installments in his or her Alternative Exercise Agreement.
Notwithstanding the foregoing, if the Participant's Termination of Employment is
a Termination for Cause, the Committee shall distribute the shares in a lump
sum.
8
(d) Survivor Benefits. If the Participant dies while actively employed by the
Company or a Subsidiary, the Committee shall distribute or commence to
distribute to the Participant's Beneficiary the number of Shares equal to the
number of Units credited to the Participant's Stock Unit Account in accordance
with the Participant's election for Retirement Benefits within sixty days after
the Participant's death. If the Participant dies after Retirement, the Committee
shall distribute to the Participant's Beneficiary the remaining Shares
distributable to the Participant under the Plan over the same period that the
Shares would have been distributed to the Participant. If the Participant dies
following Termination of Employment, but prior to the distribution of all Shares
distributable to the Participant, the Committee shall deliver the remaining
Shares to the Participant's Beneficiary in a lump sum. Beneficiaries may
petition the Committee once, and only after the death of the Participant, for a
change in the form of survivor benefits. The Committee may, in its sole and
absolute discretion, choose to grant or deny such a petition. Notwithstanding
the foregoing, the Committee may, in its sole discretion:
(i) distribute the Shares in a single lump sum if the total number of the
Shares distributable to the Beneficiary is less than or equal to
1,000, or
(ii) reduce the number of installments elected by the Participant to ten or
five if necessary to produce an annual benefit of at least 100 Shares.
(e) Disability. In the event that a Participant has suffered a Disability, the
Committee shall distribute shares upon the Participant's Termination of
Employment, Retirement or death according to the Participant's prior election.
(f) Effect of Change in Control Event. Notwithstanding Section 5.4(a) and unless
the Committee provides in advance that no such acceleration shall occur in
connection with a specific Change in Control Event, then upon the occurrence of
a Change in Control Event, cash equal to the Fair Market Value, as of the date
immediately preceding the Change in Control Event, of the number of Shares equal
to the number of Stock Units then credited to the Participant's Stock Unit
Account shall be distributed immediately in a lump sum to the Participant.
(g) Scheduled Withdrawals. When completing an Alternative Exercise Agreement, a
Participant may elect to receive a distribution of a specific number of Shares
or a percentage of Shares deferred under such Alternative Exercise Agreement on
the first business day of the calendar year which is at least the second
calendar year following the calendar year in which the Qualifying Option is
Alternatively Exercised. Any Scheduled Withdrawal Election shall be superseded
by distributions due to the Retirement, Termination of Employment or death of
the Participant.
(h) Unscheduled Withdrawals. A Participant (or Beneficiary if
the Participant is deceased) may request in writing to the Committee a
distribution of Shares in an amount equal to all or a portion of the Units
credited to his or her Stock Unit Account, which shall be distributed in a lump
sum within thirty days; provided, that
(i) the minimum distribution shall be 25% of the Stock Unit Account,
9
(ii) an election to receive 75% or more of the Stock Unit Account shall be
deemed to be an election to receive the entire Stock Unit Account, and
(iii) such an election may be made only once in a Plan Year.
There shall be a penalty deducted from the Stock Unit Account prior to an
Unscheduled Withdrawal equal to 10% of the Shares to be delivered under the
Unscheduled Withdrawal. Notwithstanding the foregoing, if the number of Units
credited to the Stock Unit Account of the Participant or Beneficiary who has
requested an Unscheduled Withdrawal is less than or equal to 1,000, the
Committee may, in its sole discretion, elect to distribute Shares in an amount
equal to all of the Units credited, reduced by the 10% penalty, in a single lump
sum.
(i) Financial Hardship Distribution. A Participant or Beneficiary may submit a
hardship distribution request to the Committee in writing setting forth the
reasons for the request. The Committee shall have the sole authority to approve
or deny such requests. Upon a finding that the Participant or the Beneficiary
has suffered a Financial Hardship, the Committee may in its sole discretion,
accelerate distributions of Shares under the Plan in the amount reasonably
necessary to alleviate the Financial Hardship.
(j) Section 162(m) Limitation. Notwithstanding the foregoing, if the Committee
determines in good faith that there is a reasonable likelihood that any benefits
paid to a
Participant for a taxable year of the Company would not be deductible by the
Company or a Subsidiary solely by reason of the limitation under Code Section
162(m), then to the extent reasonably deemed necessary by the Committee to
ensure that the entire amount of any distribution to the Participant pursuant to
this Plan is deductible, the Committee may defer all or any portion of a
distribution under this Plan. The amounts so deferred shall be distributed to
the Participant or his or her Beneficiary (in the event of the Participant's
death) at the earliest possible date, as determined by the Committee in good
faith, on which the deductibility of compensation paid or payable to the
Participant for the taxable year of the Company during which the distribution is
made will not be limited by Code Section 162(m).
(k) Changes in Distribution Elections. Participants may change the form of
payout upon termination of employment due to Retirement, Termination of
Employment (other than Termination for Cause) or death by written election filed
with the Committee; provided, however, that if the Participant files the
election less than thirteen months prior to the date of such termination of
employment, the payout election in effect thirteen months prior to such
termination date shall govern.
10
5.5 Adjustments in Case of Changes in Common Stock.
(a) If the outstanding Shares are increased, decreased, or exchanged for a
different number or kind of securities, or if additional shares or new or
different shares or other securities are distributed with respect to such Shares
or other securities, through merger, consolidation, sale of all or substantially
all of the assets of the Company, reorganization, recapitalization, stock
dividend, stock split, reverse stock split or similar change in capitalization
or any other distribution with respect to such Shares or other securities,
proportionate and equitable adjustments consistent with the effect of such event
on stockholders generally (but without duplication of benefits if Dividend
Equivalents are credited) shall be made in the number and type of Shares or
other securities, property and/or rights contemplated hereunder and of rights in
respect of Units and Stock Unit Accounts credited under this Plan so as to
preserve the benefits intended. The provisions of Section 16 of the Management
Plan, Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan and Section
3.4 of the 2000 Equity Plan shall also apply to the related Stock Units granted
under the Incentive Plans in accordance with this Plan.
(b) If the event results in any rights of stockholders to receive cash (other
than cash dividends and cash distributions), a corresponding amount of cash
shall be credited to each Participant's Stock Unit Account (or, if applicable,
the appropriate Distribution Subaccount of the Participant's Stock Unit Account)
as of the date that cash is paid in respect of outstanding Shares. As of the
last day of each calendar quarter, the Participant's Stock Unit Account shall be
credited with earnings on the cash balance credited to such Stock Unit Account
as of the last day of the preceding quarter or, if later, the date of such
event, at a rate (on an annualized basis) equal to the Interest Rate. The amount
of cash credited to a Participant's Stock Unit Account shall be distributed in
cash at such time (or times) and in such manner as otherwise provided under this
Plan and/or the applicable election made by the Participant in accordance with
the terms of this Plan.
5.6 Company's Right to Withhold.
The Company (including its Subsidiaries) may satisfy any state or federal tax
withholding obligation arising upon a distribution of Shares and any cash with
respect to a Participant's Stock Unit Account by reducing the number of Shares
or cash otherwise deliverable to the Participant. The appropriate number of
Shares required to satisfy such tax withholding obligation in the case of Stock
Units will be based on the Fair Market Value of a Share on the day prior to the
date of distribution. If the Company (including its Subsidiaries), for any
reason, elects not to (or cannot) satisfy the withholding obligation in
accordance with the preceding sentence, the Participant shall pay or provide for
payment in cash of the amount of any taxes which the Company (including its
Subsidiaries) may be required to withhold with respect to the benefits
hereunder, before any such benefits are paid.
11
6.
ADMINISTRATION
6.1 The Administrator.
The Committee hereunder shall consist of (i) the members of the Compensation and
Executive Personnel Committee of the Board who are Non-Employee Directors within
the meaning of Rule 16b-3 and "outside directors" for purposes of Section 162(m)
of the Code, or (ii) such other committee of the Board, each participating
member of which is a Non-Employee Director (as defined in Rule 16b-3) and each
member of which is an "outside director" for purposes of Section 162(m) of the
Code, as may hereafter be appointed by the Board to serve as administrator of
this Plan. Any member of the Committee may resign by delivering a written
resignation to the Board. Members of the Committee shall not receive any
additional compensation for administration of this Plan.
6.2 Committee Action.
Action of the Committee with respect to the administration of this Plan shall be
taken pursuant to a majority vote or by unanimous written consent of its
members. A member of the Committee shall not vote or act upon any matter which
relates solely to himself or herself as a Participant in this Plan.
6.3 Rights and Duties.
(a) Subject to the limitations of this Plan, the Committee shall be charged with
the general administration of this Plan and the responsibility for carrying out
its provisions, and shall have powers necessary to accomplish those purposes,
including, but not by way of limitation, the following:
(i) To construe and interpret this Plan;
(ii) To resolve any questions concerning the amount of benefits payable to
a Participant;
(iii)To make all other determinations required by this Plan, including
adjustments under Section 5.5.;
(iv) To maintain all the necessary records for the administration of this
Plan and provide statements of Stock Unit Accounts to Participants on
an annual or more frequent basis;
(v) To make and publish forms, rules and procedures for the administration
of this Plan; and
(vi) To administer the claims procedures set forth in Section 6.5 for
presentation of claims by Participants and Beneficiaries for benefits
under this Plan, including consideration of such claims, review of
claim denials and issuance of a decision on review.
12
(b) The Committee shall have full discretion to construe and interpret the terms
and provisions of this Plan (but not to increase amounts payable hereunder) and
to resolve any disputed question or controversy, which interpretation or
construction or resolution, including decisions with respect to adjustments
under Section 5.5, shall be final and binding on all parties, including but not
limited to the Company and any Eligible Person, Participant or Beneficiary,
except as otherwise required by law. The Committee shall administer such terms
and provisions in a nondiscriminatory manner and in full accordance with any and
all laws applicable to the Plan. In performing its duties, the Committee shall
be entitled to rely on information, opinions, reports or statements prepared or
presented by: (i) officers or employees of the Company whom the Committee
believes to be reliable and competent as to such matters; and (ii) counsel (who
may be employees of the Company), independent accountants and other persons as
to matters which the Committee believes to be within such persons' professional
or expert competence. The Committee shall be fully protected with respect to any
action taken or omitted by it in good faith pursuant to the advice of such
persons. The Committee may delegate ministerial, bookkeeping and other
non-discretionary functions to individuals who are officers or employees of the
Company.
6.4 Indemnity and Liability.
All expenses of the Committee shall be paid by the Company and the Company shall
furnish the Committee with such clerical and other assistance as is necessary in
the performance of its duties. No member of the Committee shall be liable for
any act or omission of any other member of the Committee nor for any act or
omission on his or her own part. To the extent permitted by law, the Company
shall indemnify and save harmless each member of the Committee against any and
all expenses and liabilities arising out of his or her membership on the
Committee.
6.5 Claims Procedure.
(a) The Committee shall notify Participants and, where appropriate,
Beneficiaries of their right to claim benefits under these claims procedures,
shall make forms available for filing of such claims, and shall provide the name
of the person or persons with whom such claims should be filed.
(b) The Committee shall act upon claims as required and communicate a decision
to the claimant promptly and, in any event, not later than 90 days after the
claim is received by the Committee, unless special circumstances require an
extension of time for processing the claim. If an extension is required, notice
of the extension shall be furnished to the claimant prior to the end of the
initial 90-day period, which notice shall indicate the reasons for the extension
and the expected decision date. The extension shall not exceed 90 days. The
claim may be deemed by the claimant to have been denied for purposes of further
review described below in the event a decision is not furnished to the claimant
within the period described in the preceding three sentences. Every claim for
benefits which is denied shall be denied by written notice setting forth in a
manner calculated to be understood by the claimant (i) the specific reason or
reasons for the denial, (ii) specific reference to any provisions of this Plan
on which denial is based, (iii) description of any additional material
13
or information necessary for the claimant to perfect his claim with an
explanation of why such material or information is necessary, and (iv) an
explanation of the procedure for further review of the denial of the claim under
the Plan.
(c) The claimant or his or her duly authorized representative shall have 60 days
after receipt of denial of his or her claim to request a review of such denial,
the right to review all pertinent documents and the right to submit issues and
comments in writing. Upon receipt of a request for a review of the denial of a
benefit claim, the Committee shall undertake a full and fair review of the
denial.
(d) The Committee shall issue a decision not later than 60 days after receipt of
a request for review from a claimant unless special circumstances, such as the
need to hold a hearing, require a longer period of time, in which case a
decision shall be rendered as soon as possible but not later than 120 days after
receipt of the claimant's request for review. The decision on review shall be in
writing and shall include specific reasons for the decision written in a manner
calculated to be understood by the claimant with specific reference to any
provisions of this Plan on which the decision is based.
7.
PLAN CHANGES AND TERMINATION
7.1 Amendments.
The Committee shall have the right to amend this Plan in whole or in part from
time to time or may at any time suspend or terminate this Plan; provided,
however, that no amendment or termination shall cancel or otherwise adversely
affect in any way, without his or her written consent, any Participant's rights
with respect to Stock Units and Dividend Equivalents (and any cash credited
pursuant to Section 5.5(b)) credited to his or her Stock Unit Account. Any
amendments authorized hereby shall be stated in an instrument in writing, and
all Eligible Persons shall be bound thereby upon receipt of notice thereof.
Adjustments pursuant to Section 5.5 hereof, Section 16 of the Management Plan,
Section 16 of the Officer Plan, Section 3.4 of the 1998 Plan or Section 3.4 of
the 2000 Equity Plan shall not be deemed amendments to this Plan, the Stock Unit
Accounts or the rights of Participants.
7.2 Term.
It is the current expectation of the Company that this Plan shall be continued
indefinitely, but continuance of this Plan is not assumed as a contractual
obligation of the Company. In the event that the Committee decides to
discontinue or terminate this Plan, it shall notify the Participants in this
Plan of its action in writing, and this Plan shall be terminated at the time
therein set forth. All Participants shall be bound thereby. In such event, the
then credited benefits of a Participant shall be immediately distributed in a
lump sum.
14
8.
MISCELLANEOUS
8.1 Limitation on Participant Rights.
Participation in this Plan shall not give any person the right to continued
employment or service or any rights or interests other than as herein provided.
No Participant shall have any right to any payment or benefit hereunder except
to the extent provided in this Plan. This Plan creates no fiduciary duty to
Participants and shall create only a contractual obligation on the part of the
Company as to such amounts; the Plan shall not be construed as creating a trust.
The Plan, in and of itself, has no assets. Participants shall have rights no
greater than the right to receive the Common Stock (and any cash as expressly
provided herein) or the value thereof as a general unsecured creditor in respect
of their Stock Unit Accounts.
8.2 Beneficiary Designation.
Upon forms provided by and subject to conditions imposed by the Company, each
Participant may designate in writing the Beneficiary or Beneficiaries whom such
Participant desires to receive any Shares or amounts payable under this Plan
after his or her death. A Participant may from time to time change his or her
designated Beneficiary or Beneficiaries without the consent of such Beneficiary
or Beneficiaries by filing a new designation with the Committee. However, if a
married Participant wishes to designate a person other than his or her spouse as
Beneficiary, such designation shall be consented to in writing by the spouse,
which consent shall acknowledge the effect of the designation. The Participant
may change any election designating a Beneficiary or Beneficiaries without any
requirement of further spousal consent if the spouse's consent so provides.
Notwithstanding the foregoing, spousal consent shall be unnecessary if it is
established (to the satisfaction of the Committee or a Committee representative)
that there is no spouse or that the required consent cannot be obtained because
the spouse cannot be located. The Company and the Committee may rely on the
Participant's designation of a Beneficiary or Beneficiaries last filed in
accordance with the terms of this Plan. Upon the dissolution of marriage of a
Participant, any designation of the Participant's former spouse as a Beneficiary
shall be treated as though the Participant's former spouse had predeceased the
Participant, unless (a) the Participant executes another Beneficiary designation
that complies with this Section 8.2 and that clearly names such former spouse as
a Beneficiary, or (b) a court order is presented to the Company that requires
the former spouse be maintained as the Beneficiary. In any case where the
Participant's former spouse is treated under the Participant's Beneficiary
designation as having predeceased the Participant, no heirs or other
beneficiaries of the former spouse shall receive benefits from the Plan as a
Beneficiary of the Participant except as provided otherwise in the Participant's
Beneficiary designation.
15
8.3 Payments to Minors or Persons Under Incapacity.
If any amount is payable under this Plan to a minor, payment shall not be made
to the minor, but instead shall be paid (i) to that person's then living
parent(s) to act as custodian, (ii) if that person's parents are then divorced,
and one parent is the sole custodial parent, to such custodial parent, or (iii)
if no parent of that person is living, to a custodian selected by the Committee
to hold the funds for the minor under the Uniform Transfers or Gifts to Minors
Act in effect in the jurisdiction in which the minor resides. If no parent is
living and the Committee decides not to select another custodian to hold the
funds for the minor, then payment shall be made to the duly appointed and
currently acting guardian of the estate for the minor or, if no guardian of the
estate for the minor is duly appointed and currently acting within 60 days after
the date the amount becomes payable, payment shall be deposited with the court
having jurisdiction over the estate of the minor.
8.4 Stock Units and Other Benefits Not Assignable; Obligations Binding Upon
Successors.
Stock Units and other benefits of a Participant under this Plan shall not be
assignable or transferable and any purported transfer, assignment, pledge or
other encumbrance or attachment of any payments or benefits under this Plan, or
any interest therein, other than by operation of law or pursuant to Section 8.2,
shall not be permitted or recognized. Obligations of the Company under this Plan
shall be binding upon successors of the Company.
8.5 Employment Taxes.
The Company (including its Subsidiaries) may satisfy any state or federal
employment tax withholding obligation arising from an Alternative Exercise of a
Qualifying Option under the Plan by deducting such amount from any amount of
compensation payable to the Participant. Alternatively, the Company (including
its Subsidiaries) may require the Participant to deliver to it the amount of any
such withholding obligation as a condition to the Alternative Exercise of the
Qualifying Option.
8.6 Governing Law; Severability.
The validity of this Plan or any of its provisions shall be construed,
administered and governed in all respects under and by the laws of the State of
California. If any provisions of this instrument shall be held by a court of
competent jurisdiction to be invalid or unenforceable, the remaining provisions
hereof shall continue to be fully effective.
8.7 Compliance With Laws.
This Plan, the Company's acceptance of the exercise price of a Qualifying Option
in the form of Shares, the Company's issuance of Stock Units, and the offer,
issuance and delivery of Shares and/or the payment in Shares through the
deferral of compensation under this Plan are subject to compliance with all
applicable federal and state laws, rules and regulations (including but not
limited to state and federal securities law) and to such
16
approvals by any listing, agency or any regulatory or governmental authority as
may, in the opinion of counsel for the Company, be necessary or advisable in
connection therewith. Any securities delivered under this Plan shall be subject
to such restrictions, and the person acquiring such securities shall, if
requested by the Company, provide such assurances and representations to the
Company as the Company may deem necessary or desirable to assure compliance with
all applicable legal requirements. If the Company in its sole discretion
determines that an Alternative Exercise of a Qualifying Option would violate any
law, rule or regulation, the Company may refuse to honor such Alternative
Exercise.
8.8 Plan Construction.
It is the intent of the Company that transactions pursuant to this Plan satisfy
and be interpreted in a manner that satisfies the applicable requirements of
Rule 16b-3 so that to the extent elections are timely made, the crediting of
Stock Units and the distribution of Shares with respect to Stock Units under
this Plan will be entitled to the benefits of Rule 16b-3 or other exemptive
rules under Section 16 of the Exchange Act and will not be subjected to
avoidable liability thereunder.
8.9 Headings Not Part of Plan
Headings and subheadings in this Plan are inserted for reference only and are
not to be considered in the construction of the provisions hereof.
IN WITNESS WHEREOF, the Company has caused its duly authorized officer to
execute this Plan on this 15th day of September, 2000.
EDISON INTERNATIONAL
/s/ John H. Kelly
- ------------------------------------
John H. Kelly, Senior Vice President
EXH 10.25
LOGO
GOVERNOR GRAY DAVIS
April 9, 2001
Mr. John E. Bryson
Southern California Edison Company
PO Box 800
Rosemead, CA 91770
Dear John:
I am pleased that Southern California Edison Company (SCE), Edison International
(EIX) and the California Department of Water Resources (CDWR) have negotiated a
final Memorandum of Understanding to implement our agreement in principle. I
know this has been a complex job, and that each and every term of the MOU is
interdependent and essential.
I firmly believe that the agreements contained in the MOU are in the best
interests of the people of California. I support them fully and will work for
the complete implementation of the MOU.
Your personal leadership and the tireless work of your team were critical to
this achievement. I hope you will convey to the Boards of Directors of SCE and
EIX my appreciation for their commitment to this effort and my assurances of
support for the MOU.
Sincerely,
/s/ Gray Davis
Gray Davis
MEMORANDUM OF UNDERSTANDING
THIS MEMORANDUM OF UNDERSTANDING ("MOU") is being entered into as of April
9, 2001, by and among the California Department of Water Resources ("CDWR")
separate and apart from its powers and responsibilities with respect to the
State Water Resources Development System, and Southern California Edison
Company, a California corporation ("SCE"), and, as to Sections 5, 8 and 12,
Edison International, a California corporation ("EIX"). 1. Purpose
The purposes of this MOU are to:
o Set forth the understandings reached by the parties above (the "Parties")
about a plan (the "Plan") to provide affordable and reliable electricity to
customers of SCE by, among other things, maintaining the output of SCE's
retained generation on a cost-of-service basis, providing for CDWR or
another authorized agency of the State of California (the "State") to
acquire SCE's transmission system (or certain other assets if the sale of
the transmission system is not consummated under certain circumstances)
(the "Transmission Sale"), dedicating a new generating facility owned by an
EIX company to cost-of-service based rates for at least 10 years, and
providing for easements and potential conveyances in fee of certain lands
described herein to ensure the long-term conservation of these lands for
their public interest value; and
o Provide a framework for the timely implementation of those understandings;
and
1
o As part of that implementation, provide for the resolution of certain
claims which SCE has asserted against the State of California and certain
agencies and subdivisions thereof.
It is expressly understood that the Parties will act in good faith to
implement all the elements of this MOU, and that the Governor of the State of
California has endorsed such implementation. Such implementation shall include
seeking to obtain the consents and authorizations contemplated herein. In
addition, it is expressly understood that there is no intention to change SCE's
continuing to be a public utility that is subject to the jurisdiction of the
California Public Utilities Commission (the "CPUC"). The Parties recognize, in
order for a number of the initiatives contemplated by this MOU to be fulfilled,
certain actions and approvals will need to be obtained by SCE from the CPUC in
an appropriate proceedings. Those actions and approvals are referred to herein
as the "CPUC Implementing Decisions." Inasmuch as the CPUC is an independent
regulatory agency which may within its discretion determine to adopt or not
adopt the actions and approvals that are described herein as "CPUC Implementing
Decisions," this MOU provides for certain rights on the part of SCE to terminate
the implementation of this MOU in the event that the CPUC does not adopt all of
the actions and approvals expressly characterized herein as "CPUC Implementing
Decisions" within the period of sixty (60) days after the date of the execution
of this MOU by all Parties.
Subject to legislation that may be adopted implementing this MOU and to the
CPUC Implementing Decisions, nothing herein shall prohibit the CPUC from
employing ratemaking and regulatory techniques, methods and standards that have
been historically used and may be used or implemented in the regulation of
public utilities.
Nothing herein is intended to provide SCE with actual recovery of a cost
more than once. In such instance, if any, the CPUC is authorized to adjust rates
to prevent multiple recovery of such cost.
2
2. General Overview
The Plan is comprised of the elements described in more detail in Sections
3 through 14 of this MOU. The Plan will be implemented through a combination of
the following:
o Legislative action, including, but not limited to, authorizing CDWR or
another State entity to acquire the SCE transmission assets and enter into
and implement the applicable contracts and activities contemplated herein,
and, as applicable or necessary, authorizing and/or directing the CPUC to
take certain actions called for hereby;
o Contracts directly between SCE and CDWR or other pertinent State agencies;
o Regulatory decisions, including actions by the Federal Energy Regulatory
Commission ("FERC") and the CPUC Implementing Decisions;
o Entry of a stipulated judgment in, or other form of mutually acceptable
disposition of, SCE's federal court lawsuit; and
o Releases or assignments of mutually agreed upon identified claims by SCE
against third parties subject to the conditions specified herein.
The Parties agree that the elements of the Plan are an integrated package,
and this MOU does not obligate any of the Parties to support any individual
element separate from the entire package. Further principles of implementation
are set forth in Section 15, and agreed upon next steps are provided in Section
16.
The proceeds from the transactions contemplated herein are intended to
eliminate SCE's net undercollected amount as of January 31, 2001, as described
herein. Accordingly, except as otherwise provided herein, proceeds received from
the securitizations
3
and Transmission Sale described herein will be applied to reduce payments
due for the procurement of power that are included in, and indebtedness (and
refinancings thereof) incurred by SCE to finance, the net undercollected amount.
In connection with the execution of the Purchase and Sale Agreement (as defined
in Section 4(b)), SCE will deliver to CDWR a schedule of sources and uses
setting forth SCE's uses of the proceeds being applied to the net undercollected
amount.
3. Utility Retained Generation
Subject to execution of the Definitive Agreements (as defined in Section
4(b)), adoption of the CPUC Implementing Decisions, and adoption of the
legislation contemplated hereby, SCE's generation assets, including all energy,
capacity, ancillary services, and any combination thereof, to which SCE has a
contractual right (collectively "URG"), will be committed to cost-based
ratemaking for SCE's bundled service customers, and SCE will not seek authority
to sell such assets, through December 31, 2010. In addition, SCE will operate
its URG in accordance with good utility practices, subject to the further terms
hereof. SCE's URG includes its interests in Units 2 and 3 of the San Onofre
Nuclear Generating Station ("SONGS"), the Palo Verde Nuclear Generating Station
("PVNGS"), the Mohave Generating Station ("Mohave"), the Four Corners Generating
Station ("Four Corners"), SCE's hydroelectric facilities ("Hydro Facilities"),
and the Pebbly Beach generating facility. URG also includes, for their
respective terms, power purchase contracts that SCE currently has, and other
contractual rights that SCE currently has, to purchase energy, capacity,
ancillary services and any combination thereof, from other utilities, power
suppliers or qualifying facilities. Consistent with the purposes of this
paragraph, SCE will withdraw its pending application with the CPUC to sell its
Mohave, PVNGS and Four Corners facilities.
This MOU does not address any aspects of the status and ratemaking
treatment of the URG or the ratemaking treatment therefore after December 31,
2010, and does not
4
bind any party to any obligation or exempt any party from any requirement
in respect thereof.
In return, subject to execution of the Definitive Agreements, the adoption
of the legislation contemplated hereby and the adoption or approval of the CPUC
Implementing Decisions, SCE will be entitled to collect revenues sufficient to
cover its costs from January 1, 2001, associated with its URG (and all costs for
ancillary services or other ISO costs associated with CDWR's procurement of the
net short allocated to SCE under Section 10) on a timely basis, in accordance
with the principles of cost-based ratemaking as applied in this State. In this
regard, one of the CPUC Implementing Decisions shall be the adoption by the CPUC
of procedures (which may include one or more balancing accounts and trigger
mechanisms) designed to ensure that any undercollection or overcollection of URG
costs (provided that actual costs of utility-owned generation shall equal
authorized costs, except for variable fuel costs) will be reconciled in a timely
manner and that any undercollection can be financed on reasonable terms
consistent with SCE being an investment grade credit (the "URG Cost Recovery
Mechanism"). The legislation necessary for the implementation of the Plan shall
include legislation overriding any applicable limits in A.B. 1890 which may be
inconsistent with the foregoing recovery principle. For the period from January
1 through 31, 2001, SCE will be deemed to have recovered its costs associated
with its URG through the operation of the Transition Cost Balancing Account
("TCBA"), except for depreciation and amortization that SCE shall recover as a
capital-related cost as described below.
Subject to the further provisions of this MOU respecting recovery of
investments, and the ratemaking principles set forth herein, a CPUC Implementing
Decision shall provide that SCE's costs associated with its URG will include,
through December 31, 2010:
o All customary categories of operating costs, including, but not limited to,
fuel costs (fixed and variable), operations and maintenance expenses, costs
of emissions credits (subject to the further provisions of Section 7),
direct, joint and common administrative and general (A&G) costs (excluding
5
non-site specific general plant, which shall be treated as a capital cost),
taxes, scheduling and dispatch costs, congestion costs, ancillary service
costs, and other transmission-related costs charged to generators.
o For SONGS 2 and 3, other than transmission-related costs, operating costs
will be recovered through 2003 through the existing Incremental Cost
Incentive Procedure ("ICIP") and will be recovered without regard to the
ICIP mechanism thereafter.
o All reasonably recorded capital-related costs, including a full return on
SCE's investment in used and useful URG (except as provided herein with
respect to SONGS 2 and 3). SCE's investment in URG will be set at the net
book value of such assets on December 31, 2000, including site specific and
non-site specific general plant and capital additions made after December
31, 1995, the costs of which have been reasonably and prudently incurred,
together with their associated income tax regulatory receivable or payable,
provided that the $129,783,000 of non-nuclear site-specific general plant
and capital additions made after December 31, 1995 and described on a
schedule that has been provided to CDWR and which have not to date been
disapproved by the CPUC shall be allowed in SCE's rate base temporarily
until the final approval or disapproval of such additions which shall be
accomplished by the CPUC as soon as practicable. Depreciation schedules
will be based on the expected remaining useful life of each plant, fixed
for this purpose for the period ending December 31, 2010 for SONGS 2 and 3
and PVNGS. For purposes of this Section 3, "net book value" means the
original cost recorded in SCE's books for a particular asset, less any
accumulated depreciation or amortization plus any deferred or flow through
taxes. Assets that have been expensed shall not have a book value.
6
o All reasonable and prudent incremental capital investments put into service
after December 31, 2000. Such investments, including income taxes and a
full return on investment, will be recovered in rates from the time they
are placed in service. Incremental investment which has not otherwise been
expensed will be depreciated over the expected remaining useful life of the
plant in question, which for purposes of SONGS 2 and 3 and PVNGS, will be
determined by the remaining term of the applicable license for each plant,
granted to SCE by the Nuclear Regulatory Commission ("NRC"), as such
licenses may be extended by the NRC. Notwithstanding anything to the
contrary in this Section 3, through 2003 incremental capital expenditures
for SONGS 2 and 3 will be recovered through the ICIP mechanism.
Operating decisions, including dispatch decisions, maintenance practices,
energy/capacity exchange decisions, and other operating practices shall be
performed by SCE in a reasonable and prudent manner.
Under current CPUC decisions, net revenues from PVNGS after 2001 and net
revenues from SONGS 2 and 3 after 2003 are subject to a sharing mechanism
whereby profits (as defined) are shared equally between shareholders and
customers. A CPUC Implementing Decision shall provide that such sharing
mechanism, and all associated provisions for transfer of post-ICIP cost
responsibility to SCE, will be eliminated through December 31, 2010. The
existing memorandum of understanding respecting SCE's Hydro Facilities will be
rendered moot, and SCE will withdraw its associated application under Public
Utilities Code section 377.
7
4. Transmission Sale
(a) Purchase of Assets and Assumed Liabilities
Subject to enabling legislation and the negotiation and execution of the
pertinent contracts, CDWR, or another authorized State agency (the "Purchaser"),
will purchase SCE's transmission system.
Subject to the further provisions of this MOU, the Transmission Sale
includes all of SCE's right, title, and interest to: (i) all transmission assets
under ISO control; (ii) any other assets not under ISO control that are used
exclusively in connection with transmission and included in SCE's FERC rates
charged to SCE's bundled service customers, or, in the case of any such assets
acquired after the date of such rates, includable in SCE's FERC rates charged to
SCE's bundled service customers; and (iii) related agreements and contracts. The
transmission assets shall also include rights to the real property associated
with or held for use in connection with the transmission system ("Real
Property") as well as other mutually agreed-upon assets and rights of SCE in
assets which are subject to joint interests of other parties, including shared
assets and rights, it being understood by the parties that the transmission
assets to be acquired by the Purchaser, whether through the acquisition of
assets to be exclusively owned by the Purchaser or through the acquisition of
rights in shared assets, shall be sufficient for the Purchaser to acquire a
functional transmission system capable of providing transmission services of the
type that it has in the past, with sufficient rights to repair and upgrade the
transmission system and to operate it efficiently and effectively. It is also
understood by the Parties that SCE's transmission system has been built and
operated on a fully integrated basis with SCE's distribution system and that the
Purchaser's operation of the transmission system and SCE's operation of the
distribution system will therefore necessarily involve mutually acceptable
arrangements for the sharing by SCE and the Purchaser of certain systems and
assets to avoid duplicative and potentially substantial costs to ratepayers and
taxpayers. To the extent the Purchaser desires physical separation of
transmission assets from distribution
8
assets, the costs of such separation, if feasible, will be borne by the
Purchaser. The Real Property and other assets included in the Transmission Sale
are collectively referred to herein as, the "Purchased Assets." Subject to the
further provisions of this MOU, title transferred to the Purchaser will be the
same as SCE's title, provided that the Purchased Assets will be transferred free
and clear of liens and encumbrances securing SCE's indebtedness for money
borrowed or other obligations of SCE not related to the transferred assets or
(unless the same has been adjusted for in the purchase price or in prorations)
not required to be assumed by the Purchaser hereunder; provided, that the
Definitive Agreements shall include provisions pursuant to which, if SCE is
unable, after using commercially reasonable efforts, to obtain the release of
any liens or encumbrances which it is responsible to release in connection with
the sale of the Purchased Assets (other than liens or encumbrances securing
indebtedness for borrowed money), then such failure shall not be a failure of
the foregoing condition or otherwise a default on the part of SCE if SCE is
diligently contesting such lien or encumbrance; SCE indemnifies the Purchaser
from and against any liability, damage, cost or expense incurred by it on
account thereof; and such lien or encumbrance has no material adverse effect on
Purchaser's ownership or operation of a functional transmission system capable
of providing transmission services of the type that it has in the past, with
sufficient rights to repair and upgrade the transmission system and to operate
it efficiently and effectively.
SCE will retain all of its right, title and interest in and to its
existing assets used exclusively in the operation of its non-transmission
business, such as generation assets (other than designated assets specified in
the Purchase and Sale Agreement, such as mutually agreed upon radial lines),
assets used in SCE's distribution business, communications facilities,
protection systems, control facilities and oil pipeline assets, and SCE will
retain rights in other assets necessary for such businesses to continue to
provide the services as they have in the past. The Purchase and Sale Agreement
will set forth the procedures and methods for transferring and retaining
interests in assets that are to be shared by the Parties after the closing
(because of the integrated nature of the transmission and distribution
businesses), provided that each Party will be entitled to the economic benefit
9
of its ownership or rights in a shared asset. The Parties will in any event
grant and reserve, as appropriate, such licenses, easements and reciprocal
easements as may be necessary or, in the reasonable judgment of the Parties,
desirable, to permit the Parties to own, operate and maintain their respective
assets and their interests therein. Such licenses, easements and reciprocal
easements shall, among other things, assure ingress, egress, access, utilities
and support; permit maintenance, relocation, construction and alteration; and
protect against encroachment, all as provided for in the Definitive Agreements
and subject to appropriate limitations and protections to be provided for
therein.
If, following the Transmission Sale, the Purchaser decides to explore
the possible offer for sale of all or substantially all of the Purchased Assets
(including all or substantially all of a larger transmission grid of which the
Purchased Assets may then form a part) through a competitive bidding process,
the Purchase and Sale Agreement will provide to SCE a non-exclusive opportunity
to bid for all, but not less than all, of the assets the Purchaser proposes to
sell, on the same terms and conditions as may be applicable to the other bidders
generally.
The Purchase and Sale Agreement will contain mutually agreed upon
representations and warranties, which will not include any representations and
warranties regarding or related to the physical condition of the Purchased
Assets, but will include covenants regarding operations in the ordinary course.
The assets will be sold to the Purchaser on an "AS IS, WHERE IS" and "WITH ALL
FAULTS" basis, and the Purchaser will assume all liabilities to the extent
related to the transferred assets, including all contractual obligations
(including obligations to provide transmission service and, without limiting the
parties' obligations under other provisions of this MOU, SCE's obligations under
the Transmission Control Agreement with the ISO, if such assumption is required
to transfer SCE's rights in the Purchased Assets or in order for SCE to be
relieved of its ongoing obligations under the Transmission Control Agreement),
environmental obligations, liabilities related to the operation of the assets
and decommissioning obligations, subject to the following:
10
o Recurring operating expenses will be subject to customary pro-ration as of
the closing;
o To the extent the cost of a liability has already been collected in rates
by SCE, SCE will indemnify the Purchaser against such liability;
o Liabilities for pending insured claims (including deductibles applicable
thereto) will be retained by SCE;
o SCE will assign its rights against insurers and third parties for
liabilities assumed by the Purchaser and each Party will cooperate and
assist the other in pursuing its rights against insurers and third parties
related to assumed and retained liabilities, provided that if consent to
such assignment is not received from insurers, then SCE will assign the
insurance proceeds arising from such claims; SCE and the Purchaser will
also negotiate provisions relating to the extension of claims periods under
insurance policies related to the Purchased Assets, including provisions
related to the cost thereof;
o SCE will indemnify the Purchaser for environmental liabilities which are
the "fault" of SCE, which term shall be as defined in the Purchase and Sale
Agreement (it being understood that liabilities related to EMF will be
assumed by the Purchaser, except for EMF-related liabilities for which SCE
would retain responsibility under the preceding bulleted provisions of this
Section and the last two bulleted provisions of this Section);
o SCE will indemnify the Purchaser for other liabilities caused by SCE's
gross negligence or willful misconduct prior to the Closing;
11
o SCE will indemnify the Purchaser for pre-closing breaches of contract under
contracts not assigned to the Purchaser;
o Non-ordinary course operating contracts to be assumed by the Purchaser will
be disclosed in schedules to the Definitive Agreements which have been
approved by the Purchaser and SCE;
o Material liabilities (to be defined in the Definitive Agreements) actually
known to a responsible officer of SCE and to be assumed by the Purchaser
will be disclosed in schedules to the Definitive Agreements which have been
approved by the Purchaser and SCE;
o The Purchaser will not assume liabilities for pre-closing taxes,
pre-closing criminal violations, breaches of the Purchase and Sale
Agreement or similar liabilities customarily excluded from "AS IS"
transactions; and
o The Purchaser will not assume liabilities to the extent related to the
assets and interests retained by SCE.
The authorizing legislation will provide that from and after the sale of
the Purchased Assets, transmission costs will be charged to retail customers
within the SCE service area by the Purchaser, and if requested, SCE will, as
billing agent, bill such charges and remit to the Purchaser all amounts
collected, less prorated uncollectibles.
(b) Agreements; Form of Transaction
In addition to a purchase and sale agreement for the Transmission Sale
("Purchase and Sale Agreement"), the Purchaser and SCE would enter into certain
related agreements as part of the transaction ("Related Agreements"). These
would include the following:
12
o O&M Agreement - Pursuant to which the Purchaser, as the owner, shall have
the right to make decisions commensurate with such interest, including the
decisions to make upgrades and to establish budgets. In addition, pursuant
to the O&M Agreement, SCE will provide operations and maintenance including
ordinary repairs and billing and collections services for a minimum term of
three (3) years with renewal options exercisable by the Purchaser. SCE
would be compensated through a fee to be negotiated. For work not included
in the fee, SCE's charges will be determined in accordance with the O&M
Agreement subject to audit by the Purchaser. The Purchaser will be
responsible for the costs of all capital improvements. It is the intention
of the Parties that the O&M Agreement be structured so that improvements
thereunder can be financed by tax-exempt bonds to the extent reasonably
practicable.
o Transmission Service Agreements - Pursuant to which the Purchaser will
agree to provide SCE with nondiscriminatory transmission service for its
URG and will further agree to provide nondiscriminatory transmission
service for other power being delivered to SCE's customers.
o Facilities Services and Coordinated Operations Agreements - Pursuant to
which the Parties will agree to the delineation of responsibilities and
costs (including the sharing of capital improvement costs) related to
certain interrelated or shared assets.
The Purchase and Sale Agreement together with the agreements contemplated
in Section 5 (power sale contract regarding Sunrise), Section 6 (grants of
conservation property), and 7 (agreements regarding claims of third parties) of
this MOU, and the agreement, if any, effectuating CDWR's obligations with
respect to the net short as provided for in Section 10 are collectively referred
to herein as the "Definitive Agreements." The Definitive Agreements shall
include all terms and conditions contained in this MOU that are to be
implemented contractually, except as the Parties may mutually agree. The
13
descriptions herein of the Definitive Agreements are intended as a summary, and
do not contain an exhaustive list of all provisions to be addressed in such
agreements; and provided, further, that any additional terms and conditions
shall not be inconsistent with the terms and conditions contained in this MOU,
except as the Parties may mutually agree.
The Definitive Agreements shall recognize that CDWR's actions as
contemplated in this MOU shall be separate and apart from its powers and
responsibilities with respect to the State Water Resources Development System
and that any and all obligations incurred and the funding for all such
obligations and activities arising from this MOU or the Definitive Agreements
shall be separate and distinct from the funds, monies, and obligations of the
State Water Resources Development System.
(c) Purchase Price
The purchase price will be 2.3 times SCE's net book value for the Purchased
Assets as of December 31, 2000, subject to verification of recorded amounts in
accordance with provisions to be negotiated in the Definitive Agreements and the
adjustments noted below, plus the sum of (i) approximately $63 million of
accelerated depreciation or similar tax benefits previously flowed through to
ratepayers (grossed up for taxes payable on the recovery of such benefits in
accordance with past ratemaking practices) and (ii) the transfer taxes payable
in connection with the sale of the Purchased Assets. For purposes of this
Section 4, "net book value" means the original cost recorded in SCE's books for
a particular asset, less any accumulated depreciation. Assets that have been
expensed shall not have a book value. The Parties currently estimate that the
unadjusted purchase price will be approximately $2.76 billion. The purchase
price will be subject to the following adjustments:
(1) To add the net book value at closing of reasonable and prudent capital
additions made to the Purchased Assets after December 31, 2000 to the
extent not recovered in transmission rates prior to the closing,
provided that capital additions approved by CDWR or the ISO and
capital additions that
14
are in process or planned and that are disclosed in a schedule to the
Definitive Agreements shall be deemed reasonable and prudent. Subject
to the preceding sentence, capital additions that are in process at
the time of the closing of the Transmission Sale will be valued at the
investment made as of the closing date.
(2) To add the net book value of any spare parts and similar current items
to the extent included in the Purchased Assets;
(3) To subtract the post-December 31, 2000 depreciation of the Purchased
Assets;
(4) To subtract the book value of any Purchased Assets existing as of
December 31, 2000 that are sold after that date, provided that if such
assets are not sold in the ordinary course of business and not
replaced by assets intended as equivalent replacements, the amount
subtracted shall be 2.3 times the book value of the sold assets; and
(5) To add or subtract for such additional items as the Parties may agree
upon.
Items such as rent, insurance, taxes and the like that are customarily pro-rated
for partial periods will be pro-rated at the closing. For purposes of this MOU,
references to the "gain on sale" of the Transmission Sale shall mean proceeds of
sale minus transaction costs paid or to be paid by SCE (other than those set
forth in Section 9), transfer taxes payable by SCE, net book value of the
Purchased Assets (including undepreciated capital additions as set forth above),
and the recapture or recovery by tax authorities of approximately $63 million of
accelerated depreciation or similar tax benefits previously flowed through to
ratepayers (grossed up for taxes payable on the recovery of such benefits in
accordance with past ratemaking practices).
15
(d) Use of Proceeds
Proceeds from the Transmission Sale (including the back-up transaction
referred to in paragraph (f) below) representing the net book value of the
assets transferred at the closing (based on SCE's recorded amounts) will be used
to reduce debt and equity (including through dividends, to the extent permitted
by the California Corporations Code and consistent with SCE's authorized capital
structure). The proceeds representing the gain on sale will be applied to
recover SCE's "net undercollected amount," as described in Section 9 of this
MOU, and accordingly will be applied to payments due for the procurement of
power that are included in, and indebtedness (including interest thereon and
refinancings thereof) incurred by SCE to finance, the net undercollected amount,
including any securitization of such indebtedness.
(e) Closing Conditions
In addition to any other conditions described in this MOU, closing of the
Transmission Sale transaction will be subject to other mutually agreed upon
conditions, including receipt of all necessary approvals, without unreasonable
conditions materially adverse to either party, from FERC, the ISO and SCE's
Indenture Trustee, if required. It is contemplated that, regarding the sale of
the Purchased Assets to the Purchaser and the other actions to be implemented
contractually pursuant to this MOU, the legislative authorization will dispense
with CEQA compliance. It is also contemplated that, regarding the sale of the
Purchased Assets to the Purchaser, the legislation will dispense with approvals
by the CPUC. Such legislation will also authorize the CDWR (or such other
agency) and the Purchaser to enter into the transactions as contemplated hereby.
The closing will also be conditioned upon the absence of any injunction,
restraining order or other order restraining or prohibiting the consummation of
the transactions contemplated in this MOU, and the absence of any suit by the
Federal Government seeking to restrain or prohibit the consummation of the
transactions contemplated in this MOU.
16
SCE will be required to deliver assets and rights sufficient for the
Purchaser to acquire a functional transmission system capable of providing
transmission services of the type that it has in the past, with sufficient
rights to repair and upgrade the transmission system and to operate it
efficiently and effectively. Subject to the foregoing, the Parties intend that a
failure to obtain a necessary consent or approval to transfer that relates to
only a portion of the Purchased Assets, after the Parties have used commercially
reasonable efforts to do so, or a third party's exercise of a right of first
refusal, will not result in a failure of closing conditions so long as the
Purchaser obtains substantially the same benefits of the contemplated bargain as
described below. In the event such a consent or approval is not received in a
timely manner, the Parties will work in good faith to provide substantially the
same benefits of the contemplated bargain to each of them through contractual
and other means not involving an actual transfer that is subject to such consent
or approval. Without limitation, the benefits of the contemplated bargain
include, in the case of the Purchaser, the ability of the Purchaser to have
upgrades and improvements made to the transmission system intended to be
purchased by the Purchaser hereunder, without any material limitation. If the
Parties are unable to provide substantially the same benefits of the
contemplated bargain through contractual and other means (but in all events
subject to the condition that the assets and rights to be acquired by the
Purchaser must be sufficient for the Purchaser to acquire a functional
transmission system capable of providing transmission services of the type that
it has in the past, with sufficient rights to repair and upgrade the
transmission system and to operate it efficiently and effectively), then the
portion of the Purchased Assets in question will not be transferred, and there
will be an equitable adjustment in the purchase price. In the event of any such
exclusion of assets and equitable adjustment of price, SCE shall nonetheless
cooperate with the Purchaser after the closing in order to enable upgrades and
improvements to be made to that portion of the Purchased Assets that are not
transferred.
17
(f) Back-Up Transaction
If the Transmission Sale fails to close within 24 months (subject to
extension by one party if the failure to close is due to the breach of the other
party) of the execution of the Purchase and Sale Agreement for a "Qualified
Triggering Reason" (as defined below), then SCE shall offer to sell to CDWR or
its designated Purchaser (i) its hydroelectric assets and, if such assets do not
produce a gain on sale substantially equivalent to the gain expected from the
Transmission Sale, (ii) such rights, over a reasonable period of time, to the
output of SCE's interests in generating plants (including its interests in Four
Corners, SONGS, PVNGS and Mohave if then operated) after 2010 on terms and
conditions that result in a value to CDWR determined on a net present value
basis at the time of the consummation of the sale of the hydroelectric assets,
reasonably equal to the difference between the gain expected from the
Transmission Sale and the gain expected from the sale of the hydroelectric
assets. If CDWR or such Purchaser so elects to purchase such assets, then the
Parties will promptly negotiate in good faith a definitive sale agreement
respecting such assets that shall contain terms comparable to the terms of the
Transmission Sale. Upon execution of an agreement in respect of the alternative
assets, the Purchase and Sale Agreement for the Transmission Sale will be
cancelled and the references herein to the "Purchase and Sale Agreement" shall
mean the definitive sale agreement for such alternative assets, and to the
"Purchased Assets" shall mean the alternative assets purchased in such sale,
mutatis mutandis.
A Qualified Triggering Reason will be defined in the Purchase and Sale
Agreement for the Transmission Sale consistent with the following: Failure to
close for any reason other than (x) a breach or default by the Purchaser causing
the failure to close, or (y) other reasons mutually agreed upon in the
Definitive Agreements, it being understood that it is the intent of the Parties
that (i) breaches of the Purchase and Sale Agreement by either Party that are
compensable in damages or are immaterial will not provide a basis for the other
Party's failure to close (provided that, in the case of Purchaser, upon closing
Purchaser would obtain the benefits of the contemplated bargain as described
above) and (ii) the Purchaser's or SCE's failure to close because a regulatory
18
authority or the ISO reasonably conditions its approval of the Transmission Sale
shall not constitute a Qualified Triggering Reason.
5. Sunrise Project
An EIX company will commit by contract - for a term of not less than 10
years - the entire output of the Sunrise power project (the "Sunrise Project")
to CDWR or its designee under cost-of-service based rates on terms and
conditions to be set forth in a Definitive Agreement that incorporates the terms
hereof (the "Sunrise Agreement"). The EIX company will continue to use all
commercially reasonable efforts to place Phase I of the Sunrise Project in
service before the end of the Summer, 2001. Cost-of-service based rates shall be
determined on the basis of a 50/50 debt to equity leverage, permanent financing
at the Phase II commercial operations date, an assumed long-term interest rate
of 9.0%, an 11.6% return on equity, a useful life of the facility of 30 years
and a value at the end of the contract term equal to book value less
undepreciated acceleration costs to bring Phase I online by Summer 2001. The
fuel cost shall be passed through to CDWR, with a right of CDWR to supply its
own fuel, provided CDWR gives the notice to be specified in the Sunrise
Agreement. All other prices shall be fixed in the Sunrise Agreement. The
capacity price, based on capital cost estimates for the Sunrise Project as of
the signing of this MOU, would be $120/kW-yr for Phase I and $176/kW-yr for
Phase II. The final capacity price will be based upon final costs incurred for
the Project, which costs shall be subject to audit verification by CDWR. If the
actual costs would result in a lower capacity price, the final price to CDWR
shall be that lower capacity price. If the actual costs would result in a higher
capacity price, CDWR and the EIX company shall share the increased costs on a
50/50 basis and the capacity price on Phase II shall be increased accordingly.
The price for variable O&M, other than fuel costs, shall be fixed at $3.00/MW H
for the term of the Sunrise Agreement. In addition to the above variable O&M
payment, CDWR shall be responsible for start up payments per start for each
normal start up in excess of 100 normal start ups per contract year in
accordance with the following
19
schedule: 101-135 starts at a cost of $300/start, 136-150 starts at a cost
of $5,000/start, over 150 starts at a cost of $14,000/start. The Sunrise
Agreement shall provide CDWR with the standard rights of dispatch for this type
of arrangement. The Phase I capacity charge is based on a limitation of the
hours of operation as specified in the latest term sheet provided by the EIX
company to CDWR prior to the date of this MOU based upon emission credits which
the EIX company has obtained for the Project. Any increase in the hours of
operation that CDWR may request would reflect increased costs for additional
emission credits which would be reflected in an increase in the capacity charge
to be agreed to by the Parties. In the event that this MOU terminates, the
foregoing agreement for the Sunrise project would be withdrawn and subject to
new discussions between the parties. Notwithstanding the foregoing, the Sunrise
Agreement shall provide that if the Sunrise Project is not placed in service on
or before August 15, 2001 subject to extension for a force majeure event outside
of the control of the EIX company, the EIX company party thereto will credit the
amount of $2,000,000 against the first $2,000,000 in billings the CDWR would
otherwise be required to pay the EIX company under the Sunrise Agreement.
6. Conservation Property
Pursuant to the Definitive Agreements, SCE will convey perpetual protective
conservation easements to approximately 20,600 acres of its Big Creek
hydroelectric related lands and approximately 825 acres of its Eastern Sierra
hydroelectric related lands to a trust for the benefit of the State of
California, which trust will serve as the interim holder of these interests
while disposition and management plans therefore are developed as described
below. The easements will restrict public agency access over lands included in
FERC licensed areas to limited purposes consistent and that do not interfere
with utility uses over such property.
The purpose of these conveyances will be to ensure the long-term
conservation of these lands for their public interest value for the people of
the State of California, including fish, wildlife, and other ecological
20
purposes; human recreation; preservation of open space and cultural resources;
and for protection of water quality and watershed functions. Accordingly, the
trust conveyances will restrict future development over such lands in
perpetuity, subject to the following: (i) existing non-utility uses based on
current levels of activity shall be permitted for a period equal to the longer
of 5 years or the remaining term set forth in existing leases, licenses, permits
or other applicable agreements; (ii) existing utility uses (i.e., ownership and
operation of any existing hydroelectric plants located on said lands and related
improvements, including, in connection therewith, the maintenance, repair,
replacement and installation of public utility infrastructure, such as water and
sewer pipelines, and electric and telecommunications lines for existing utility
uses) based on current levels of activity shall in all events be permitted for
as long as the same continue; (iii) expansion of hydroelectric facilities
currently located on said lands shall be permitted, but only with the approval
of the state and federal agencies with jurisdiction over any such expansion;
(iv) SCE's current timber harvesting, logging or similar activities shall be
subject to modification based on the approved management and disposition plans
referred to below; and (v) the maintenance, repair, replacement and installation
of public utility infrastructure, such as water and sewer pipelines, and
electric and telecommunications lines for non-utility and other uses to the
extent permitted pursuant to the management and disposition plan. SCE will
indemnify the trust, the State and any successor-in-interest against
environmental liability associated with these lands, only to the extent
attributable to SCE's own negligent or willful acts.
The Definitive Agreements will provide that during the period the trust
holds these interests, the Wildlife Conservation Board or another state agency
whose primary mission includes the above purposes to be identified in the
Definitive Agreements will develop, with input from SCE, local governments,
federal agencies and other stakeholders, disposition and management plans for
each of the conservation easements conveyed by SCE, through a property-specific
process in which public input shall be obtained. All such disposition plans will
be subject to the reservations contained in the easement grant, as specified
above. The plans will analyze each property's natural resource, recreational,
21
and economic use value to the people of the State of California and to the local
community, subject to protection for existing uses and potential expansions of
hydroelectric activities as set forth above, and determine the appropriate
interests in the various lands to be transferred to the State or applicable
agencies thereof (or, where appropriate, the U.S. Forest Service, or other
applicable federal agencies, local governmental agencies or, after consultation
with and subject to the approval of SCE, non-governmental conservation
organizations or other third parties specified in Civil Code Section 815.3) to
preserve these values. As part of this process, the trust may request of SCE
that it convey a fee interest in specific properties, and SCE will consider any
such request in good faith on the basis of the specific justifications therefore
and the necessity thereof in light of the existence of the conservation
easement, provided that any such conveyance will be subject to an easement back
to SCE in form and substance reasonably satisfactory to it to protect its
interests, and no fee ownership request will relate to lands covering existing
hydroelectric facilities and related uses as well as reasonable expansions
thereof.
It is anticipated that these disposition and management plans will be
completed within 18 months after the conveyances of the easements to the trust
(subject to compliance with applicable laws), and dispositions of the property
or interests therein to the State or applicable agencies thereof, to the U.S.
Forest Service or other applicable federal agencies, to local governmental
agencies, or, after consultation with and subject to the approval of SCE,
non-governmental conservation organizations or other third parties specified in
Civil Code Section 815.3, will occur once such individual plans are finalized.
The formal terms of the trust arrangement will be negotiated between
the designated State agency and SCE as part of the Definitive Agreements on the
basis of the principles enumerated above. Except as provided in the Definitive
Agreements, SCE will continue to pay all expenses associated with the properties
over which it has fee title, including property taxes, and will receive all
income generated from these properties.
22
7. BFMs; Emission Credits; Claims Against Third Parties
Upon execution of the Definitive Agreements, SCE will relinquish all claims
against the State for commandeering SCE's block forward market contracts
("BFMs") purchased through the California Power Exchange ("PX"), and in
connection therewith, CDWR will assume SCE's liabilities in respect of any
claims arising on or after February 2, 2001 or relating to the collateral value
of the BFMs after such date brought by the PX and/or PX Participants related to
the BFMs.
The Definitive Agreements shall obligate SCE, subject to pertinent
regulatory approvals, to sell certain mutually agreed upon emission credits
related to its previously sold generating stations, with the proceeds of such
sale to be for the benefit of ratepayers, or, alternatively, SCE shall, subject
to pertinent regulatory approvals, convey such credits to the State's Mitigation
Bank for no additional consideration.
In connection with the Definitive Agreements, the parties will negotiate
concerning their mutual cooperation and coordination with respect to pursuing
potential claims against third-party generators, and such Definitive Agreements
may contain provisions for the assignment of such claims from SCE to the State
or its agencies at times and upon terms to be mutually agreed upon. To the
extent SCE at any time after execution of this MOU realizes a discount or credit
in connection with the payment of any obligation included in the undercollection
amount described in Section 9 of this MOU, the amount of such discount or credit
shall be applied to the benefit of ratepayers in a manner to be more fully set
forth in the Definitive Agreements.
8. Tax Payments
To the extent not previously refunded by EIX after January 1, 2001, EIX
will, following its filing of a final federal income tax return for the year
2000, refund to SCE its year 2000 estimated quarterly tax payments
(approximately $293 million), and will fund an additional payment to SCE equal
to the federal loss carryback (currently estimated at approximately $127
23
million) that SCE would have had if it were not part of EIX's consolidated group
of taxpayers; provided that in no event will refunds from EIX to SCE
attributable to tax year 2000 aggregate less than $400 million.
9. Net Undercollected Amount
For the purposes of this MOU, the "net undercollected amount" shall be
computed as set forth in the remainder of this paragraph. For the purposes of
this calculation, SCE's TCBA and Transition Revenue Account ("TRA") as of
January 31, 2001 will not be combined. The balance in SCE's TCBA as of January
31, 2001 (adjusted (a) to exclude any amortization and depreciation for
presently owned generating facilities, together with their associated regulatory
receivable or payable for taxes that has occurred since December 31, 2000, which
shall be recovered as provided in Section 3 of this MOU, (b) to include the
associated Generation Memorandum Accounts, and (c) to exclude any entries with
corresponding entries in the Generation Asset Balancing Account) will be applied
to reduce the January 31, 2001 TRA balance (adjusted to remove amounts
representing potential payments to CDWR or the ISO for the period January 18 to
31, 2001 which are part of the procurement obligations which are being assumed
by CDWR pursuant to Section 10), resulting in a "net undercollected amount." The
net undercollected amount (i) will include retail generation revenues in respect
of power delivered in January 2001 received in February 2001 and thereafter
(until the end of the last full calendar month preceding the execution of the
Definitive Agreements), (ii) will exclude accrued QF costs as of January 31,
2001 not yet actually due and payable as of that date (it being acknowledged
that, notwithstanding the January 2001 cost recovery mechanism in Section 3, SCE
will be entitled to recover these accrued QF costs in a timely manner in rates
going forward), (iii) will exclude ISO charges (including imbalance energy
charges) assumed by the CDWR, as set forth in Section 10, and (iv) will include
CDWR charges on account of certain QF's not delivering power to SCE, set forth
in Section 10 of this MOU and SCE's cost obligations described in Section 15 of
this MOU. Subject to the foregoing, the size of the net undercollected amount as
computed under this paragraph will be subject to verification of recorded
24
amounts and any resulting adjustments by the CPUC, within 60 days of the passage
of the legislation referred to below. The net undercollected amount will be
deemed to equal the amount submitted by SCE if the CPUC does not complete the
verification process (and any adjustments resulting therefrom) within the 60-day
period. The net undercollected amount and the costs reflected therein will not
be subject to review by the CPUC or any other legislative, administrative or
judicial body for reasonableness. SCE estimates that the net undercollected
amount, as of January 31, 2001 was approximately $3.5 billion.
Legislation will direct the CPUC to establish an initial nonbypassable
dedicated rate component (including recovery of associated franchise fees and
uncollectibles) intended to be securitized, subject to the terms hereof, as soon
as practicable after the establishment thereof. Such dedicated rate component
will enable SCE to recover (i) the full net undercollected amount less the
expected gain on the Transmission Sale described in Sections 4(c) and 4(d)
above; (ii) the discounted net present value of interest on the expected gain on
the Transmission Sale for a period commencing on the date of the consummation of
the securitization of the Initial Dedicated Rate Component as described below
and ending two years after the date of the execution of the Purchase and Sale
Agreement; and (iii) interest on obligations included in the undercollection or
interim financing thereof during such period from January 31, 2001 until the
securitization transaction covering (i), (ii) and (iii) is consummated, based on
an effective interest rate to be mutually agreed to and set forth in the
Definitive Agreements, net of interest earned by SCE on its balances of cash,
cash equivalents and other liquid assets, if any, during such period in excess
of its normal cash balances. Such dedicated rate component is referred to herein
as the "First Dedicated Rate Component." SCE's actual borrowing costs are
referred to herein as "SCE's interest cost." As indicated above, the amount of
interest described in clause (ii) will be appropriately discounted to reflect
SCE's receipt of such amount in the securitization transaction before interest
on the expected gain on the Transmission Sale would actually accrue. SCE's
interest cost shall be addressed as provided in this paragraph and, subject to
the consummation of the financings and securitizations contemplated hereby,
25
shall not be recoverable in rates (other than through the dedicated rate
component described above), except that any difference between the amount of
interest securitized by SCE pursuant to clause (ii) above and the actual net
amount of interest incurred by SCE with respect to financing of a portion of the
undercollection equal to the expected gain on the Transmission Sale from the
date of the consummation of the securitization of the Initial Dedicated Rate
Component until the earlier of two years after the date of the execution of the
Purchase and Sale Agreement or the consummation of the Transmission Sale (based
on a rate to be mutually agreed to and set forth in the Definitive Agreements)
shall be recovered by or paid by SCE from or to its ratepayers.
Legislation will further direct the CPUC to establish a second
nonbypassable dedicated rate component (including recovery of associated
franchise fees and uncollectibles) that enables SCE to recover the expected gain
on the Transmission Sale as described in Section 4(c) and 4(d) above, subject to
the provisions set forth below. This dedicated rate component is referred to
herein as the "Second Dedicated Rate Component." The Second Dedicated Rate
Component is intended to provide a source to secure bridge financing of the
expected gain on the Transmission Sale. It shall not appear in rates for two
years after the execution of the Purchase and Sale Agreement and shall be made
subject to the Transmission Sale not closing before such time. The Second
Dedicated Rate Component would not be eligible to be securitized through a
public offering of debt securities by a special purpose entity until it is
eligible to appear in rates as provided above, but may be used to secure or
facilitate bridge financing prior to such time. However, the Second Dedicated
Rate Component will have the benefit of a financing order of the kind described
in Article 5.5 of the Public Utilities Code or order or action having equivalent
effect, and shall be effective no later than the effectiveness of the financing
order or its equivalent for the First Dedicated Rate Component. If the actual
gain on the Transmission Sale exceeds the estimated amount, then the difference
shall be refunded to SCE's customers; if the actual gain on the Transmission
Sale is less than the estimated amount, then the deficiency will be recovered
26
from SCE's customers in retail rates over the term of the securitization period.
Likewise, if there are other elements (other than interest, which is covered in
the preceding paragraph) included in the amount securitized which are based upon
contingencies related to the consummation of the Transmission Sale (such as, for
example, estimates of closing costs), there shall be adjustments (to be refunded
to or recovered from SCE's customers) if the actual amounts are less than or
greater than the estimated amounts. In addition, if any amount paid to SCE from
the proceeds of the initial securitization is intended to cover costs other than
procurement costs (such as interest or closing costs), SCE shall maintain such
amounts in one or more segregated accounts and use the amounts therein solely
for the purposes for which they were paid. Further, the Definitive Agreements
shall provide for appropriate adjustments upon the Transmission Sale in the
event that the Second Dedicated Rate Component has commenced but the
Transmission Sale has not yet occurred.
The dedicated rate components will be used solely to recover the net
undercollected amount, together with (a) reasonable costs incurred by SCE
associated with any financing of such amount (including any reasonable hedging
costs incurred by SCE in a reasonable hedging transaction approved by the
Department of Finance to hedge SCE's interest rate risk if the interest rate
provided for in the financing order or equivalent is a fixed or determined rate)
and (b) costs incurred or anticipated to be incurred by the State and the CDWR
in connection with this MOU, the Transmission Sale, or the securitization, as
more fully described in Section 15. The terms of any securitization transaction
will be subject to the approval of the Director of the State Department of
Finance, which approval shall not be unreasonably withheld or delayed. The net
undercollected amount will be amortized over a period of not less than 15 years
unless placement of securities with such a maturity is not reasonably practical,
in which case a shorter maturity shall be authorized by the Department of
Finance.
The legislation will further contain provisions that are the same as
Article 5.5 of the Public Utilities Code, mutatis mutandis, and that are
designed to facilitate the securitizing of the First and Second Dedicated Rate
27
Components, with such changes thereto as may be agreed upon by the Parties as
necessary to effectuate the foregoing provisions.
Amounts financed through such dedicated rate component(s) will not be
regarded as long-term debt for purposes of determining the utility's authorized
capital structure. Any tax benefits resulting from the timing difference between
the incurrence of procurement costs and the recovery thereof through the
financing contemplated in this Section 9 will be used to benefit retail
customers. The amount of benefit resulting from any such tax timing difference
during each applicable period will be determined by using a rate of return equal
to the weighted average yield applicable to the securities issued in such
financing.
10. Procurement Obligations
Either through legislation and/or through a contract between SCE and CDWR
(which, if in the form of a contract, shall be a Definitive Agreement), the
following will be effected:
o Through December 31, 2002, CDWR will assume the entire responsibility for
procuring the full net short needs of retail customers within the SCE
service area (i.e., the electricity needed to meet SCE's load that is not
met by the generation resources owned or under contract to SCE as of
January 18, 2001, plus any additions thereafter). CDWR shall also assume
responsibility for ancillary services (other than regulation, except to the
extent the parties agree pursuant to the next paragraph) associated with
CDWR import energy purchases and responsibility for the cost of Reliability
Must Run contracts from January 18, 2001. In addition, CDWR will also
assume responsibility for ISO charges to SCE for the energy cost component
of energy purchased by the ISO since January 18, 2001, to meet the net
short requirements in SCE's service area (such energy cost component shall
not include charges for underscheduling, capacity charges, ancillary
28
services or PX or similar chargebacks, except to the extent the parties
agree pursuant to the next paragraph).
o It is the intent of both SCE and CDWR that the overall costs to SCE's
retail customers be minimized, and accordingly SCE and CDWR agree that
SCE's operation of URG and CDWR's net short procurement should be
coordinated. SCE and CDWR will negotiate a mutually-agreeable operational
protocol which will address the use of URG for self-scheduling of ancillary
services, and will allocate responsibility for procurement and costs of
ancillary services. In addition, the operational protocol will allocate
cost responsibility for any ISO underscheduling penalties based upon SCE's
good faith forecast of the net-short and CDWR's activities to procure
sufficient quantities to meet SCE's forecast. SCE shall be entitled to
collect revenues through its retail rates sufficient to cover the costs of
any ancillary services it is responsible for on a timely basis.
o SCE will cooperate with CDWR to achieve operational efficiencies for
bundled service customers; and
o SCE power purchases, and, until it is creditworthy, utilization of URG, to
meet its obligations under interutility contracts will be allowed with an
offset for the net proceeds of any sale of power.
CDWR desires to be relieved of its obligation to provide for the net short
needs of SCE's retail customers, and SCE agrees to resume procurement of the
full net short needs and electric requirements for retail customers within the
SCE service area after 2002. In addition, after 2002, CDWR may at least assign
to SCE the administration of any of CDWR's outstanding procurement contracts.
The Parties will work together to minimize the burden on CDWR, without imposing
direct or indirect financial risks on SCE for those contracts. The Parties
recognize that legislation may be needed to achieve this result.
29
Given the magnitude of the net short and SCE's current financial condition,
the practical ability of SCE to resume such procurement responsibility after
2002, and to relieve CDWR of such burden, will depend in substantial part upon
prompt restoration of SCE's creditworthiness and its ability to recover such
procurement costs in rates on a timely basis. Accordingly, the CPUC Implementing
Decisions will include confirmation of SCE's entitlement to recover its
reasonable procurement costs on a timely basis and establish procedures (which
may include one or more balancing accounts and trigger mechanisms) designed to
ensure that any undercollection or overcollection of procurement costs will be
reconciled in a timely manner and any undercollection will be able to be
financed on reasonable terms consistent with SCE being an investment grade
credit, and mechanisms to mitigate the potential risks of retrospective
reasonableness review of procurement practices, including the development of a
framework and criteria for procurement practices, the submission of an annual
procurement plan, and the prompt approval or disapproval of contracts (the
"Procurement Cost Recovery Mechanism").
In addition, subject to execution of the Definitive Agreements and adoption
of legislation necessary to implement this MOU, SCE shall cooperate with CDWR in
the implementation of AB 1X, including provision by SCE of such information as
CDWR may reasonably require in connection with the financing of its power
purchase program. SCE and CDWR shall also execute a mutually approved servicing
agreement (which shall not be treated as a Definitive Agreement hereunder)
relating to the distribution, billing and collection of CDWR power for customers
in SCE's service area.
Upon the securitization of the First Dedicated Rate Component referred
to in Section 9 hereof, SCE shall pay CDWR an amount to be agreed upon
representing those costs incurred by CDWR in covering that portion of the net
short from January 18, 2001 through April 7, 2001 which is attributable to
certain QF's not delivering power to SCE, it being agreed that such payments to
30
CDWR shall be added to the net undercollected amount referred to herein and
shall not be construed as any admission by SCE.
The Parties agree to discuss in good faith the terms pursuant to which SCE,
as agent and not as principal, would be willing to assist CDWR in the management
of its power purchase contracts, on terms to be resolved in a subsequent
agreement. Such subsequent agreement shall not be considered a "Definitive
Agreement" as defined herein.
11. Investment Recovery
One of the goals of the Plan is for SCE to be an investment grade credit.
The Parties recognize that the creditworthiness and health of SCE, and the
ability of SCE to finance infrastructure improvements, require greater certainty
in respect of SCE's ability to earn a fair return on invested capital.
Accordingly, new legislation will provide that SCE's authorized return on equity
may not be reduced by the CPUC below its current 11.6% before December 31, 2010,
and that prior to such date, the CPUC will not establish a ratemaking capital
structure for SCE with different proportions of common equity or preferred
equity to debt than that set forth in current authorizations.
12. Capital Commitment by EIX; "First Priority" Condition
Pursuant to the Definitive Agreements, EIX and SCE shall commit to make
capital investments in SCE's regulated businesses of at least $3 billion through
2006, or such lesser amount as the CPUC may approve, with the equity component
thereof funded from utility retained earnings or, if insufficient, from EIX
equity investment, provided that SCE will receive a return of and on equity in
retail rates as provided in Section 11 hereof.
The CPUC Implementing Decisions will include a clarification that the
"first priority" condition in the decision authorizing the formation of a
holding company for SCE (D. 88-01-063, Condition 12) refers to equity
investment, not working capital for operating costs.
31
13. Additional CPUC Implementing Decisions
In addition to the URG Cost Recovery Mechanism, the Procurement Cost
Recovery Mechanism, and the other provisions of this MOU that are contemplated
to be implemented through CPUC Implementing Decisions, the CPUC Implementing
Decisions shall include:
o Orders resolving the responsibility of SCE to provide credits to direct
access customers in respect of electricity deliveries after December 31,
2000 in respects which do not result in any material financial detriment to
SCE; and
o A favorable determination by the CPUC in response to a request to be
submitted by SCE that SCE's 2002 Utility Distribution Company's GRC will be
deferred to test-year 2003.
14. Litigation Settlement
As part of the implementation steps, the Parties to the federal lawsuit
either will enter into a stipulated judgment resolving the federal lawsuit by
abandonment of SCE's claims and reflecting those terms of this MOU that have not
been secured either by entering into a Definitive Agreement, by CPUC action or
by legislation, or, if reasonably acceptable at the time to SCE, will enter into
a dismissal, with prejudice, of those claims. The claims to be abandoned or
dismissed by SCE as part of the settlement of the Federal litigation will
include, without limitation:
o any claim SCE may have or could have had against the State of California or
any agency, department or subdivision thereof, the Federal Government, or
the CPUC for takings or under the filed rate doctrine arising from or
related to the facts asserted in such litigation; and
32
o any claims challenging actions taken by the CPUC prior to execution of the
last executed Definitive Agreement to implement AB 1X and 6X, including,
without limitation, any determinations by the CPUC, State of California or
any agency, department or subdivision thereof of the California Procurement
Adjustment or the Fixed Department of Water Resources Set Aside.
In addition as part of the Definitive Agreements, the parties thereto will
negotiate in good faith releases of certain other claims. The judgment or
dismissal will be filed promptly following passage of all legislation, execution
of the Definitive Agreements and issuance of the financing order or equivalent
for the securitizations of the First and Second Dedicated Rate Components.
15. Implementation Principles
The MOU signifies the intention of the Parties to act in good faith to
sponsor and support legislation effecting elements of the Plan to be implemented
by legislation and to act in good faith to negotiate final agreements for those
elements of the Plan that are to be implemented by contract. As part of such
intention, each Party will allow for reasonable due diligence by the other
Party, and SCE will not seek to sell, encumber or otherwise dispose of the
transmission assets to any other person or entity or submit any application in
respect of the same to the CPUC or FERC. This MOU shall be terminable by either
Party upon written notice to the other in the event that such legislation is not
passed and the Definitive Agreements are not executed by August 15, 2001 unless
the Parties otherwise agree. This MOU shall also be terminable in the event that
any of the following (each, a "Material Adverse Change") occurs: (a) in the
event any law is passed, adopted or repealed or regulatory action taken which,
in the good faith judgment of such Party, would materially impede or frustrate
the ability of the Parties to effectuate all of the elements of the Plan as a
package; (b) as set forth above, in the event that all of the actions and
approvals expressly characterized herein as "CPUC Implementing Decisions" have
33
not been taken or adopted on or before sixty (60) days after the date this MOU
is signed by all Parties; (c) in the event of the adoption of or any change in
any applicable rule, regulation or order which would have a material adverse
effect on any Party or which, in the case of SCE, would include the failure on
the part of the CPUC, following a motion therefor filed on behalf of SCE (i) to
extend SCE's existing non-generation Performance Based Ratemaking and cost of
capital mechanisms until SCE's new GRC is implemented; (ii) to terminate the
Accelerated Cost Recovery and Reduced Cost Recovery ("ACRA/RCRA") mechanisms;
(iii) to permit the amortization of the RCRA reserve, in accordance with prior
CPUC decisions; (d) in the event that any material penalty is imposed by the
CPUC in respect of the relationship between SCE and EIX prior to the date
hereof, including without limitation any of the matters raised in Order
Instituting Investigation 01-04-002 or (e) in the event any bankruptcy
proceeding in respect of any Party is commenced. In the event of termination of
this MOU or any failure of the Definitive Agreements to be executed or become
effective, there shall be no liability for damages or otherwise on the part of a
Party to another under or by reason of this MOU or any discussions, negotiations
or conduct pertaining to this MOU or by reason of the failure of the
transactions contemplated hereby or thereby to be consummated.
Inasmuch as each element of the Plan is part of an integrated package, the
effectuation of each will depend upon effectuation of the others. In particular:
(i) Execution of the Definitive Agreements will be subject to final
passage and effectiveness of legislation implementing all elements of the
Plan that are required to be legislatively implemented and the adoption of
the CPUC Implementing Decisions. The Parties recognize that, as part of the
Definitive Agreements, mutually acceptable provisions shall be made with
respect to liabilities for PX chargebacks and ISO underscheduling charges.
(ii) Any financing order implementing the dedicated rate component(s)
will be subject to execution of the Definitive Agreements by the parties
thereto, and the consummation of the effectiveness of the Definitive
34
Agreements shall be conditioned upon the existence of financing orders or
their equivalent establishing irrevocable dedicated rate components for the
"net undercollected amount" referred to in Section 9.
(iii) Each Definitive Agreement will be subject to the Parties'
execution of the other Definitive Agreements; provided that: (A) the
Sunrise Agreement may be signed prior to the date the other agreements are
signed; (B) EIX may thereafter terminate the Sunrise Agreement if the other
Definitive Agreements are not executed when otherwise required by this MOU;
and (C) the EIX company shall be excused from performance under the Sunrise
Agreement in the event that, after the execution of the Definitive
Agreements, either (I) any legislation is enacted or any rule, regulation
or order is adopted by the CPUC which would have the effect of overturning,
in respects materially adverse to SCE, those CPUC Implementing Decisions
which were adopted prior to the execution of the Definitive Agreements or
(II) any Material Adverse Change referred to in clause (d) of the
definition thereof occurs.
(iv) Execution of each Definitive Agreement called for by the Plan and
dismissal or other resolution of the litigation referred to in Section 14
will be subject to there having been no Material Adverse Change and no
commencement of any bankruptcy or similar proceeding to which any party
hereto is subject.
Implementation of the Plan will be further subject to the following:
(a) Absence of any injunction, restraining order or other order restraining
or prohibiting the consummation of the transactions contemplated in this MOU,
and the absence of any suit by the Federal Government seeking to restrain or
prohibit the consummation of the transactions contemplated in this MOU.
(b) Receipt by each of the Parties upon or prior to execution of the
Definitive Agreements of such opinions of their financial advisors as they deem
reasonably necessary.
35
Provided the Definitive Agreements are entered into, SCE will pay all of
the reasonable costs and expenses incurred by the State directly in connection
with the negotiation or effectuation of this MOU and the Definitive Agreements,
including legal fees, fees of financial advisors and accountants and expenses of
its representatives, whether or not the transactions contemplated by this MOU
are consummated, subject to the following:
o SCE's obligations will only be for transaction costs identified to
transactions with SCE (not including, for example, costs associated with
State financing of its obligations or the conservation advertising
program);
o SCE's will not be obligated for State costs in excess of an amount to be
agreed upon based on an estimate provided by the State in connection with
the execution of the Definitive Agreements. All such costs shall be subject
to audit verification; and
o SCE recovers such expenses through the securitization of the First
Dedicated Rate Component described in Section 9 of this MOU (in addition to
the net undercollected amount) or if such securitization does not occur, in
retail rates.
16. Next Steps
Subject to the provisions of Section 15, the Parties will act in good faith
to implement this MOU and effectuate the Plan as quickly as reasonably
practicable. In this regard, the Governor will submit to the State Legislature,
after review and comment by SCE, a comprehensive legislative package setting
forth the legislative elements of the Plan. The Parties will then proceed
diligently and in good faith to attempt to have the necessary legislation
adopted, and will negotiate in good faith in an attempt to execute the
Definitive Agreements, by August 15, 2001.
36
While time is of the essence of this MOU, failure to satisfy the calendar
set forth in the preceding paragraph will not result in a termination of this
MOU, if the Parties are continuing to proceed diligently and in good faith to
achieve its implementation. Failure of all implementing legislation to be
adopted and effective and Definitive Agreements to be signed on or before
December 31, 2001, will entitle any Party thereafter to terminate this MOU upon
notice to the other Parties.
17. Signatures
This MOU may be executed in counterparts and via facsimile. The individuals
executing this MOU represent that they are authorized to sign on behalf of the
Parties they represent, it being understood, however, that the execution of this
MOU by representatives of SCE and EIX is following the approval of this MOU by
the Board of Directors of each such entity.
37
IN WITNESS WHEREOF, the undersigned have executed this Memorandum of
Understanding as of the day and year first above written.
SOUTHERN CALIFORNIA EDISON COMPANY,
a California corporation
By: /s/ Stephen E. Frank
Name: Stephen E. Frank
Title: Chairman of the Board, President and CEO
EDISON INTERNATIONAL, INC.,
a California corporation
By: /s/ John E. Bryson
Name: John E. Bryson
Title: Chairman of the Board, President and CEO
CALIFORNIA DEPARTMENT OF WATER RESOURCES
By: /s/ Thomas M. Hannigan
Name: Thomas M. Hannigan
Title: Director
Exhibit 12
SOUTHERN CALIFORNIA EDISON COMPANY AND CONSOLIDATED UTILITY-RELATED SUBSIDIARIES
RATIOS OF EARNINGS TO FIXED CHARGES
(Thousands of Dollars)
Year Ended December 31,
----------------------------------------------------------------------------------------
1995 1996 1997 1998 1999 2000
------------ ------------ ------------ ------------ ----------- -------------
EARNINGS BEFORE INCOME TAXES
AND FIXED CHARGES:
Income before interest expense (1) $ 1,143,477 $ 1,108,410 $ 1,049,866 $ 999,910 $ 992,354 $ (1,456,584)
Add:
Taxes on income (2) 509,632 511,819 520,468 442,356 438,006 (1,021,452)
Rentals (3) 4,018 3,269 2,639 2,208 1,901 2,905
Allocable portion of interest
on long-term Contracts for
the purchase of power (4) 1,848 1,824 1,797 1,767 1,735 1,699
Amortization of previously capitalized
fixed charges 1,185 814 1,127 1,571 1,508 1,390
------------ ------------ ------------ ------------ ----------- -------------
Total earnings before income
taxes and fixed charges (A) $ 1,660,160 $ 1,626,136 $ 1,575,897 $ 1,447,812 $ 1,435,504 $ (2,472,042)
============ ============ ============ ============ =========== =============
FIXED CHARGES:
Interest and amortization $ 463,786 $ 453,015 $ 444,272 $ 484,788 $ 482,933 $ 571,760
Rentals (3) 4,018 3,269 2,639 2,208 1,901 2,905
Capitalized fixed charges -
nuclear fuel (5) 1,531 1,711 2,398 1,294 1,211 1,538
Allocable portion of interest on
long-term contracts for
the purchase of power (4) 1,848 1,824 1,797 1,767 1,735 1,699
------------ ------------ ------------ ------------ ----------- -------------
Total fixed charges (B) $ 471,183 $ 459,819 $ 451,106 $ 490,057 $ 487,780 $ 577,902
============ ============ ============ ============ =========== =============
RATIO OF EARNINGS TO
FIXED CHARGES (A) / (B): 3.52 3.54 3.49 2.95 2.94 (4.28)
============ ============ ============ ============ =========== =============
(1) Includes allowance for funds used during construction and accrual of
unbilled revenue.
(2) Includes allocation of federal income and state franchise taxes to other
income.
(3) Rentals include the interest factor relating to certain significant rentals
plus one-third of all remaining annual rentals.
(4) Allocable portion of interest included in annual minimum debt service
requirement of supplier.
(5) Includes fixed charges associated with Nuclear Fuel.
Southern California Edison Company
2000 Annual Report
- -------------------------------------------------------------------------------
Southern California Edison Company
Southern California Edison Company (SCE) is one of the nation's largest
investor-owned electric utilities. Headquartered in Rosemead, California, SCE is
a subsidiary of Edison International.
SCE, a 115-year-old electric utility, serves 4.3 million customers and more than
11 million people within a 50,000-square-mile area of central, coastal and
Southern California.
Contents
1 Selected Financial and Operating Data: 1996-2000
2 Management's Discussion and Analysis of
Results of Operations and Financial Condition
25 Consolidated Financial Statements
30 Notes to Consolidated Financial Statements
59 Quarterly Financial Data
60 Responsibility for Financial Reporting
61 Report of Independent Public Accountants
62 Board of Directors
62 Management Team
- ---------------------------------------------------------------- ----------------------------------------------------
Selected Financial and Operating Data: 1996-2000 Southern California Edison Company
Dollars in millions 2000 1999 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
Income statement data:
Operating revenue $ 7,870 $ 7,548 $ 7,500 $ 7,953 $ 7,583
Operating expenses 9,522 6,693 6,582 6,893 6,450
Fuel and purchased power expenses 4,882 3,405 3,586 3,735 3,336
Income tax from operations (1,007) 451 446 582 578
Allowance for funds used during construction 21 24 20 17 25
Interest expense-- net of amounts capitalized 572 483 485 444 453
Net income (loss) (2,028) 509 515 606 655
Net income (loss) available for common stock (2,050) 484 490 576 621
Ratio of earnings to fixed charges (4.28) 2.94 2.95 3.49 3.54
- -------------------------------------------------------------------------------------------------------------------
Balance sheet data:
Assets $15,966 $ 17,657 $ 16,947 $ 18,059 $ 17,737
Gross utility plant 15,653 14,852 14,150 21,483 21,134
Accumulated provision for depreciation
and decommissioning 7,834 7,520 6,896 10,544 9,431
Common shareholder's equity 780 3,133 3,335 3,958 5,045
Preferred stock:
Not subject to mandatory redemption 129 129 129 184 284
Subject to mandatory redemption 256 256 256 275 275
Long-term debt 5,631 5,137 5,447 6,145 4,779
Capital structure:
Common shareholder's equity 11.5% 36.2% 36.4% 37.5% 48.6%
Preferred stock:
Not subject to mandatory redemption 1.9% 1.5% 1.4% 1.7% 2.7%
Subject to mandatory redemption 3.8% 2.9% 2.8% 2.6% 2.7%
Long-term debt 82.8% 59.4% 59.4% 58.2% 46.0%
- -------------------------------------------------------------------------------------------------------------------
Operating data:
Peak demand in megawatts (MW) 19,757 19,122 19,935 19,118 18,207
Generation capacity at peak (MW) 10,191 10,474 10,546 21,511 21,602
Kilowatt-hour sales (in millions) 83,436 78,602 76,595 77,234 75,572
Total energy requirement (kWh) (in millions) 82,503 78,752 80,289 86,849 84,236
Energy mix:
Thermal 36.0% 35.5% 38.8% 44.6% 47.6%
Hydro 5.4% 5.6% 7.4% 6.5% 6.9%
Purchased power and other sources 58.6% 58.9% 53.8% 48.9% 45.5%
Customers (in millions) 4.29 4.36 4.27 4.25 4.22
Full-time employees 12,593 13,040 13,177 12,642 12,057
1
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
California's investor-owned electric utilities, including Southern California
Edison Company (SCE), are currently facing a crisis resulting from deregulation
of the generation side of the electric industry through legislation enacted by
the California Legislature and decisions issued by the California Public
Utilities Commission (CPUC). Under the legislation and CPUC decisions, prices
for wholesale purchases of electricity from power suppliers are set by markets
while the retail prices paid by utility customers for electricity delivered to
them remain frozen at June 1996 levels. Since May 2000, SCE's costs to obtain
power (at wholesale electricity prices) for resale to its customers
substantially exceeded revenue from frozen rates. The shortfall has been
accumulated in the transition revenue account (TRA), a CPUC-authorized
regulatory asset. SCE has borrowed significant amounts of money to finance its
electricity purchases, creating a severe financial drain on SCE.
On April 9, 2001, SCE and the California Department of Water Resources (CDWR)
executed a memorandum of understanding (MOU) which sets forth a comprehensive
plan calling for legislation, regulatory action and definitive agreements to
resolve important aspects of the energy crisis, and which is expected to help
restore SCE's creditworthiness and liquidity. The Governor of the State of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. The MOU
is discussed in detail in the Memorandum of Understanding with the CDWR section.
SCE and the CDWR committed in the MOU to proceed in good faith to sponsor and
support the required legislation and to negotiate in good faith the necessary
definitive agreements. If required legislation is not adopted and definitive
agreements executed by August 15, 2001, or if the CPUC does not adopt required
implementing decisions by June 8, 2001, the MOU may be terminated by SCE or the
CDWR. SCE cannot provide assurance that all the required legislation will be
enacted, regulatory actions taken and definitive agreements executed before the
applicable deadlines.
Accounting standards generally accepted in the United States permit SCE to defer
costs as regulatory assets if those costs are determined to be probable of
recovery in future rates. If SCE determines that regulatory assets, such as the
TRA and the transition cost balancing account (TCBA), are no longer probable of
recovery through future rates, they must be written off. The TCBA is a
regulatory balancing account that tracks the recovery of generation-related
transition costs, including stranded investments. SCE must assess the
probability of recovery of the undercollected costs that are now recorded in the
TCBA in light of the CPUC's March 27, 2001, and April 3, 2001, decisions,
including the retroactive transfer of balances from SCE's TRA to its TCBA and
related changes that are discussed in more detail in Rate Stabilization
Proceeding. These decisions and other regulatory and legislative actions did not
meet SCE's prior expectation that the CPUC would provide adequate cost recovery
mechanisms. Until legislative and regulatory actions contemplated by the MOU
occur, or other actions are taken, SCE is unable to conclude that its
undercollected costs that are recovered through the TCBA mechanism are probable
of recovery in future rates. As a result, SCE's financial results for the year
ended 2000 include an after-tax charge of approximately $2.5 billion ($4.2
billion on a pre-tax basis), reflecting a write-off of the TCBA (as restated to
reflect the CPUC's March 27, 2001, decisions) and regulatory assets to be
recovered through the TCBA mechanism, as of December 31, 2000. In addition, SCE
currently does not have regulatory authority to recover any purchased-power
costs it incurs during 2001 in excess of revenue from retail rates. Those
amounts will be charged against earnings in 2001 absent a regulatory or
legislative solution, such as implementation of the actions called for in the
MOU that makes recovery of such costs probable. This will result in further
material declines in reported common shareholder's equity, particularly in light
of the CPUC's failure to provide SCE with sufficient rate revenue to cover its
ongoing costs and obligations through the CPUC's March 27, 2001, decisions. The
December 31, 2000, write-off also caused SCE to be unable to meet an earnings
test that must be met before SCE can issue additional first mortgage bonds. If
the MOU is implemented, or a rate mechanism provided by legislation or
regulatory authority is established that makes recovery from regulated rates
probable as to all or a portion of the amounts that were previously charged
against earnings, current accounting standards provide that a regulatory asset
would be reinstated with a corresponding increase in earnings.
2
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Southern California Edison Company
The following pages include a discussion of the history of the TRA and TCBA and
related circumstances, the devastating effect on the financial condition of SCE
of undercollections recorded in the TRA and TCBA, the current status of the
undercollections, the impact of the CPUC's March 27, 2001, decisions and related
matters, and possible resolution of the current crisis through implementation of
the MOU.
Results of Operations
Earnings
In 2000, SCE recorded a loss of $2.0 billion. The net loss in 2000 included a
write-off of regulatory assets and liabilities in the amount of $2.5 billion
(after tax) as of December 31, 2000. Accounting principles generally accepted in
the United States require SCE at each financial statement date to assess the
probability of recovering its regulatory assets through a regulatory process. On
March 27, 2001, the CPUC issued a decision adopting a 3(cent)-per-kilowatt-hour
(kWh) surcharge on rates effective immediately, with revenue generated by the
surcharge to be applied to electric power costs incurred after the date of the
order. This rate stabilization decision also stated that the rate freeze had not
ended, and the TCBA mechanism was to remain in place. However, the decision
required SCE to recalculate the TCBA retroactive to January 1, 1998, the
beginning of the rate freeze period. The new calculation required the coal and
hydroelectric balancing accounting overcollections (which amounted to $1.5
billion as of December 31, 2000) to be closed monthly to the TRA, rather than
annually to the TCBA. In addition, it required the TRA to be transferred to the
TCBA on a monthly basis. Previous rules had called for TRA overcollections to be
transferred to the TCBA monthly, while undercollections were to remain in the
TRA until they were recovered from future overcollections or the end of the rate
freeze, whichever came first. Based on the new rules, the $4.5 billion TRA
undercollection as of December 31, 2000, and the coal and hydroelectric
balancing account overcollections were reclassified, and the TCBA balance was
recalculated to be a $2.9 billion undercollection (see further discussion of the
CPUC rate increase in the Rate Stabilization Proceeding section and the
components of the TCBA undercollection in the Status of Transition and Power
Procurement Costs Recovery section of Regulatory Environment).
On April 9, 2001, SCE and the CDWR executed an MOU providing for the sale of
SCE's transmission assets, or other assets under certain circumstances, recovery
of SCE's net undercollected amount through the application of proceeds of the
asset sale and one or more securitization financings, rate-making provisions for
recovery of SCE's future power procurement costs, settlement of SCE's legal
actions against the CPUC, and other elements of a comprehensive plan (see
further discussion in Memorandum of Understanding with the CDWR). The
implementation of the MOU requires various regulatory and legislative actions to
be taken in the future. Until those actions or actions in other proceedings are
taken, which would include modifying or reversing recent CPUC decisions that
impair recovery of SCE's power procurement and transition costs, SCE is not able
to conclude that, under applicable accounting principles, the $2.9 billion TCBA
undercollection (as recalculated above) and $1.3 billion (book value) of other
regulatory assets and liabilities, that were to be recovered through the TCBA
mechanism by the end of the rate freeze, are probable of recovery through the
rate-making process as of December 31, 2000.
As a result, accounting principles generally accepted in the United States
require that the net balance of these accounts be written off as a charge to
earnings as of December 31, 2000. This write-off consists of the following:
3
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
In millions
-----------------------------------------------------------------------
TCBA (as recalculated) $2,878
Unamortized nuclear investment-- net 610
Purchased-power settlements 435
Unamortized loss on sale of plant 61
Other regulatory assets-- net 39
-----------------------------------------------------------------------
Subtotal 4,023
Flow-through taxes 218
-----------------------------------------------------------------------
Total regulatory assets-- net 4,241
Less income tax benefit (1,720)
-----------------------------------------------------------------------
Net write-off $2,521
- --------------------------------------------------------------------------------
This write-off is included in the income statement as a $4.0 billion charge to
provisions for regulatory adjustment clauses, and a $1.5 billion net reduction
in income tax expense.
As stated above, an MOU has been negotiated with representatives of the Governor
(see Memorandum of Understanding with the CDWR) to resolve the energy crisis.
The regulatory and legislative actions set forth in the MOU, if implemented, are
expected to result in a rate-making mechanism that would make recovery of these
regulatory assets probable. If and when those actions or other actions that make
such recovery probable are taken, and the necessary rate-making mechanism is
adopted, the regulatory assets would be restored to the balance sheet, with a
corresponding increase to earnings.
Excluding the write-off, SCE's 2000 earnings were $471 million. SCE's earnings
were $484 million in 1999 and $490 million in 1998. SCE's 1999 earnings include
a $15 million one-time tax benefit due to an Internal Revenue Service ruling.
The 2000 decrease was mainly due to adjustments to reflect potential regulatory
refunds and lower gains from sales of equity investments, partially offset by
superior operating performance at the San Onofre Nuclear Generating Station and
higher kWh sales. Excluding the one-time tax benefit, SCE's 1999 earnings were
$469 million, down $21 million from 1998. The 1999 decrease was primarily due to
the accelerated depreciation of SCE's generation assets, partially offset by
higher kWh sales in 1999.
Unless a rate-making mechanism is implemented in accordance with the MOU
described above or other necessary rate-making action is taken, future net
undercollections in the TCBA will be charged to earnings as the losses are
incurred. The loss (before tax) incurred in this balancing account (as
redefined) in January and February 2001 amounts to approximately $800 million.
SCE anticipates that losses will continue unless a rate-making mechanism is
established. In addition to the losses from the TCBA undercollections, SCE
expects its 2001 earnings to be negatively affected by the recent fire and
resulting damage at San Onofre Unit 3. See further discussion of the San Onofre
fire in the San Onofre Nuclear Generating Station section.
Operating Revenue
SCE's customers are able to choose to purchase power directly from an energy
service provider, thus becoming direct access customers, or continue to have SCE
purchase power on their behalf. Most direct access customers are billed by SCE,
but given a credit for the generation portion of their bills. Under Assembly
Bill 1 (First Extraordinary Session) (AB 1X), enacted on February 1, 2001, the
CPUC was directed (on a schedule it determines) to suspend the ability of retail
customers to select alternative providers of electricity until the CDWR stops
buying power for retail customers.
During 2000, as a result of the power shortage in California, SCE's customers on
interruptible rate programs (which provide for a lower generation rate with a
provision that service can be interrupted if needed, with penalties for
noncompliance) were asked to curtail their electricity usage at various times.
As a result of noncompliance with SCE's requests, those customers were assessed
significant penalties.
4
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Southern California Edison Company
On January 26, 2001, the CPUC waived the penalties being assessed to
noncompliant customers until a reevaluation of the operation of the
interruptible programs can be completed.
Operating revenue increased in 2000 (as shown in the table below), primarily due
to: warmer weather in the second and third quarters of 2000 as compared to the
same periods in 1999; increased resale sales; and an increase in revenue related
to penalties customers incurred for not adhering to their interruptible
contracts. The increase in resale sales resulted from other utilities and
municipalities exercising their contractual option to buy more power from SCE as
the price of power purchased through the California Power Exchange (PX) and
Independent System Operator (ISO) increased significantly in 2000. These
increases were partially offset by the credit given to customers who chose
direct access. Operating revenue increased by less than 1% in 1999, as increased
kWh sales and revenue resulting from maintenance work SCE was providing the new
owners of generating plants previously sold by SCE was almost completely offset
by the credit given to customers who chose direct access. On March 27, 2001, the
CPUC affirmed that the interim surcharge of 1(cent) per kWh granted on January
4, 2001, is now permanent. See further discussion in Rate Stabilization
Proceeding.
In 2000, more than 92% of operating revenue was from retail sales. Retail rates
are regulated by the CPUC and wholesale rates are regulated by the Federal
Energy Regulatory Commission (FERC).
Due to warmer weather during the summer months, operating revenue during the
third quarter of each year is significantly higher than other quarters.
The changes in operating revenue resulted from:
In millions Year ended December 31, 2000 1999 1998
---------------------------------------------------------------------------
Operating revenue --
Rate changes (including refunds) $ 120 $ (75) $ (498)
Direct access credit (434) (213) (29)
Interruptible noncompliance penalty 102 6 --
Sales volume changes 520 195 (44)
Other 14 136 117
----------------------------------------------------------------------------
Total $ 322 $ 49 $ (454)
-----------------------------------------------------------------------------
Operating Expenses
Fuel expense decreased in both 2000 and 1999. The decrease in 2000 was primarily
due to fuel-related refunds resulting from a settlement with another utility
that SCE recorded in the second and third quarters of 2000. The decrease in 1999
was due to the sale of 12 generating plants in 1998.
Prior to April 1998, SCE was required under federal law and CPUC orders to enter
into contracts to purchase power from qualifying facilities (QFs) at
CPUC-mandated prices even though energy and capacity prices under many of these
contracts are generally higher than other sources. Purchased-power expense
related to contracts decreased in both 2000 and 1999. The decrease in 2000 was
primarily due to a contract adjustment with a state agency, as well as the terms
in some of the remaining QF contracts reverting to lower prices. The decrease in
1999 was primarily due to the terms in some of the remaining QF contracts
reverting to lower prices, as well as SCE's settlement agreements to terminate
contracts with certain QFs. SCE's settlement agreements with certain QFs
decreased purchased-power expense related to contracts by $47 million in 1999.
SCE's purchased-power settlement obligations were recorded as a liability.
Because the settlement payments were to be recovered through the TCBA mechanism
as the payments were made, a regulatory asset was also recorded. As of December
31, 2000, the purchased-power settlement regulatory asset was written off as a
charge to earnings. See further discussion of the write-off in Earnings.
5
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
In 2000, PX/ISO purchased-power expense increased significantly due to increased
demand for electricity in California, dramatic price increases for natural gas
(a key input of electricity production), and structural problems within the PX
and ISO. The increased volume of higher priced PX purchases was minimally offset
by increases in PX sales revenue and ISO net revenue, as well as the use of risk
management instruments (gas call options and PX block forward contracts). The
gas call options (which were sold in October 2000) and the PX block forward
contracts mitigated SCE's transition cost recovery exposure to increases in
energy prices. SCE's use of gas call options reduced PX/ISO purchased-power
expense by $200 million in 2000 compared to 1999. SCE's use of PX block forward
contracts reduced PX/ISO purchased-power expense by $688 million in 2000
compared to 1999. In 1999, PX/ISO purchased-power expense increased compared to
1998, mainly due to three additional months of PX transactions in 1999. However,
when 1999 PX purchased-power expense was compared on the same nine-month basis
as 1998, the increase was less than 1%, despite the fact that SCE experienced a
significant decrease in the volume of kWh sales through the PX. The lower volume
of sales through the PX in 1999 was the result of less generation at SCE (due to
San Onofre refueling outages in 1999, divestiture of 12 generating plants in
1998 and reduced hydroelectric generation) and fewer purchases from QFs. SCE's
use of gas call options decreased PX/ISO purchased-power expense by $8 million
in 1999 compared to 1998. SCE's use of PX block forward contracts increased
PX/ISO purchased-power expense by $3 million in 1999 compared to 1998. For a
further discussion of SCE's hedging instruments and the recent significant
increases in power prices, see Market Risk Exposures. As of December 15, 2000,
the FERC eliminated the requirement that SCE buy and sell its purchased and
generated power through the PX and ISO. See further discussion in Wholesale
Electricity Markets.
Due to SCE's noncompliance with the PX's tariff requirement for posting
collateral for all transactions in the day-ahead and day-of markets as a result
of the downgrade in its credit rating, the PX suspended SCE's market trading
privileges for the day-of market effective January 18, 2001, and, for the
day-ahead market effective January 19, 2001. See further discussion of SCE's
liquidity crisis in Financial Condition.
Provisions for regulatory adjustment clauses increased in 2000 and decreased in
1999. The 2000 increase was mainly due to a write-off as of December 31, 2000,
of $4.2 billion in regulatory assets and liabilities as a result of the
California energy crisis. See further discussion of the write-off in the
Earnings section. In addition, the provision also increased in 2000 due to
adjustments to reflect potential regulatory refunds related to the outcome of
the CPUC's reevaluation of the operation of the interruptible rate programs. The
decrease in 1999 was mainly due to undercollections related to the TCBA and the
rate-making treatment of the rate reduction notes. These undercollections were
partially offset by overcollections related to the administration of public
purpose funds. The rate-making treatment associated with rate reduction notes
has allowed for the deferral of the recovery of a portion of the
transition-related costs, from a four-year period to a 10-year period. SCE's use
of gas call options increased the provisions by $200 million in 2000 compared to
1999, and decreased the provisions by $8 million in 1999 compared to 1998.
Other operation and maintenance expense decreased in 2000, primarily due to a
$120 million decrease in mandated transmission service (known as must-run
reliability services) expense and a $19 million decrease in operating expenses
at San Onofre. The decrease at San Onofre in 2000 was primarily due to scheduled
refueling outages for both units in the first half of 1999. San Onofre had only
one refueling outage in 2000. Other operation and maintenance expense increased
in 1999, mostly due to an increase in mandated transmission service expense and
PX and ISO costs incurred by SCE. These increases were partially offset by lower
expenses incurred for distribution facilities.
Income taxes decreased in 2000, primarily due to the $1.5 billion income tax
benefit related to the write-off as of December 31, 2000, of regulatory assets
and liabilities in the amount of $2.5 billion (after tax). Absent the write-off,
SCE's income tax expense increased in 2000 due to higher pre-tax income.
6
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Southern California Edison Company
Net gain on sale of utility plant in 2000 resulted from the sale of additional
property related to four of the generating stations SCE sold in 1998. The gains
were returned to the ratepayers through the TCBA mechanism.
Other Income and Deductions
Interest and dividend income increased in 2000, primarily due to increases in
interest earned on higher balancing account undercollections.
Other nonoperating income decreased in 2000 but increased in 1999. Although SCE
recorded gains on sales of equity investments in 2000, 1999 and 1998, the
different amounts of the gains were the primary reason for other nonoperating
income to decrease in 2000 when compared to 1999, and to increase in 1999 when
compared to 1998.
Interest expense -- net of amounts capitalized increased in 2000 and decreased
slightly in 1999. The increase in 2000 was mostly due to higher overall
short-term debt balances necessary to meet general cash requirements (especially
PX and ISO payments) and higher interest expense related to balancing account
overcollections. The decrease in 1999 was mainly due to a decrease in interest
on long-term debt more than offsetting an increase resulting from higher overall
short-term debt balances necessary to meet general cash requirements and higher
interest expense related to balancing account overcollections. The 1999 decrease
in interest on long-term debt was due to an adjustment of accrued interest in
first quarter 1998 related to the rate reduction notes issued in December 1997.
Other nonoperating deductions decreased in 1999, as expenses related to a ballot
initiative in 1998 more than offset additional accruals for regulatory matters
in 1999.
The tax benefit on other income and deductions increased in both 2000 and 1999.
The increase in 2000 was primarily the result of tax benefits related to
interest expense and other nonoperating expenses exceeding the tax expense
related to interest income and other nonoperating income. The increase in 1999
was primarily the result of a $15 million one-time tax benefit due to an
Internal Revenue Service ruling.
Financial Condition
SCE's liquidity is primarily affected by power purchases, debt maturities,
access to capital markets, dividend payments and capital expenditures. Capital
resources include cash from operations and external financings. As a result of
SCE's lack of creditworthiness (further discussed in Liquidity Crisis), at March
31, 2001, the fair market value of approximately $500 million of its short-term
debt was approximately 75% of its carrying value (as compared to 100% at
December 31, 2000) and the fair market value of its long-term debt was
approximately 90% of its carrying value (as compared to 92% at December 31,
2000).
Beginning in 1995, Edison International's Board of Directors authorized the
repurchase of up to $2.8 billion of its outstanding shares of common stock.
Edison International repurchased more than 21 million shares (approximately $400
million) of its common stock during the first six months of 2000. These were the
first repurchases since first quarter 1999. Between January 1, 1995, and June
30, 2000, Edison International repurchased $2.8 billion (approximately 122
million shares) of its outstanding shares of common stock, funded by dividends
from its subsidiaries (primarily from SCE).
Liquidity Crisis
Sustained higher wholesale energy prices that began in May 2000 persisted
through Spring 2001. This resulted in an increasing undercollection in the TRA.
The increasing undercollection, coupled with SCE's anticipated near-term capital
requirements (detailed in the Projected Capital Requirements section of
Financial Condition) and the adverse reaction of the credit markets to continued
regulatory uncertainty
7
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
regarding SCE's ability to recover its current and future power procurement
costs, have materially and adversely affected SCE's liquidity. As a result of
its liquidity crisis, SCE has taken and is taking steps to conserve cash, so
that it can continue to provide service to its customers. As a part of this
process, SCE has temporarily suspended payments of certain obligations for
principal and interest on outstanding debt and for purchased power. As of March
31, 2001, SCE had $2.7 billion in obligations that were unpaid and overdue
including: (1) $626 million to the PX or ISO; (2) $1.1 billion to QFs; (3) $229
million in PX energy credits for energy service providers; (4) $506 million of
matured commercial paper; (5) $206 million of principal and interest on its
5-7/8% notes; and (6) $7 million of other obligations. SCE's failure to pay when
due the principal amount of the 5-7/8% series of notes constitutes a default on
the series, entitling those noteholders to exercise their remedies. Such failure
and the failure to pay commercial paper when due could also constitute an event
of default on all the other series of notes (totaling $2.4 billion of
outstanding principal) if the trustee or holders of 25% in principal amount of
the notes give a notice demanding that the default be cured, and SCE does not
cure the default within 30 days. Such failures are also an event of default
under SCE's credit facilities, entitling those lenders to exercise their
remedies including potential acceleration of the outstanding borrowings of $1.6
billion. If a notice of default is received, SCE could cure the default only by
paying $700 million in overdue principal and interest to holders of commercial
paper and the 5-7/8% notes. Making such payment would further impact SCE's
liquidity. If a notice of default were received and not cured, and the trustee
or noteholders were to declare an acceleration of the outstanding principal
amount of the senior unsecured notes, SCE would not have the cash to pay the
obligation and could be forced to declare bankruptcy.
Subject to certain conditions, the bank lenders under SCE's credit
facilities agreed to forbear from exercising remedies, including acceleration of
borrowed amounts, against SCE with respect to the event of default arising from
the failure to pay the 5-7/8 notes and commercial paper when due. The initial
forbearance agreement expired on February 13, 2001, but it has been extended
twice and currently expires on April 28, 2001. At March 31, 2001, SCE had
estimated cash reserves of approximately $2.0 billion, which is approximately
$700 million less than its outstanding unpaid obligations (discussed above) and
overdue amounts of preferred stock dividends (see below). As of March 31, 2001,
SCE resumed payment of interest on its debt obligations. If the MOU is
implemented, it is expected to allow SCE to recover its undercollected costs and
to restore SCE's creditworthiness, which would allow SCE to pay all of its past
due obligations.
On March 27, 2001, the CPUC ordered SCE and the other California investor-owned
utilities to pay QFs for power deliveries on a going forward basis, commencing
with April 2001 deliveries. SCE must pay the QFs within 15 days of the end of
the QFs' billing period, and QFs are allowed to establish 15-day billing
periods. Failure to make a required payment within 15 days of delivery would
result in a fine equal to the amount owed to the QF. The CPUC decision also
modified the formula used in calculating payments to QFs by substituting natural
gas index prices based on deliveries at the Oregon border rather than index
prices at the Arizona border. The changes apply to all QFs, where appropriate,
regardless of whether they use natural gas or other resources such as solar or
wind.
On March 27, 2001, the CPUC also issued decisions on the California Procurement
Adjustment (CPA) calculation (see CDWR Power Purchases discussion) and the
approval of a 3(cent)-per-kWh rate increase (see Rate Stabilization Proceeding
discussion). Based on these two decisions, SCE estimates that revenue going
forward will not be sufficient to recover retained generation, purchased-power
and transition costs. In comments filed with the CPUC on March 29, 2001, and
April 2, 2001, SCE provided a forecast showing that the net effects of the rate
increase, the payment ordered to be made to the CDWR, and the QF decision
discussed above could result in a shortfall to the CPA calculation of $1.7
billion for SCE during 2001. To implement the MOU, it will be necessary for the
CPUC to modify or rescind these decisions.
In light of SCE's liquidity crisis, its Board of Directors did not declare
quarterly common stock dividends to SCE's parent, Edison International, in
either December 2000 or March 2001. Also, SCE's Board has not
8
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Southern California Edison Company
declared the regular quarterly dividends for SCE's cumulative preferred stock,
4.08% Series, 4.24% Series, 4.32% Series, 4.78% Series, 6.05% Series, 6.45%
Series and 7.23% Series in 2001. As of March 31, 2001, SCE's preferred stock
dividends in arrears were $6 million. As a result of SCE's $2.5 billion charge
to earnings as of December 31, 2000, SCE's retained earnings are now in a
deficit position and therefore under California law, SCE will be unable to pay
dividends as long as a deficit remains. SCE does not meet other tests under
which dividends can be paid from sources other than retained earnings. As long
as accumulated dividends on SCE's preferred stock remain unpaid, SCE cannot pay
any dividends on its common stock.
SCE has begun immediate cost-cutting measures which, together with previously
announced actions, such as freezing new hires, postponing certain capital
expenditures and ceasing new charitable contributions, are aimed at reducing
general operating costs. These actions were expected to impact about 1,450 to
1,850 jobs, affect service levels for customers, and reduce near-term capital
expenditures to levels that will not sustain operations in the long term.
However, on March 15, 2001, the CPUC issued an order rescinding SCE's layoffs of
employees involved with service and reliability. SCE was also ordered to restore
specified service levels, make regular reports to the CPUC concerning its
cost-cutting measures, and track its cost savings pending future adjustments to
rates. The amount of the cost savings affected by the order is not material.
SCE's current actions, including the suspension of debt and purchased-power
obligations, are intended to allow it to continue to operate while efforts to
reach a regulatory solution, involving both state and federal authorities, are
underway. Additional actions by SCE may be necessary if the energy and liquidity
crisis is not resolved in the near future. See further discussion in Status of
Transition and Power Procurement Costs Recovery.
For additional discussion on the impact of California's energy crisis on SCE's
liquidity, see Cash Flows from Financing Activities. For a discussion on an
agreement to resolve SCE's crisis, see Memorandum of Understanding with the
CDWR.
SCE's future liquidity depends, in large part, on whether the MOU is
implemented, or other action by the California Legislature and the CPUC is taken
in a manner sufficient to resolve the energy crisis and the cash flow deficit
created by the current rate structure and the excessively high price of energy.
Without a change in circumstances, such as that contemplated by the MOU,
resolution of SCE's liquidity crisis and its ability to continue to operate
outside of bankruptcy is uncertain. In addition, SCE's independent accountant's
opinion in the accompanying financial statements includes an explanatory
paragraph which states that the issues resulting from the California energy
crisis raise substantial doubt about SCE's ability to continue as a going
concern.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $829 million in 2000, $1.5
billion in 1999 and $978 million in 1998. The decrease in cash flows provided by
operating activities in 2000 was primarily due to the extremely high prices SCE
paid for energy and ancillary services procured through the PX and ISO. Cash
flows provided by operations is expected to increase in the first half of 2001
as SCE conserves cash as result of the liquidity crisis (see Liquidity Crisis
discussion).
SCE's cash flow coverage of dividends was 2.1 times for both 2000 and 1999, and
0.9 times for 1998. The 1999 increase primarily reflects the rate-making
treatment of the gains on sales of the generating plants, as well as the special
dividend ($680 million) SCE paid to Edison International in 1998. Beginning in
first quarter 2001, the cash flow coverage of dividends calculation will reflect
SCE's inability to pay dividends (discussed above in the Liquidity Crisis
section).
SCE's estimates of cash available for operations in 2001 assume, among other
things, satisfactory reimbursement of costs incurred during California's energy
crisis, the receipt of adequate and timely rate relief, and the realization of
its assumptions regarding cost increases, including the cost of capital.
9
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
Cash Flows from Financing Activities
At December 31, 2000, SCE had total credit lines of $1.65 billion, with $125
million available for the refinancing of its variable-rate pollution-control
bonds. These unsecured lines of credit have various expiration dates and can be
drawn down at negotiated or bank index rates. However, as of January 2, 2001,
SCE had drawn on its entire credit lines of $1.65 billion.
Short-term debt is used to finance balancing account undercollections, fuel
inventories and general cash requirements, including purchased-power payments.
Long-term debt is used mainly to finance capital expenditures. External
financings are influenced by market conditions and other factors. Because of the
$2.5 billion charge to earnings, SCE does not currently meet the interest
coverage ratios that are required for SCE to issue additional first mortgage
bonds or preferred stock. In addition, because of its current liquidity and
credit problems, SCE is unable to obtain financing of any kind.
As a result of investors' concerns regarding the California energy crisis and
its impact on SCE's liquidity and overall financial condition, SCE has
repurchased $549 million of pollution-control bonds that could not be remarketed
in accordance with their terms. These bonds may be remarketed in the future if
SCE's credit status improves sufficiently. In addition, SCE has been unable to
sell its commercial paper and other short-term financial instruments.
In January 2001, Fitch IBCA, Standard & Poor's and Moody's Investors Service
lowered their credit ratings of SCE to substantially below investment grade. In
mid-April, Moody's removed SCE's credit ratings from review for possible
downgrade. The ratings remain under review for possible downgrade by the other
agencies.
Subject to the outcome of regulatory, legislative and judicial proceedings,
including steps to implement the MOU, SCE intends to pay all of its obligations.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure,
limiting the dividends it may pay Edison International.
In December 1997, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable
right known as transition property. Transition property is a current property
right created by the restructuring legislation and a financing order of the CPUC
and consists generally of the right to be paid a specified amount from
nonbypassable rates charged to residential and small commercial customers. The
rate reduction notes are being repaid over 10 years through these nonbypassable
residential and small commercial customer rates, which constitute the transition
property purchased by SCE Funding LLC. The remaining series of outstanding rate
reduction notes have scheduled maturities beginning in 2001 and ending in 2007,
with interest rates ranging from 6.17% to 6.42%. The notes are secured by the
transition property and are not secured by, or payable from, assets of SCE or
Edison International. SCE used the proceeds from the sale of the transition
property to retire debt and equity securities. Although, as required by
accounting principles generally accepted in the United States, SCE Funding LLC
is consolidated with SCE and the rate reduction notes are shown as long-term
debt in the consolidated financial statements, SCE Funding LLC is legally
separate from SCE. The assets of SCE Funding LLC are not available to creditors
of SCE or Edison International and the transition property is legally not an
asset of SCE or Edison International. Due to its recent credit rating downgrade,
in January 2001, SCE began remitting its customer collections related to the
rate-reduction notes on a daily basis.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant and funding of nuclear decommissioning trusts. Decommissioning costs are
recovered in rates. These costs are expected to be
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Southern California Edison Company
funded from independent decommissioning trusts that receive SCE contributions of
approximately $25 million per year. In 1995, the CPUC determined the
restrictions related to the investments of these trusts. They are: not more than
50% of the fair market value of the qualified trusts may be invested in equity
securities; not more than 20% of the fair market value of the trusts may be
invested in international equity securities; up to 100% of the fair market
values of the trusts may be invested in investment grade fixed-income securities
including, but not limited to, government, agency, municipal, corporate,
mortgage-backed, asset-backed, non-dollar, and cash equivalent securities; and
derivatives of all descriptions are prohibited. Contributions to the
decommissioning trusts are reviewed every three years by the CPUC. The
contributions are determined from an analysis of estimated decommissioning
costs, the current value of trust assets and long-term forecasts of cost
escalation and after-tax return on trust investments. Favorable or unfavorable
investment performance in a period will not change the amount of contributions
for that period. However, trust performance for the three years leading up to a
review proceeding will provide input into the contribution analysis for that
proceeding's contribution determination.
Projected Capital Requirements
SCE's projected construction expenditures for 2001 are $602 million. This
projection reflects SCE's recently announced cost-cutting measures discussed
above in the Liquidity Crisis section.
Long-term debt maturities and sinking fund requirements for the next five years
are: 2001 - $646 million; 2002 - $746 million; 2003 - $1.4 billion; 2004 - $371
million; and 2005 - $246 million.
Preferred stock redemption requirements for the next five years are: 2001- zero;
2002 - $105 million; 2003 - $9 million; 2004 - $9 million; and 2005 - $9
million.
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in both energy
prices and interest rates. SCE's risk management policy allows the use of
derivative financial instruments to manage its financial exposures, but
prohibits the use of these instruments for speculative or trading purposes. At
December 31, 2000, a 10% change in market rates would have had an immaterial
effect on SCE's financial instruments not specifically discussed below.
SCE is exposed to changes in interest rates primarily as a result of its
borrowing and investing activities used for liquidity purposes and to fund
business operations, as well as to finance capital expenditures. The nature and
amount of SCE's long-term and short-term debt can be expected to vary as a
result of future business requirements, market conditions and other factors. As
a result of California's energy crisis, SCE has been exposed to significantly
higher interest rates, which has intensified its liquidity crisis (further
discussed in the Liquidity Crisis section of Financial Condition).
At December 31, 2000, SCE did not believe that its short-term debt was subject
to interest rate risk, due to the fair market value being approximately equal to
the carrying value. SCE did believe that the fair market value of its fixed-rate
long-term debt was subject to interest rate risk. At December 31, 2000, a 10%
increase in market interest rates would have resulted in a $222 million decrease
in the fair market value of SCE's long-term debt. A 10% decrease in market
interest rates would have resulted in a $244 million increase in the fair market
value of SCE's long-term debt. See further discussion in Financial Condition of
the impact of SCE's lack of creditworthiness on its short-term and long-term
debt.
SCE used an interest rate swap to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At December 31, 2000, a 10%
increase in market interest rates would have resulted in a $5 million increase
in the fair value of SCE's interest rate swap. A 10% decrease in market interest
rates would have resulted in an $8 million decrease in the fair value of SCE's
interest rate swap. As a result of the downgrade in SCE's credit rating below
the level allowed under the interest rate hedge agreement, on
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
January 5, 2001, the counterparty on this interest rate swap terminated the
agreement. As a result of the termination of the swap, SCE is paying a floating
rate on $196 million of its debt due 2008.
Since April 1998, the price SCE paid to acquire power on behalf of customers was
allowed to float, in accordance with the 1996 electric utility restructuring
law. Until May 2000, retail rates were sufficient to cover the cost of power and
other SCE costs. However, since May 2000, market power prices have skyrocketed,
creating a substantial gap between costs and retail rates. In response to the
dramatically higher prices, the ISO and the FERC have placed certain caps on the
price of power, but these caps are set at high levels and are not entirely
effective. For example, SCE paid an average of $248 per megawatt in December
2000, versus an average of $32 per megawatt in December 1999.
SCE attempted to hedge a portion of its exposure to increases in power prices.
However, the CPUC has approved a very limited amount of hedging. In 1997, SCE
bought gas call options as a hedge against electricity price increases, since
gas is a primary component for much of SCE's power supply. These gas call
options were sold in October 2000, resulting in a $190 million gain (lowering
purchased-power expense) for 2000. In July 1999, SCE began forward purchases of
electricity through the PX block forward market. In November 2000, SCE began
purchases of energy through bilateral forward contracts. At December 31, 2000,
the nominal value of SCE's block and bilateral forward contracts was $234
million and $798 million, respectively. The block forward contracts reduced
purchased-power costs by $684 million in 2000.
At December 31, 2000, a 10% fluctuation in electricity prices would have changed
the fair market value of SCE's forward contracts by $187 million.
Because SCE has temporarily suspended payments for purchased power since January
16, 2001, the PX sought to liquidate SCE's remaining block forward contracts.
Before the PX could do so, on February 2, 2001, the State of California seized
the contracts, but must pay SCE the reasonable value of the contracts under the
law. A valuation of the contracts is expected in mid-2001. After other elements
of the MOU are implemented, SCE would relinquish all claims against the State
for seizing these contracts.
Due to its speculative grade credit ratings, SCE has been unable to purchase
additional bilateral forward contracts, and some of the existing contracts were
terminated by the counterparties.
In January 2001, the CDWR began purchasing power for delivery to utility
customers. On March 27, 2001, the CPUC issued a decision directing SCE to, among
other things, immediately pay amounts owed to the CDWR for certain past
purchases of power for SCE's customers. See additional discussion of regulatory
proceedings related to CDWR activities in the Generation and Power Procurement
section of Regulatory Environment.
Regulatory Environment
SCE operates in a highly regulated environment in which it has an obligation to
deliver electric service to customers in return for an exclusive franchise
within its service territory and certain obligations of the regulatory
authorities to provide just and reasonable rates. In 1996, state lawmakers and
the CPUC initiated the electric industry restructuring process. SCE was directed
by the CPUC to divest the bulk of its gas-fired generation portfolio. Today,
independent power companies own those generating plants. Along with electric
industry restructuring, a multi-year freeze on the rates that SCE could charge
its customers was mandated and transition cost recovery mechanisms (as described
in Status of Transition and Power Procurement Costs Recovery) allowing SCE to
recover its stranded costs associated with generation-related assets were
implemented. California's electric industry restructuring statute included
provisions to finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which allowed SCE to
reduce rates by at least 10% to these customers, effective January 1, 1998.
These frozen rates were to remain in effect until the earlier of March 31, 2002,
or the
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Southern California Edison Company
date when the CPUC-authorized costs for utility-owned generation assets and
obligations were recovered. However, since May 2000, the prices charged by
sellers of power have escalated far beyond what SCE can currently charge its
customers. See further discussion in Wholesale Electricity Markets.
Generation and Power Procurement
During the rate freeze, revenue from generation-related operations has been
determined through the market and transition cost recovery mechanisms, which
included the nuclear rate-making agreements. The portion of revenue related to
coal generation plant costs (Mohave Generating Station and Four Corners
Generating Station) that was made uneconomic by electric industry restructuring
has been recovered through the transition cost recovery mechanisms. After April
1, 1998, coal generation operating costs have been recovered through the market.
The excess of power sales revenue from the coal generating plants over the
plants' operating costs has been accumulated in a coal generation balancing
account. SCE's costs associated with its hydroelectric plants have been
recovered through a performance-based mechanism. The mechanism set the
hydroelectric revenue requirement and established a formula for extending it
through the duration of the electric industry restructuring transition period,
or until market valuation of the hydroelectric facilities, whichever occurred
first. The mechanism provided that power sales revenue from hydroelectric
facilities in excess of the hydroelectric revenue requirement is accumulated in
a hydroelectric balancing account. In accordance with a CPUC decision issued in
1997, the credit balances in the coal and hydroelectric balancing accounts were
transferred to the TCBA at the end of 1998 and 1999. However, due to the CPUC's
March 27, 2001, rate stabilization decision, the credit balances in these
balancing accounts have now been transferred to the TRA on a monthly basis,
retroactive to January 1, 1998. In addition, the TRA balance, whether over- or
undercollected, has now been transferred to the TCBA on a monthly basis,
retroactive to January 1, 1998. Due to a December 15, 2000, FERC order, SCE is
no longer required to buy and sell power exclusively through the ISO and PX. In
mid-January 2001, the PX suspended SCE's trading privileges for failure to post
collateral due to SCE's rating agency downgrades. As a result, power from SCE's
coal and hydroelectric plants is no longer being sold through the market and
these two balancing accounts have become inactive. As a key element of the MOU,
SCE would continue to own its generation assets, which would be subject to
cost-based ratemaking, through 2010. The MOU calls for the CPUC to adopt cost
recovery mechanisms consistent with SCE obtaining and maintaining an investment
grade credit rating.
SCE has been recovering its investment in its nuclear facilities on an
accelerated basis in exchange for a lower authorized rate of return on
investment. SCE's nuclear assets are earning an annual rate of return on
investment of 7.35%. In addition, the San Onofre incentive pricing plan
authorizes a fixed rate of approximately 4(cent) per kWh generated for operating
costs including incremental capital costs, nuclear fuel and nuclear fuel
financing costs. The San Onofre plan commenced in April 1996, and ends at the
earlier of December 2001 or the date when the statutory rate freeze ends for the
accelerated recovery portion, and in December 2003 for the incentive-pricing
portion. The Palo Verde Nuclear Generating Station's operating costs, including
incremental capital costs, and nuclear fuel and nuclear fuel financing costs,
are subject to balancing account treatment. The Palo Verde plan commenced in
January 1997 and ends in December 2001. The benefits of operation of the San
Onofre units and the Palo Verde units are required to be shared equally with
ratepayers beginning in 2004 and 2002, respectively. Beginning January 1, 1998,
both the San Onofre and Palo Verde rate-making plans became part of the TCBA
mechanism. These rate-making plans and the TCBA mechanism will continue for
rate-making purposes at least through the end of the rate freeze period. Under
the MOU, both nuclear facilities would be subject to cost-based ratemaking upon
completion of their respective rate-making plans and the sharing mechanisms that
were to begin in 2004 and 2002 would be eliminated. However, due to the various
unresolved regulatory and legislative issues (as discussed in Status of
Transition and Power Procurement Costs Recovery), SCE is no longer able to
conclude that the unamortized nuclear investment regulatory assets (as discussed
in Accounting for Generation-Related Assets and Power Procurement Costs) are
probable of recovery through the rate-making process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000 (see
further discussion in Earnings).
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
In 1999, SCE filed an application with the CPUC establishing a market value for
its hydroelectric generation-related assets at approximately $1.0 billion
(almost twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based, revenue-sharing mechanism. If
approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-indexed operations and maintenance allowance, as well as a reasonable
return on capital investment. A revenue-sharing arrangement would be activated
if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue
to ratepayers or recover 90% of any shortfalls from ratepayers. If the MOU is
implemented, SCE's hydroelectric assets will be retained through 2010 under
cost-based rates, or they may be sold to the State if a sale of SCE's
transmission assets is not completed under certain circumstances. In June 2000,
SCE credited the TCBA with the estimated excess of market value over book value
of its hydroelectric generation assets and simultaneously recorded the same
amount in the generation asset balancing account (GABA), pursuant to a CPUC
decision. This balance was to remain in GABA until final market valuation of the
hydroelectric assets. If there were a difference in the final market value, it
would have been credited to or recovered from customers through the TCBA. Due to
the various unresolved regulatory and legislative issues (as discussed in Status
of Transition and Power Procurement Costs Recovery), the GABA transaction was
reclassified back to the TCBA, and as discussed in the Earnings section, the
TCBA balance (as recalculated based on a March 27, 2001, CPUC interim decision
discussed in Rate Stabilization Proceeding) was written off as of December 31,
2000.
During 2000, SCE entered into agreements to sell the Mohave, Palo Verde and Four
Corners generation stations. The sales were pending various regulatory
approvals. Due to the shortage of electricity in California and the increasing
wholesale costs, state legislation was enacted in January 2001 barring the sale
of utility generation stations until 2006. Under the MOU, SCE would continue to
retain its generation assets through 2010.
CDWR Power Purchases
Pursuant to an emergency order signed by the Governor, the CDWR began making
emergency power purchases for SCE's customers on January 18, 2001. On February
1, 2001, AB 1X was enacted into law. The new law authorized the CDWR to enter
into contracts to purchase electric power and sell power at cost directly to
retail customers being served by SCE, and authorized the CDWR to issue revenue
bonds to finance electricity purchases. The new law directed the CPUC to
determine the amount of a CPA as a residual amount of SCE's generation-related
revenue, after deducting the cost of SCE-owned generation, QF contracts,
existing bilateral contracts and ancillary services. The new law also directed
the CPUC to determine the amount of the CPA that is allocable to the power sold
by the CDWR which will be payable to the CDWR when received by SCE. On March 7,
2001, the CPUC issued an interim order in which it held that the CDWR's
purchases are not subject to prudency review by the CPUC, and that the CPUC must
approve and impose, either as a part of existing rates or as additional rates,
rates sufficient to enable the CDWR to recover its revenue requirements.
On March 27, 2001, the CPUC issued an interim CDWR-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh for electricity (based on rates in effect on January 5,
2001), for each kWh the CDWR sells to SCE's customers. The CPUC determined that
the generation-related retail rate should be equal to the total bundled electric
rate (including the 1(cent)-per-kWh temporary surcharge adopted by the CPUC on
January 4, 2001) less certain non-generation related rates or charges. For the
period January 19 through January 31, 2001, the CPUC ordered SCE to pay the CDWR
at a rate of 6.277(cent) per kWh. The CPUC determined that the company-wide
generation-related rate component is 7.277(cent) per kWh (which will increase to
10.277(cent) per kWh for electricity delivered after March 27, 2001, due to the
3(cent)-surcharge discussed in Rate Stabilization Proceeding), for each kWh
delivered to customers beginning February 1, 2001, until more specific rates are
calculated. The CPUC ordered SCE to pay the CDWR within 45 days after the CDWR
supplies power to retail customers. Using these rates, SCE has billed customers
$196 million for energy sales made by the CDWR during the period
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Southern California Edison Company
January 19 through March 31, 2001, and has forwarded $52 million to the CDWR on
behalf of these customers as of March 31, 2001.
On April 3, 2001, the CPUC adopted the method (originally proposed in the March
27 CDWR-related order discussed above) it will use to calculate the CPA (which
was established by AB 1X) and then applied the method to calculate a
company-wide CPA rate for SCE. The CPUC used that rate to determine the CPA
revenue amount that can be used by the CDWR for issuing bonds. The CPUC stated
that its decision is narrowly focused to calculate the maximum amount of bonds
that the CDWR may issue and does not dedicate any particular revenue stream to
the CDWR. The CPUC determined that SCE's CPA rate is 1.120(cent) per kWh, which
generates annual revenue of $856 million. In its calculation of the CPA, the
CPUC disregarded all of the adjustments requested by SCE in its comments filed
on March 29 and April 2, 2001. SCE's comments included, among other things, a
forecast showing that the net effect of the rate increases (discussed in Rate
Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Liquidity Crisis) and the payments ordered to be made to CDWR
(discussed above), could result in a shortfall in the CPA calculation of $1.7
billion for SCE during 2001. SCE estimates that its future revenue will not be
sufficient to cover its retained generation, purchased-power and transition
costs. To implement the MOU described in Memorandum of Understanding with CDWR,
the CPUC will need to modify the calculation methods and provide reasonable
assurance that SCE will be able to recover its ongoing costs.
SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that it
considers to be reasonably priced, leaving the ISO to purchase in the short-term
market the additional power necessary to meet system requirements. The ISO, in
turn, takes the position that it will charge SCE for the costs of power it
purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it can not assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions. In any event, SCE takes the position that it is not responsible
for purchases of power by the CDWR or the ISO on or after January 18, 2001, the
day after the Governor signed the order authorizing the CDWR to begin purchasing
power for utility customers. SCE cannot predict the outcome of any of these
proceedings or issues. The recently executed MOU states that the CDWR will
assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the
extent those needs are not met by generation sources owned by or under contract
to SCE (SCE's net short position). SCE will resume buying power for its net
short position after 2002. The MOU calls for the CPUC to adopt cost recovery
mechanisms to make it financially practicable for SCE to reassume this
responsibility.
Status of Transition and Power Procurement Costs Recovery
SCE's transition costs include power purchases from QF contracts (which are the
direct result of prior legislative and regulatory mandates), recovery of certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the recovery
of income tax benefits previously flowed through to customers, postretirement
benefit transition costs, accelerated recovery of investment in San Onofre Units
2 and 3 and the Palo Verde units, and certain other costs. Transition costs
related to power-purchase contracts are being recovered through the terms of
each contract. Most of the remaining transition costs may be recovered through
the end of the transition period (not later than March 31, 2002). Although the
MOU provides for, among other things, SCE to be entitled to sufficient revenue
to cover its costs from January 2001 associated with retained generation and
existing power contracts, the implementation of the MOU requires the CPUC to
modify
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
various decisions (discussed in Rate Stabilization Proceeding). Until the
various regulatory and legislative actions necessary to implement the MOU, or
other actions that make such recovery probable are taken, SCE is not able to
conclude that the regulatory assets and liabilities related to purchased-power
settlements, the unamortized loss on SCE's generating plant sales in 1998, and
various other regulatory assets and liabilities (including income taxes
previously flowed through to customers) related to certain generating assets are
probable of recovery through the rate-making process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000 (see
further discussion in Earnings).
During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: revenue from the sale or valuation of
generation assets in excess of book values, net market revenue from the sale of
SCE-controlled generation into the ISO and PX markets, and competition
transition charge (CTC) revenue. However, due to events discussed elsewhere in
this report, revenue from the sale or valuation of generation assets in excess
of book values (state legislation enacted in January 2001 bars the sale of SCE's
remaining generation assets until 2006) and from the sale of SCE-controlled
generation into the ISO and PX markets (see discussion in Generation and Power
Procurement) are no longer available to SCE. During 1998, SCE sold all of its
gas-fueled generation plants for $1.2 billion, over $500 million more than the
combined book value. Net proceeds of the sales were used to reduce transition
costs, which otherwise were expected to be collected through the TCBA mechanism.
Net market revenue from sales of power and capacity from SCE-controlled
generation sources was also applied to transition cost recovery. Increases in
market prices for electricity affected SCE in two fundamental ways prior to the
CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue decreased
because there was less or no residual revenue from frozen rates due to higher
cost PX and ISO power purchases. Second, transition costs decreased because
there was increased net market revenue due to sales from SCE-controlled
generation sources to the PX at higher prices (accumulated as an overcollection
in the coal and hydroelectric balancing accounts). Although the second effect
mitigated the first to some extent, the overall impact on transition cost
recovery was negative because SCE purchased more power than it sold to the PX.
In addition, higher market prices for electricity adversely affected SCE's
ability to recover non-transition costs during the rate freeze period. Since May
2000, market prices for electricity were extremely high and there was
insufficient revenue from customers under the frozen rates to cover all costs of
providing service during that period, and therefore there was no positive
residual CTC revenue transferred into the TCBA.
CTC revenue is determined residually (i.e., CTC revenue is the residual amount
remaining from monthly gross customer revenue under the rate freeze after
subtracting the revenue requirements for transmission, distribution, nuclear
decommissioning and public benefit programs, and ISO payments and power
purchases from the PX and ISO). The CTC applies to all customers who are using
or begin using utility services on or after the CPUC's 1995 restructuring
decision date. Residual CTC revenue is calculated through the TRA mechanism.
Under CPUC decisions in existence prior to March 27, 2001, positive residual CTC
revenue (TRA overcollections) was transferred to the TCBA monthly; TRA
undercollections were to remain in the TRA until they were offset by
overcollections, or the rate freeze ended, whichever came first. Pursuant to the
March 27, 2001, rate stabilization decision, both positive and negative residual
CTC revenue is transferred to the TCBA on a monthly basis, retroactive to
January 1, 1998 (see further discussion in Rate Stabilization Proceeding).
Upon recalculating the TCBA balance based on the new decision, SCE has received
positive residual CTC revenue (TRA overcollections) of $4.7 billion to recover
its transition costs from the beginning of the rate freeze (January 1, 1998)
through April 2000. As a result of sustained higher market prices, SCE
experienced the first month in which costs exceeded revenue in May 2000. Since
then, SCE's costs to provide power have continued to exceed revenue from frozen
rates and as a result, the cumulative positive residual CTC revenue flowing into
the TCBA mechanism has been reduced from $4.7 billion to $1.4 billion as of
December 31, 2000. The cumulative TCBA undercollection (as recalculated) is $2.9
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Southern California Edison Company
billion as of December 31, 2000. A summary of the components of this cumulative
undercollection is as follows:
In millions Transition costs recorded in the TCBA:
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QF and interutility costs $3,561
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 577
Other transition costs 634
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Total transition costs 7,862
Revenue available to recover transition costs (4,984)
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Unrecovered transition costs $2,878
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Unless the regulatory and legislative actions required to implement the MOU, or
other actions that make such recovery probable are taken, SCE is not able to
conclude that the recalculated TCBA net undercollection is probable of recovery
through the rate-making process. As a result, the $2.9 billion TCBA net
undercollection was written off as a charge to earnings as of December 31, 2000
(see further discussion in Earnings). In its interim rate stabilization decision
of March 27, 2001, the CPUC denied a December motion by SCE to end the rate
freeze, and stated that it will not end until recovery of all specified
transition costs (including TCBA undercollections as recalculated) or March 31,
2002. For more details on the matters discussed above, see Rate Stabilization
Proceeding.
Litigation
In November 2000, SCE filed a lawsuit against the CPUC in federal court in
California, seeking a ruling that SCE is entitled to full recovery of its past
electricity procurement costs in accordance with the tariffs filed with the
FERC. The effect of such a ruling would be to overturn the prior decisions of
the CPUC restricting recovery of TRA undercollections. In January 2001, the
court denied the CPUC's motion to dismiss the action and also denied SCE's
motion for summary judgment without prejudice. In February 2001, the court
denied SCE's motion for a preliminary injunction ordering the CPUC to institute
rates sufficient to enable SCE to recover its past procurement costs, subject to
refund. The court granted, in part, SCE's additional motion to specify certain
material facts without substantial controversy, but denied the remainder of the
motion and declined to declare at that time that SCE is entitled to recover the
amount of its undercollected procurement costs. In March 2001, the court
directed the parties to be prepared for trial on July 31, 2001. As discussed in
the Memorandum of Understanding with the CDWR, after the other elements of the
MOU are implemented, SCE will enter into a settlement of or dismiss its lawsuit
against the CPUC seeking recovery of past undercollected costs. The settlement
or dismissal will include related claims against the State of California or any
of its agencies, or against the federal government. SCE cannot predict whether
or when a favorable final judgment or other resolution would be obtained in this
legal action, if it were to proceed to trial.
In December 2000, a first amended complaint to a class action securities lawsuit
(originally filed in October 2000) was filed in federal district court in Los
Angeles against SCE and Edison International. On March 5, 2001, a second amended
complaint was filed that alleges that SCE and Edison International are engaging
in fraud by over-reporting and improperly accounting for the TRA
undercollections. The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock beginning
June 1, 2000, and continuing until such time as TRA-related undercollections are
recorded as a loss on SCE's income statement. The response to the second amended
complaint was due April 2, 2001. The response has been deferred pending
resolution of motions to consolidate this lawsuit with the March 15, 2001,
lawsuit discussed below. SCE believes that its current and past accounting for
the TRA undercollections and related items, as described above, is appropriate
and in accordance with accounting principles generally accepted in the United
States.
17
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
On March 15, 2001, a purported class action lawsuit was filed in federal
district court in Los Angeles against Edison International and SCE and certain
of their officers. The complaint alleges that the defendants engaged in
securities fraud by misrepresenting and/or failing to disclose material facts
concerning the financial condition of Edison International and SCE, including
that the defendants allegedly over-reported income and improperly accounted for
the TRA undercollections. The complaint is supposedly filed on behalf of a class
of persons who purchased all publicly traded securities of Edison International
between May 12, 2000, and December 22, 2000. Pursuant to an agreement with
Edison International and SCE, this lawsuit is expected to be consolidated with
the October 20, 2000, lawsuit discussed above, pending the court's approval.
In addition to the two lawsuits filed against SCE and discussed above, as of
April 13, 2001, 17 additional lawsuits have been filed against SCE by QFs. The
lawsuits have been filed by various parties, including geothermal or wind energy
suppliers or owners of cogeneration projects. The lawsuits are seeking payments
of at least $420 million for energy and capacity supplied to SCE under QF
contracts, and in some cases for damages as well. Many of these QF lawsuits also
seek an order allowing the suppliers to stop providing power to SCE and sell the
power to other purchasers. SCE is seeking coordination of all of the QF-related
lawsuits that have commenced in various California courts. On April 13, 2001, an
order was issued assigning all pending cases to a coordination motion judge and
setting a hearing on SCE's coordination petition by May 30, 2001. SCE cannot
predict the outcome of any of these matters.
Rate Stabilization Proceeding
In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. On December 20,
2000, SCE filed an amended rate stabilization plan application, stating that the
CPUC must recognize that the statutory rate freeze is now over in accordance
with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001. SCE's plan
included a trigger mechanism allowing for rate increases of 5% every six months
if SCE's TRA undercollection balance exceeds $1 billion. Hearings were held in
late December 2000.
On January 4, 2001, the CPUC issued an interim decision that authorized SCE to
establish an interim surcharge of 1(cent) per kWh for 90 days, subject to refund
(see additional discussion below). The revenue from the surcharge is being
tracked through a balancing account and applied to ongoing power procurement
costs. The surcharge resulted in rate increases, on average, of approximately 7%
to 25%, depending on the class of customer. As noted in the decision, the 90-day
period allowed independent auditors engaged by the CPUC to perform a
comprehensive review of SCE's financial position, as well as that of Edison
International and other affiliates.
On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the CPUC in public filings about
SCE's financial condition. The audit report covers, among other things, cash
needs, credit relationships, accounting mechanisms to track stranded cost
recovery, the flow of funds between SCE and Edison International, and earnings
of SCE's California affiliates. On April 3, 2001, the CPUC adopted an order
instituting investigation (originally proposed on March 15, 2001). The order
reopens past CPUC decisions authorizing the utilities to form holding companies
and initiates an investigation into: whether the holding companies violated
requirements to give priority to the capital needs of their respective utility
subsidiaries; whether ring-fencing actions by Edison International and PG&E
Corporation and their respective nonutility affiliates also violated the
requirements to give priority to the capital needs of their utility
subsidiaries; whether the payment of dividends by the utilities violated
requirements that the utilities maintain dividend policies as though they were
comparable stand-alone utility companies; any additional suspected violations of
laws or CPUC rules and decisions; and whether additional rules, conditions, or
other changes to the holding company decisions are necessary. An assigned
commissioner's ruling on March 29, 2001, required SCE to respond within 10 days
to document
18
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Southern California Edison Company
requests and questions that are substantially identical to those included in the
March 15 proposed order instituting investigation. The MOU calls for the CPUC to
adopt a decision clarifying that the first priority condition in SCE's holding
company decision refers to equity investment, not working capital for operating
costs. SCE cannot provide assurance that the CPUC will adopt such a decision, or
predict what effects any investigation or any subsequent actions by the CPUC may
have on SCE.
In its interim rate stabilization order adopted on March 27, 2001, the CPUC
granted SCE a rate increase in the form of a 3(cent)-per-kWh surcharge applied
only to electric power costs, effective immediately, and affirmed that the
1(cent) interim surcharge granted on January 4, 2001, is now permanent. Although
the 3(cent)-increase was authorized immediately, the surcharge will not be
collected in rates until the CPUC establishes an appropriate rate design, which
is not expected to occur until May 2001. SCE has asked the CPUC to immediately
adopt an interim rate increase that would allow the rate change to go into
effect sooner. The CPUC also ordered that the 3(cent)-surcharge be added to the
rate paid to the CDWR pursuant to the interim CDWR-related decision (see CDWR
Power Purchases).
Also, in the interim order, the CPUC granted a petition previously filed by The
Utility Reform Network and directed that the balance in SCE's TRA, whether over-
or undercollected, be transferred on a monthly basis to the TCBA, retroactive to
January 1, 1998. Previous rules called only for TRA overcollections (residual
CTC revenue) to be transferred to the TCBA. The CPUC also ordered SCE to
transfer the coal and hydroelectric balancing account overcollections to the TRA
on a monthly basis before any transfer of residual CTC revenue to the TCBA,
retroactive to January 1, 1998. Previous rules called for overcollections in
these two balancing accounts to be transferred directly to the TCBA on an annual
basis (see further discussion of the recalculation of the TCBA in Status of
Transition and Power Procurement Costs Recovery). SCE believes this interim
order attempts to retroactively transform power purchase costs in the TRA into
transition costs in the TCBA. However, the CPUC characterized the accounting
changes as merely reducing the prior residual CTC revenue recorded in the TCBA,
thus only affecting the amount of transition cost recovery achieved to date.
Based upon the transfer of balances into the TCBA, the CPUC denied SCE's
December 2000 filing to have the current rate freeze end, and stated that it
will not end until recovery of all specified transition costs or March 31, 2002;
and that balances in the TRA cannot be recovered after the end of the rate
freeze. The CPUC also said that it would monitor the balances remaining in the
TCBA and consider how to address remaining balances in the ongoing proceeding.
If the CPUC does not modify this decision in a manner consistent with the MOU,
SCE intends to challenge this decision through all appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 27,
2001, order, it has allocated the revenue from the increase entirely to future
purchased-power costs without addressing SCE's past undercollections for the
costs of purchased power. The CPUC's decisions do not assure that SCE will be
able to meet its ongoing obligations or repay past due obligations. By ordering
immediate payments to the CDWR and QFs, the CPUC aggravated SCE's cash flow and
liquidity problems. Additionally, the CPUC expressed the view that AB 1X
continues the utilities' obligations to serve their customers, and stated that
it cannot assume that the CDWR will purchase all the electricity needed above
what the utilities either generate or have under contract (the net short
position) and cannot order the CDWR to do so. This could result in additional
purchased power costs with no allowed means of recovery. To implement the MOU,
it will be necessary for the CPUC to modify or rescind these decisions. SCE
cannot provide any assurance that the CPUC will do so.
Accounting for Generation-Related Assets and Power Procurement Costs
In 1997, SCE discontinued application of accounting principles for
rate-regulated enterprises for its generation assets. At that time, SCE did not
write off any of its generation-related assets, including related regulatory
assets, because the electric utility industry restructuring plan made probable
their recovery through a nonbypassable charge to distribution customers.
19
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
During the second quarter of 1998, in accordance with asset impairment
accounting standards, SCE reduced its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recorded a regulatory asset on its balance
sheet for the same amount. For this impairment assessment, the fair value of the
investment was calculated by discounting expected future net cash flows. This
reclassification had no effect on SCE's results of operations.
The implementation of the MOU requires various regulatory and legislative
actions to be taken in the future. Unless those actions or other actions that
make such recovery probable are taken, which would include modifying or
reversing recent CPUC decisions that impair recovery of SCE's power procurement
and transition costs, SCE is not able to conclude that its $2.9 billion TCBA
undercollection (as redefined in the March 27 decisions) and $1.3 billion (book
value) of its generation-related regulatory assets and liabilities to be
amortized into the TCBA, are probable of recovery through the rate-making
process. As a result, accounting principles generally accepted in the United
States require that the balances in the accounts be written off as a charge to
earnings as of December 31, 2000 (see Earnings).
As discussed below, an MOU has been negotiated with representatives of the
Governor as a step to resolving the energy crisis. The regulatory and
legislative actions set forth in the MOU, if implemented, are expected to result
in a rate-making mechanism that would make recovery of these regulatory assets
probable. If and when those actions, or other actions that make such recovery
probable are taken, and the necessary rate-making mechanism is adopted, the
regulatory assets would be restored to the balance sheet, with a corresponding
increase to earnings.
Memorandum of Understanding with the CDWR
On April 9, 2001, SCE signed an MOU with the CDWR regarding the California
energy crisis and its effects on SCE. The Governor of California and his
representatives participated in the negotiation of the MOU, and the Governor
endorsed implementation of all the elements of the MOU. The MOU sets forth a
comprehensive plan calling for legislation, regulatory action and definitive
agreements to resolve important aspects of the energy crisis, and which, if
implemented, is expected to help restore SCE's creditworthiness and liquidity.
Key elements of the MOU include:
o SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate book
value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, SCE's hydroelectric assets
and other rights may be sold to the state in their place. SCE will use the
proceeds of the sale in excess of book value to reduce its undercollected
costs and retire outstanding debt incurred in financing those costs. SCE
will agree to operate and maintain the transmission assets for at least
three years, for a fee to be negotiated.
o Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the
undercollected amount over the expected gain on sale of SCE's transmission
assets, as well as certain other costs. Such securitization will occur as
soon as reasonably practicable after passage of the necessary legislation
and satisfaction of other conditions of the MOU. The second dedicated rate
component would not be securitized and would not appear in rates unless the
transmission sale failed to close within a two-year period. The second
component is designed to allow SCE to obtain bridge financing of the
portion of the undercollection intended to be recovered through the gain on
the transmission sale.
o SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenue sufficient to cover its costs from January 1, 2001, associated with
the retained generation assets and existing power contracts. The MOU calls
for
20
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Southern California Edison Company
the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment grade credit rating.
o The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are
referred to as SCE's net short position.) SCE will resume procurement of
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.
o SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2010. Through the same date, a
rate-making capital structure for SCE will not be established with
different proportions of common equity or preferred equity to debt than set
forth in current authorizations. These measures are intended to enable SCE
to achieve and maintain an investment grade credit rating.
o Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a lesser
amount approved by the CPUC. The equity component of the investments will
be funded from SCE's retained earnings or, if necessary, from equity
investments by Edison International.
o An affiliate of Edison International will execute a contract with the CDWR
or another state agency for the provision of power to the state at
cost-based rates for 10 years from a power project currently under
development. The Edison International affiliate will use all commercially
reasonable efforts to place the first phase of the project into service
before the end of summer 2001.
o SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be assigned
to nonprofit entities or certain governmental agencies. SCE will be
permitted to continue utility uses of the subject lands.
o After the other elements of the MOU are implemented, SCE will enter into a
settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.
The sale of SCE's transmission system and other elements of the MOU must be
approved by the FERC. SCE and the CDWR committed in the MOU to proceed in good
faith to sponsor and support the required legislation and to negotiate in good
faith the necessary definitive agreements. The MOU may be terminated by either
SCE or the CDWR if required legislation is not adopted and definitive agreements
executed by August 15, 2001, or if the CPUC does not adopt required implementing
decisions within 60 days after the MOU was signed, or if certain other adverse
changes occur. SCE cannot provide assurance that all the required legislation
will be enacted, regulatory actions taken, and definitive agreements executed
before the applicable deadlines.
Distribution
Revenue related to distribution operations is determined through a
performance-based rate-making (PBR) mechanism and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return on investment. The
distribution PBR will extend through December 2001. Key elements of the
distribution PBR include: distribution rates indexed for inflation based on the
Consumer Price Index less a productivity factor; adjustments for cost changes
that are not within SCE's control; a cost-of-capital trigger mechanism based on
changes in a utility bond index; standards for customer satisfaction; service
reliability and safety;
21
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
and a net revenue-sharing mechanism that determines how customers and
shareholders will share gains and losses from distribution operations.
Transmission
Transmission revenue is determined through FERC-authorized rates and is subject
to refund.
Wholesale Electricity Markets
In October 2000, SCE filed a joint petition urging the FERC to immediately find
the California wholesale electricity market to be not workably competitive;
immediately impose a cap on the price for energy and ancillary services; and
institute further expedited proceedings regarding the market failure, mitigation
of market power, structural solutions and responsibility for refunds. On
December 15, 2000, the FERC released a final order containing remedies and other
actions in response to the problems in the California electricity market. The
order, among other things, eliminated the requirement for California utilities
to buy and sell power exclusively through the ISO and PX; created a benchmark
price for wholesale bilateral power contracts; created penalties for
under-scheduling power loads; provided for an independent governing board for
the ISO; and established a breakpoint of $150/MWh so that bids below $150 may
clear at a single market-clearing price at or below $150/MWh and bids above $150
will be paid as bid. On December 18, 2000, SCE filed with the FERC an emergency
request for rehearing and expedited action seeking reconsideration of the
December 15 order. On January 12, 2001, the FERC issued an order granting
rehearing for the purpose of further consideration. The PX did not immediately
implement the $150/MWh breakpoint and on February 26, 2001, made a compliance
filing with the FERC, which requested the FERC's guidance on an acceptable
recalculation methodology. On April 6, 2001, the FERC issued an order providing
guidance to the PX, which should reduce SCE's energy costs owed to the PX for
the month of January 2001.
On December 13, 2000, the ISO announced that generators of electricity were
refusing to sell into the California market due to concerns about the financial
stability of SCE and Pacific Gas and Electric Company. In response to this
announcement, on December 14, 2000, the United States Secretary of Energy issued
an order requiring power companies to make arrangements to generate and deliver
electricity as requested by the ISO after the ISO certifies that it has been
unable to acquire adequate supplies of electricity in the market. After being
renewed multiple times, the order expired on February 6, 2001. However, on
February 7, 2001, a federal court judge issued a temporary restraining order
requiring power suppliers to sell to the California grid. On March 21, 2001, a
federal court judge ordered one of the power suppliers to continue to sell power
to the California grid. Three other power suppliers have signed an agreement
with the judge voluntarily agreeing to continue to sell power to the grid while
awaiting a review of the issue by the FERC. On April 6, 2001, the United States
Court of Appeals issued a stay order, suspending the lower court's March 21
order until a final appeals ruling can be issued.
On December 26, 2000, SCE filed an emergency petition in the federal Court of
Appeals challenging the FERC order and seeking a writ of mandamus requiring the
FERC to immediately establish cost-based wholesale rates. On January 5, 2001,
the court denied SCE's petition. The effect of the denial is to leave in place
the FERC's market controls that have allowed wholesale prices to climb to
current levels. SCE's petition for rehearing remains pending. SCE cannot predict
what action the FERC may take. SCE is considering the possibility of judicial
appeals and other actions.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69
million or submit cost-of-service information to the FERC to justify their
prices above $273/MWh during ISO Stage 3 emergencies in January 2001. SCE will
oppose the order as inadequate, particularly because the FERC is unwilling to
exercise any control over the sellers' exercise of market power during periods
other than Stage 3 emergencies. On March 16, 2001, the FERC ordered six
wholesale sellers of energy to refund an additional $55 million or submit
cost-of-service information to the FERC to justify their prices above
22
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Southern California Edison Company
$430/MWh during ISO Stage 3 emergencies in February 2001. A Stage 3 emergency
refers to 1.5% or less in reserve power, which could trigger rotating blackouts
in some neighborhoods.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
As further discussed in Note 12 to the Consolidated Financial Statements, SCE
records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE's recorded estimated minimum liability to remediate its 44
identified sites is $114 million. SCE believes that, due to uncertainties
inherent in the estimation process, it is reasonably possible that cleanup costs
could exceed its recorded liability by up to $272 million. In 1998, SCE sold all
of its gas-fueled power plants but has retained some liability associated with
the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism, which is discussed in Note 12. SCE has recorded a regulatory asset of
$75 million for its estimated minimum environmental-cleanup costs expected to be
recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information. As a result, no reasonable estimate of cleanup
costs can be made for these sites. SCE expects to clean up its identified sites
over a period of up to 30 years. Remediation costs in each of the next several
years are expected to range from $5 million to $15 million. Recorded costs for
2000 were $13 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
The Clean Air Act requires power producers to have emissions allowances to emit
sulfur dioxide. Power companies receive emissions allowances from the federal
government and may bank or sell excess allowances. SCE expects to have excess
allowances under Phase II of the Clean Air Act (2000 and later). A study was
undertaken to determine the specific impact of air contaminant emissions from
the Mohave Generating Station on visibility in Grand Canyon National Park. The
final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. In June
1999, the Environmental Protection Agency (EPA) issued an advanced notice of
proposed rulemaking regarding assessment of visibility impairment at the Grand
Canyon. SCE filed comments on the proposed rulemaking in November 1999. In 1998,
several environmental groups filed suit against the co-owners of the Mohave
station regarding alleged violations of emissions limits. In order to accelerate
resolution of key environmental issues regarding the plant, the parties filed,
in concurrence with SCE and the other station owners, a consent decree, which
was approved by the court in December 1999. In a letter to SCE, the EPA has
expressed its belief that the controls provided in the consent decree will
likely resolve the potential Clean Air Act visibility concerns. The EPA is
considering incorporating the decree into the visibility provisions of its
Federal Implementation Plan for Nevada.
23
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
SCE's projected environmental capital expenditures are $1.2 billion for the
2001-2005 period, mainly for undergrounding certain transmission and
distribution lines.
San Onofre Nuclear Generating Station
On February 3, 2001, SCE's San Onofre Unit 3 experienced a fire due to an
electrical fault in the non-nuclear portion of the plant. The turbine rotors,
bearings and other components of the turbine generator system were damaged
extensively. SCE expects that Unit 3 will return to service sometime in mid-June
2001. SCE anticipates that its lost revenue under the currently effective San
Onofre rate-recovery plan (discussed in the Generation and Power Procurement
section of Regulatory Environment) will be approximately $100 million.
The San Onofre Units 2 and 3 steam generators' design allows for the removal of
up to 10% of the tubes before the rated capacity of the unit must be reduced.
Increased tube degradation was found during routine inspections in 1997. To
date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from
service. A decreasing (favorable) trend in degradation has been observed in more
recent inspections.
Accounting Changes
On January 1, 2001, SCE adopted a new accounting standard for derivative
instruments and hedging activities. The new standard requires all derivatives be
recognized on the balance sheet at fair value. Gains or losses from changes in
fair value would be recognized in earnings in the period of change unless the
derivative is designated as a hedging instrument. Gains or losses from hedges of
a forecasted transaction or foreign currency exposure would be recorded as a
separate component of shareholders' equity under the caption "Accumulated other
comprehensive income." Gains or losses from hedges of a recognized asset or
liability or a firm commitment would be reflected in earnings for the
ineffective portion of the hedge. SCE's derivatives qualify for hedge accounting
under the new standard. On the implementation date, SCE recorded its interest
rate swap agreement (terminated January 5, 2001), and its block forward power
purchase contracts (seized by the State of California on February 2, 2001) at
fair value on its balance sheet. SCE does not anticipate any earnings impact
from its derivatives, since it expects that any market price changes will be
recovered in rates.
Forward-looking Information
In the preceding Management's Discussion and Analysis of Results of Operations
and Financial Condition and elsewhere in this annual report, the words
estimates, expects, anticipates, believes, and other similar expressions are
intended to identify forward-looking information that involves risks and
uncertainties. Actual results or outcomes could differ materially as a result of
such important factors as implementation (or non-implementation) of the MOU as
described above; the outcome of negotiations for solutions to SCE's liquidity
problems; further actions by state and federal regulatory bodies setting rates,
adopting or modifying cost recovery, accounting or rate-setting mechanisms and
implementing the restructuring of the electric utility industry; actions by
lenders, investors and creditors in response to SCE's suspension of payments for
debt service and purchased power, including the possible filing of an
involuntary bankruptcy petition against SCE; the effects, unfavorable
interpretations and applications of new or existing laws and regulations
relating to restructuring, taxes and other matters; the effects of increased
competition in energy-related businesses; changes in prices of electricity and
fuel costs; the actions of securities rating agencies; the availability of
credit, including SCE's ability to regain an investment grade credit rating and
re-enter the credit markets; changes in financial market conditions; the amount
of revenue available to both transition and non-transition costs; new or
increased environmental liabilities; the financial viability of new businesses,
such as telecommunications; weather conditions; and other unforeseen events.
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Consolidated Statements of Income (Loss) Southern California Edison Company
In thousands Year ended December 31, 2000 1999 1998
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Operating revenue $ 7,869,950 $ 7,547,834 $ 7,499,519
- -------------------------------------------------------------------------------------------------------------------
Fuel 194,961 214,972 323,716
Purchased power-- contracts 2,357,336 2,419,147 2,625,900
Purchased power-- PX/ISO-- net 2,329,276 770,574 636,343
Provisions for regulatory adjustment clauses-- net 2,301,268 (762,653) (472,519)
Other operation and maintenance 1,771,792 1,933,217 1,891,210
Depreciation, decommissioning and amortization 1,472,872 1,547,738 1,545,735
Income taxes (1,006,825) 451,247 445,642
Property and other taxes 125,720 121,628 128,402
Net gain on sale of utility plant (24,602) (3,035) (542,608)
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 9,521,798 6,692,835 6,581,821
- -------------------------------------------------------------------------------------------------------------------
Operating income (loss) (1,651,848) 854,999 917,698
Interest and dividend income 172,736 69,389 66,725
Other nonoperating income 118,064 162,317 129,046
Interest expense-- net of amounts capitalized (571,760) (483,241) (484,788)
Other nonoperating deductions (110,163) (107,285) (116,845)
Taxes on other income and deductions 14,627 13,242 3,286
- -------------------------------------------------------------------------------------------------------------------
Net income (loss) (2,028,344) 509,421 515,122
Dividends on preferred stock 21,443 25,889 24,632
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Net income (loss) available for common stock $ (2,049,787) $ 483,532 $ 490,490
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Consolidated Statements of Comprehensive Income (Loss)
In thousands Year ended December 31, 2000 1999 1998
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Net income (loss) $ (2,028,344) $ 509,421 $ 515,122
Unrealized gain on securities - net 2,919 28,009 9,275
Reclassification adjustment for gains included in net income (24,470) (45,920) (17,836)
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Comprehensive income (loss) $ (2,049,895) $ 491,510 $ 506,561
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The accompanying notes are an integral part of these financial statements.
25
Consolidated Balance Sheets
In thousands December 31, 2000 1999
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ASSETS
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Utility plant, at original cost:
Transmission and distribution $13,128,755 $12,439,059
Generation 1,745,505 1,717,676
Accumulated provision for depreciation
and decommissioning (7,834,201) (7,520,036)
Construction work in progress 635,572 562,651
Nuclear fuel, at amortized cost 143,082 132,197
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Total utility plant 7,818,713 7,331,547
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Nonutility property-- less accumulated provision
for depreciation of $11,008 and $6,797
at respective dates 102,223 103,644
Nuclear decommissioning trusts 2,504,990 2,508,904
Other investments 89,570 160,241
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Total investments and other assets 2,696,783 2,772,789
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents 583,159 26,046
Receivables, less allowances of $23,220 and $24,665
for uncollectible accounts at respective dates 919,045 579,859
Accrued unbilled revenue 376,873 433,802
Fuel inventory 11,720 49,989
Materials and supplies, at average cost 131,651 122,866
Accumulated deferred income taxes-- net 544,561 188,143
Prepayments and other current assets 124,736 111,151
- -------------------------------------------------------------------------------------------------------------------
Total current assets 2,691,745 1,511,856
- -------------------------------------------------------------------------------------------------------------------
Regulatory assets-- net 2,390,124 5,555,216
Other deferred charges 368,731 485,898
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 2,758,855 6,041,114
- -------------------------------------------------------------------------------------------------------------------
Total assets $15,966,096 $ 17,657,306
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
26
- -------------------------------------------------------------------------------------------------------------------
Southern California Edison Company
In thousands, except share amounts December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- -------------------------------------------------------------------------------------------------------------------
Common shareholder's equity:
Common stock (434,888,104 shares outstanding
at each date) $2,168,054 $ 2,168,054
Additional paid-in capital 334,030 335,038
Accumulated other comprehensive income -- 21,551
Retained earnings (deficit) (1,721,599) 608,453
- -------------------------------------------------------------------------------------------------------------------
780,485 3,133,096
Preferred stock:
Not subject to mandatory redemption 128,755 128,755
Subject to mandatory redemption 255,700 255,700
Long-term debt 5,631,308 5,136,681
- -------------------------------------------------------------------------------------------------------------------
Total capitalization 6,796,248 8,654,232
- -------------------------------------------------------------------------------------------------------------------
Short-term debt 1,451,071 795,988
Current portion of long-term debt 646,300 571,300
Accounts payable 1,055,483 573,919
Accrued taxes 535,517 500,709
Accrued interest 96,053 82,554
Dividends payable 662 94,407
Regulatory liabilities-- net 195,047 100,907
Deferred unbilled revenue 249,949 300,339
Other current liabilities 1,154,834 1,114,834
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 5,384,916 4,134,957
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 2,009,290 2,938,661
Accumulated deferred investment tax credits 163,952 205,197
Customer advances and other deferred credits 754,741 823,992
Power purchase contracts 466,231 563,459
Accumulated provision for pensions and benefits 296,380 233,003
Other long-term liabilities 93,978 103,470
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 3,784,572 4,867,782
- -------------------------------------------------------------------------------------------------------------------
Minority interest 360 335
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2, 3, 11 and 12)
Total capitalization and liabilities $15,966,096 $ 17,657,306
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
27
Consolidated Statements of Cash Flows
In thousands Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net income (loss) $(2,028,344) $ 509,421 $ 515,122
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning and amortization 1,472,872 1,547,738 1,545,735
Other amortization 96,958 95,060 89,323
Deferred income taxes and investment tax credits (927,607) 177,599 (94,504)
Regulatory balancing accounts-- long-term 1,758,594 (1,353,570) (361,403)
Regulatory asset related to the sale of
generating plants 48 179 (220,232)
Net gain on sale of generating plants (14,287) (938) (564,623)
Net gain on sale of marketable securities (41,161) (77,241) (30,002)
Other assets 44,369 (62,328) (45,191)
Other liabilities 850 17,315 40,263
Changes in working capital:
Receivables (282,257) 98,969 (206,242)
Regulatory balancing accounts-- short-term 96,882 363,071 (94,067)
Fuel inventory, materials and supplies 29,484 (5,297) 23,481
Prepayments and other current assets (13,585) (19,159) 1,106
Accrued interest and taxes 48,307 (185,520) 174,107
Accounts payable and other current liabilities 588,154 352,489 205,256
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 829,277 1,457,788 978,129
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 1,759,708 490,840 --
Long-term debt repaid (524,700) (362,872) (776,030)
Bonds repurchased and funds held in trust (439,855) -- --
Preferred stocks redeemed -- -- (74,300)
Rate reduction notes repaid (246,300) (246,300) (251,591)
Nuclear fuel financing-- net 8,651 (37,287) 16,244
Short-term debt financing-- net 655,033 326,423 147,537
Dividends paid (394,718) (685,731) (1,129,812)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 817,819 (514,927) (2,067,952)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (1,095,633) (985,623) (860,837)
Proceeds from sale of generating plants 18,880 -- 1,203,039
Funding of nuclear decommissioning trusts (69,428) (115,937) (162,925)
Proceeds from sales of marketable securities 41,161 84,306 32,127
Investments in other assets 11,607 15,870 (3,952)
Other 3,430 3,069 1,599
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by investing activities (1,089,983) (998,315) 209,051
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents 557,113 (55,454) (880,772)
Cash and equivalents, beginning of year 26,046 81,500 962,272
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of year $ 583,159 $ 26,046 $ 81,500
- -------------------------------------------------------------------------------------------------------------------
Cash payments for interest and taxes (in millions):
Interest-- net of amounts capitalized $ 303 $ 287 $ 264
Taxes 306 433 405
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
28
- --------------------------------------------------------------------------------------------------------------------
Consolidated Statement of Changes in Common Southern California Edison Company
Shareholder's Equity
Accumulated Total
Additional Other Retained Common
Common Paid-in Comprehensive Earnings Shareholder's
In thousands Stock Capital Income (deficit) Equity
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 $2,168,054 $ 334,031 $ 48,023 $ 1,407,834 $3,957,942
- --------------------------------------------------------------------------------------------------------------------
Net income 515,122 515,122
Unrealized gain on securities 13,784 13,784
Tax effect (4,509) (4,509)
Reclassified adjustment for gain
included in net income (30,002) (30,002)
Tax effect 12,166 12,166
Dividends declared on common stock (1,100,777) (1,100,777)
Dividends declared on preferred stock (24,632) (24,632)
Stock option appreciation (3,922) (3,922)
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $2,168,054 $ 334,031 $ 39,462 $ 793,625 $3,335,172
- --------------------------------------------------------------------------------------------------------------------
Net income 509,421 509,421
Unrealized gain on securities 45,813 45,813
Tax effect (17,804) (17,804)
Reclassified adjustment for gain
included in net income (77,241) (77,241)
Tax effect 31,321 31,321
Dividends declared on common stock (665,884) (665,884)
Dividends declared on preferred stock (25,889) (25,889)
Stock option appreciation (2,820) (2,820)
Capital stock expense 1,007 1,007
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $2,168,054 $ 335,038 $ 21,551 $ 608,453 $3,133,096
- --------------------------------------------------------------------------------------------------------------------
Net income (loss) (2,028,344) (2,028,344)
Unrealized gain on securities 8,027 8,027
Tax effect (5,108) (5,108)
Reclassified adjustment for gain
included in net income (41,161) (41,161)
Tax effect 16,691 16,691
Dividends declared on common stock (278,522) (278,522)
Dividends declared on preferred stock (21,443) (21,443)
Stock option appreciation (1,743) (1,743)
Capital stock expense and other (1,008) (1,008)
- --------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 $2,168,054 $ 334,030 $ -- $ (1,721,599) $ 780,485
- --------------------------------------------------------------------------------------------------------------------
Authorized common stock is 560 million shares with no par value.
The accompanying notes are an integral part of these financial statements.
29
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Nature of Operations
Southern California Edison Company (SCE) is a rate-regulated electric utility
which supplies electric energy for its 4.3 million customers in central, coastal
and Southern California. SCE operates in a highly regulated environment in which
it has an obligation to deliver electric service to customers in return for an
exclusive franchise within its service territory. In 1996, state lawmakers and
the California Public Utilities Commission (CPUC) initiated the electric
industry restructuring process. SCE was directed by the CPUC to divest the bulk
of its generation portfolio. Today, those generating plants are owned by
independent power companies. Along with electric industry restructuring, a
multi-year freeze on the rates that SCE could charge its customers was mandated
and transition cost recovery mechanisms allowing SCE to recover its stranded
costs associated with generation-related assets were implemented. California's
electric industry restructuring statute included provisions to finance a portion
of the stranded costs that residential and small commercial customers would have
paid between 1998 and 2001, which allowed SCE to reduce rates by at least 10% to
these customers, effective January 1, 1998. These frozen rates are to remain in
effect until the earlier of March 31, 2002, or the date when the CPUC-authorized
costs for utility-owned generation assets and obligations are recovered.
However, since the summer of 2000, the prices charged by generators and other
sellers have escalated far beyond what SCE can currently charge its customers.
See Note 3 for a further discussion.
SCE also produces electricity. On April 1, 1998, SCE began selling all of its
electric generation through the California Power Exchange (PX) and Independent
System Operator (ISO) and scheduling delivery through the ISO, as mandated by
the CPUC's 1995 restructuring decision. By purchasing wholesale electricity
through the PX and ISO, SCE satisfied the electric energy needs for customers
who did not choose an alternative energy provider. The Federal Energy Regulatory
Commission (FERC) issued an order on December 15, 2000, which, among other
things, eliminated the requirement for California utilities to buy and sell
power exclusively through the ISO and PX. On January 19, 2001, the PX announced
that it will permanently cease operations by April 2001; on March 9, 2001, the
PX filed for Chapter 11 bankruptcy protection.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. In light of SCE's liquidity crisis, its Board of Directors
did not declare quarterly common stock dividends to its parent, Edison
International, in either December 2000 or March 2001. See Note 2 for a further
discussion.
Basis of Presentation
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated. Certain prior-year amounts were
reclassified to conform to the December 31, 2000, financial statement
presentation.
SCE's accounting policies conform with accounting principles generally accepted
in the United States, including the accounting principles for rate-regulated
enterprises, which reflect the rate-making policies of the CPUC and the FERC.
Since 1997, SCE has used accounting principles applicable to enterprises in
general for its investment in generation facilities, as a result of industry
restructuring legislation enacted by the State of California and related changes
in the rate-recovery of generation-related assets. Application of such
accounting principles to SCE's generation assets did not result in any
adjustment of their carrying value.
SCE's outstanding common stock is owned entirely by its parent company, Edison
International.
30
- --------------------------------------------------------------------------------
Southern California Edison Company
Estimates
Financial statements prepared in compliance with accounting principles generally
accepted in the United States require management to make estimates and
assumptions that affect the amounts reported in the financial statements and
disclosure of contingencies. Actual results could differ from those estimates.
Certain significant estimates related to liquidity, regulatory matters,
decommissioning and contingencies are further discussed in Notes 2, 3, 11 and 12
to the Consolidated Financial Statements, respectively.
Regulatory Balancing Accounts
During the rate freeze period, the difference between certain generation-related
revenue and generation-related costs are being accumulated in the transition
cost balancing account (TCBA). The gains resulting from the sale of 12 of SCE's
generating plants during 1998 have been credited to the TCBA; the losses are
being amortized over the remaining transition period and accumulated in the
TCBA.
In June 2000, SCE credited the TCBA for the estimated excess of the market value
over book value of its hydroelectric generation assets and simultaneously
recorded the same amount in the generation asset balancing account (GABA),
pursuant to a CPUC decision. This balance was to remain in GABA until final
market valuation of the hydroelectric generation assets. If there was a
difference in the final market valuation, it would have been credited to or
recovered from customers through the TCBA mechanism. Due to the various
unresolved regulatory and legislative issues (as discussed in Note 3), the GABA
transaction was reclassified back into the TCBA as of December 31, 2000.
The coal and hydroelectric generation balancing accounts tracked the differences
between market revenue from coal and hydroelectric generation and the plants'
operating costs after April 1, 1998. Overcollections were credited to the TCBA
in 1998 and 1999, pursuant to a 1997 CPUC decision. Due to a January 4, 2001,
interim CPUC decision, the balance at year-end 2000 was not credited to the
TCBA, pending further testimony and evidence on the implications of crediting
the overcollections to the transition revenue account (TRA) rather than the
TCBA. The TRA is a CPUC-authorized regulatory asset in which SCE recorded the
difference between revenue received from customers through currently frozen
rates and the costs of providing service to customers, including power
procurement costs.
On March 27, 2001 the CPUC issued a decision stating, among other things, that
the rate freeze had not ended, and the TCBA mechanism was to remain in place.
However, the decision required SCE to recalculate the TCBA retroactive to
January 1, 1998, the beginning of the rate freeze period. The new calculation
required the coal and hydroelectric balancing accounting overcollections (which
amounted to $1.5 billion as of December 31, 2000) to be closed monthly to the
TRA, rather than annually to the TCBA. In addition, it required the TRA to be
transferred to the TCBA on a monthly basis. Previous rules had called only for
overcollections to be transferred to the TCBA monthly, while undercollections
were to remain in the TRA until they were recovered from future overcollections
or the end of the rate freeze, whichever came first. Based on the new rules, the
$4.5 billion TRA undercollection as of December 31, 2000, and the coal and
hydroelectric balancing account overcollections, were reclassified to the TCBA,
and the TCBA balance was recalculated to be a $2.9 billion undercollection.
Due to the various unresolved regulatory and legislative issues (as discussed in
Note 3), the TCBA undercollection was charged to earnings as of December 31,
2000.
Balancing account undercollections and overcollections accrue interest. Income
tax effects on all balancing account changes are deferred.
31
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Regulatory Assets and Liabilities
In accordance with accounting principles for rate-regulated enterprises, SCE
records regulatory assets, which represent probable future revenue associated
with certain costs that will be recovered from customers through the rate-making
process, and regulatory liabilities, which represent probable future reductions
in revenue associated with amounts that are to be credited to customers through
the rate-making process. SCE's discontinuance of the application of accounting
principles for rate-regulated enterprises to its generation assets in 1997 did
not result in a write-off of its generation-related regulatory assets at that
time since the CPUC had approved recovery of these assets through the TCBA
mechanism.
There are many factors that affect SCE's ability to recover its regulatory
assets. SCE must assess the probability of recovery of its generation-related
regulatory assets in light of the CPUC's March 27, 2001, and April 3, 2001,
decisions (discussed in Note 3), including the retroactive transfer of balances
from SCE's TRA to its TCBA and related changes. These decisions and other
regulatory and legislative actions did not meet SCE's prior expectation that the
CPUC would provide adequate cost recovery mechanisms. Until legislative and
regulatory actions contemplated by the memorandum of understanding (MOU, as
discussed in Note 3) occur, or other actions are taken, SCE is unable to
conclude that its generation-related regulatory assets are probable of recovery
through the rate-making process. Therefore, in accordance with accounting rules,
SCE recorded a $2.5 billion after-tax charge to earnings as of December 31,
2000, to write off the TCBA and other regulatory assets (see below).
In addition to the TCBA, generation-related regulatory assets totaling $1.3
billion (including unamortized nuclear investment, flow-through taxes,
unamortized loss on sale of plant, purchased-power settlements and other
regulatory assets) were written off as of December 31, 2000. Unless the
memorandum of understanding (MOU, as discussed in Note 3) is implemented or a
rate-making mechanism is in place that would make recovery of SCE's TCBA-related
regulatory assets probable, future net undercollections in the TCBA will be
charged to earnings as losses are incurred. The regulatory and legislative
actions set forth in the MOU are expected to result in a rate-making mechanism
that would make recovery of these regulatory assets probable. If and when those
actions are taken, or other actions occur that make such recovery probable, and
the rate-making mechanism is adopted, the regulatory assets would be restored to
the balance sheet, with a corresponding increase to earnings.
Regulatory assets and liabilities included in the consolidated balance sheets
are:
In millions December 31, 2000 1999
- -----------------------------------------------------------------------------------------------
Generation-related:
Unamortized nuclear investment - net $ -- $ 1,366
Flow-through taxes -- 414
Unamortized loss on sale of plant -- 122
Purchased-power settlements -- 531
TCBA -- 1,044
Other - net -- 47
- -----------------------------------------------------------------------------------------------
Subtotal -- 3,524
- -----------------------------------------------------------------------------------------------
Rate reduction notes - transition cost deferral 1,090 707
- -----------------------------------------------------------------------------------------------
Other:
Flow-through taxes 874 859
Unamortized loss on reacquired debt 273 295
Environmental remediation 52 111
Regulatory balancing accounts and other (94) (42)
- -----------------------------------------------------------------------------------------------
Subtotal 1,105 1,223
- -----------------------------------------------------------------------------------------------
Total $2,195 $ 5,454
- -----------------------------------------------------------------------------------------------
32
- --------------------------------------------------------------------------------
Southern California Edison Company
The regulatory asset related to the rate reduction notes will be recovered over
the terms of the rate reduction notes. The other regulatory assets and
liabilities are being recovered through other components of the unbundled rates.
The unamortized nuclear investment regulatory asset was created during the
second quarter of 1998. SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount in accordance with asset impairment accounting
standards. For this impairment assessment, the fair value of the investment was
calculated by discounting expected future net cash flows. This reclassification
had no effect on SCE's results of operations.
Nuclear
SCE has been recovering its investments in San Onofre Nuclear Generating Station
Units 2 and 3 and Palo Verde Nuclear Generating Station on an accelerated basis,
as authorized by the CPUC. The accelerated recovery was to continue through
December 2001, earning a 7.35% fixed rate of return on investment. San Onofre's
operating costs, including nuclear fuel and nuclear fuel financing costs, and
incremental capital expenditures, are recovered through an incentive pricing
plan which allows SCE to receive about 4(cent) per kilowatt-hour through 2003.
Any differences between these costs and the incentive price will flow through to
the shareholders. Palo Verde's accelerated plant recovery, as well as operating
costs, including nuclear fuel and nuclear fuel financing costs, and incremental
capital expenditures, are subject to balancing account treatment through
December 31, 2001. The San Onofre and Palo Verde rate recovery plans and the
Palo Verde balancing account are part of the TCBA.
The nuclear rate-making plans and the TCBA mechanism will continue for
rate-making purposes at least through the end of the rate freeze period and
through 2001 for Palo Verde operating costs and through 2003 for the San Onofre
incentive pricing plan. However, due to the various unresolved regulatory and
legislative issues (as discussed in Note 3), SCE is no longer able to conclude
that the unamortized nuclear investment is probable of recovery through the
rate-making process. As a result, the balance was written off as a charge to
earnings as of December 31, 2000.
The benefits of operation of the San Onofre units and the Palo Verde units are
required to be shared equally with ratepayers beginning in 2004 and 2002,
respectively. Palo Verde's existing nuclear unit incentive procedure will
continue through 2001 only for purposes of calculating a reward for performance
of any unit above an 80% capacity factor for a fuel cycle.
Under the MOU (discussed in Note 3), both nuclear facilities would be subject to
cost-based ratemaking upon completion of their respective rate-making plans and
the sharing mechanisms that were to begin in 2004 and 2002 would be eliminated.
Cash Equivalents
Cash equivalents include tax-exempt investments, time deposits and other
investments with original maturities of three months or less.
Planned Major Maintenance
Certain plant facilities require major maintenance on a periodic basis. All such
costs are expensed as incurred.
33
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and
under the first-in, first-out method for coal.
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end
of each year.
Investments
Net unrealized gains (losses) on equity investments are recorded as a separate
component of shareholder's equity under the caption "Accumulated other
comprehensive income." Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
Derivative Financial Instruments
SCE uses the hedge accounting method to record its derivative financial
instruments. Hedge accounting requires an assessment that the transaction
reduces risk, that the derivative be designated as a hedge at the inception of
the derivative contract, and that the changes in the market value of a hedge
move in an inverse direction to the item being hedged. Under hedge accounting,
the derivative itself is not recorded on SCE's balance sheet. Mark-to-market
accounting would be used if the hedge accounting criteria were not met. Interest
rate differentials and amortization of premiums for interest rate caps are
recorded as adjustments to interest expense. If the derivatives were terminated
before the maturity of the corresponding debt issuance, the realized gain or
loss on the transaction would be amortized over the remaining term of the debt.
Utility Plant
Utility plant additions, including replacements and betterments, are
capitalized. Such costs include direct material and labor, construction overhead
and an allowance for funds used during construction (AFUDC). AFUDC represents
the estimated cost of debt and equity funds that finance utility-plant
construction. AFUDC is capitalized during plant construction and reported in
current earnings in other nonoperating income. AFUDC is recovered in rates
through depreciation expense over the useful life of the related asset.
Depreciation of utility plant is computed on a straight-line, remaining-life
basis.
AFUDC - equity was $11 million in 2000, $13 million in 1999 and $12 million in
1998. AFUDC - debt was $10 million in 2000, $11 million in 1999 and $8 million
in 1998.
Replaced or retired property and removal costs less salvage are charged to the
accumulated provision for depreciation. Depreciation expense stated as a percent
of average original cost of depreciable utility plant was 3.6% for both 2000 and
1999, and 4.2% for 1998.
SCE's net investment in generation-related utility plant was $1.0 billion at
both December 31, 2000, and December 31, 1999.
Related Party Transactions
Certain Edison Mission Energy (a wholly owned subsidiary of Edison
International) subsidiaries have ownership in partnerships that sell electricity
generated by their project facilities to SCE under long-term power purchase
agreements. Such sales to SCE were $716 million in 2000, $513 million in 1999
and
34
- --------------------------------------------------------------------------------
Southern California Edison Company
$535 million in 1998. As a result of SCE's liquidity crisis, SCE has
deferred payments for power purchases from some of these facilities.
Purchased Power -- PX/ISO
Transactions through the PX and ISO (reported net) were:
In millions Year ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------------------------------------
Purchases $8,449 $2,490 $1,984
Generation sales 6,120 1,719 1,348
- ----------------------------------------------------------------------------------------------------
Purchased power-- PX/ISO-- net $2,329 $ 771 $ 636
- ----------------------------------------------------------------------------------------------------
Other Nonoperating Income and Deductions
Other nonoperating income and deductions was comprised of:
In millions Year ended December 31, 2000 1999 1998
- -----------------------------------------------------------------------------------------------------
Gain on sale of marketable securities $ 41 $ 77 $ 30
AFUDC 21 24 20
Other 56 61 79
- -----------------------------------------------------------------------------------------------------
Total other nonoperating income $ 118 $ 162 $ 129
- -----------------------------------------------------------------------------------------------------
Provisions for regulatory issues and refunds $ 78 $ 79 $ 66
Other 32 28 51
- -----------------------------------------------------------------------------------------------------
Total other nonoperating deductions $ 110 $ 107 $ 117
- -----------------------------------------------------------------------------------------------------
Note 2. Liquidity Crisis
SCE's liquidity is primarily affected by debt maturities, dividend payments,
capital expenditures and power purchases. Capital resources include cash from
operations and external financings.
The increasing undercollection in the TRA, coupled with SCE's anticipated
near-term capital requirements and the adverse reaction of the credit markets to
continued regulatory uncertainty regarding SCE's ability to recover its current
and future power procurement costs, have materially and adversely affected SCE's
liquidity. As a result of the liquidity crisis, SCE has taken and is taking
steps to conserve cash, so that it can continue to provide service to its
customers. As a part of this process, SCE has temporarily suspended payments of
certain obligations for principal and interest on outstanding debt and for
purchased power. As of March 31, 2001, SCE had $2.7 billion in obligations that
were unpaid and overdue including: (1) $626 million to the PX or the ISO; (2)
$1.1 billion to power producers that are qualifying facilities (QFs); (3) $229
million in PX energy credits for energy service providers; (4) $506 million of
matured commercial paper; (5) $206 million of principal and interest on its
5-7/8% notes; and (6) $7 million of other obligations. Unpaid obligations will
continue to accrue interest, as applicable. At March 31, 2001, SCE had estimated
cash reserves of approximately $2.0 billion, which is approximately $700 million
less than its outstanding unpaid obligations and preferred stock dividends in
arrears (see below).
SCE is unable to obtain financing of any kind. As a result of investors'
concerns regarding the California energy crisis and its impact on SCE's
liquidity and overall financial condition, SCE has repurchased $549 million of
pollution-control bonds that could not be remarketed in accordance with their
terms. These bonds may be remarketed in the future if SCE's credit status
improves sufficiently. In addition, SCE has been unable to market its commercial
paper and other short-term financial instruments. As of March 31, 2001, SCE
resumed payment of interest on its debt obligations. If the MOU is implemented,
it is expected
35
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
to allow SCE to recover its undercollected costs and to restore SCE's
creditworthiness, which would allow SCE to pay all of its past due obligations.
On March 27, 2001, the CPUC ordered SCE to pay QFs for power deliveries on a
going forward basis, commencing with April 2001 deliveries. SCE must pay QFs
within 15 days of the end of the QF's billing period, and QFs are allowed to
establish 15-day billing periods. Failure to make a payment when due will result
in a fine equal to the amount owed. The CPUC also modified the formula used in
calculating payments to QFs by substituting natural gas index prices based on
deliveries at the Oregon border rather than the Arizona border. The CPUC stated
that the changes will probably result in lower QF power prices. The changes
apply to all QFs, where appropriate, regardless of whether they use natural gas
or other resources such as solar or wind.
On March 27, 2001, the CPUC also issued decisions on the California Procurement
Adjustment (CPA) calculation and the approval of a 3(cent) per kWh rate increase
(see Note 3). Based on these two decisions, SCE estimates that revenue going
forward will not be sufficient to recover retained generation, purchased-power
and transition costs. In comments filed with the CPUC on March 29, 2001, and
April 2, 2001, SCE provided a forecast showing that the net effects of the rate
increase, the payment ordered to be made to the California Department of Water
Resources (CDWR), and the QF decision discussed above could result in a
shortfall to the CPA calculation of $1.7 billion for SCE during 2001. To
implement the MOU, it will be necessary for the CPUC to modify or rescind these
decisions.
In light of SCE's liquidity crisis, its Board of Directors did not declare
quarterly common stock dividends to its parent, Edison International, in either
December 2000 or March 2001. Also, SCE's Board has not declared the regular
quarterly dividends for SCE's cumulative preferred stock, 4.08% Series, 4.24%
Series, 4.32% Series, 4.78% Series, 6.05% Series, 6.45% Series and 7.23% Series
in 2001. The total preferred stock dividends in arrears is $6 million as of
March 31, 2001. As a result of the $2.5 billion charge to earnings as of
December 31, 2000, SCE's retained earnings are now in a deficit position and
therefore, under California law, SCE will be unable to pay dividends as long as
a deficit remains. SCE does not meet other tests under which dividends can be
paid from sources other than retained earnings. As long as dividends in arrears
on SCE's cumulative preferred stock remain unpaid, SCE cannot pay any dividends
on its common stock.
In addition to the above, SCE has begun immediate cost-cutting measures which,
together with previously announced actions, such as freezing new hires,
postponing certain capital expenditures and ceasing new charitable
contributions, are aimed at reducing general operating costs. SCE's current
cost-cutting measures are intended to allow it to continue to operate while
efforts to reach a regulatory solution, involving both state and federal
authorities, are underway. Additional actions by SCE may be necessary if the
energy and liquidity crisis is not resolved in the near future.
On April 9, 2001, SCE and the CDWR signed an MOU that, if approved by the
legislature, would allow SCE to restore its financial health.
For a more detailed discussion on the matters discussed above, see Notes 3
through 7.
SCE's future liquidity depends, in large part, on whether the MOU is
implemented, or other action by the California Legislature and the CPUC is taken
in a manner sufficient to resolve the energy crisis and the cash flow deficit
created by the current rate structure and the excessively high price of energy.
Without a change in circumstances, such as that contemplated by the MOU,
resolution of SCE's liquidity crisis and its ability to continue to operate
outside of bankruptcy is uncertain. In addition, SCE's independent public
accountant's opinion in the accompanying financial statements includes an
explanatory paragraph which states that the issues resulting from the California
energy crisis raise substantial doubt about SCE's ability to continue as a going
concern.
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Southern California Edison Company
Note 3. Regulatory Matters
Status of Transition and Power-Procurement Cost Recovery
SCE's transition costs include power purchases from QF contracts (which are the
direct result of prior legislative and regulatory mandates), recovery of certain
generating assets and regulatory commitments consisting of recovery of costs
incurred to provide service to customers. Such commitments include the recovery
of income tax benefits previously flowed through to customers, postretirement
benefit transition costs, accelerated recovery of investment in San Onofre Units
2 and 3 and the Palo Verde units, and certain other costs. Transition costs
related to power-purchase contracts are being recovered through the terms of
each contract. Most of the remaining transition costs may be recovered through
the end of the transition period (not later than March 31, 2002). Although the
MOU provides for, among other things, SCE to be entitled to sufficient revenue
to cover its costs from January 2001 associated with retained generation and
existing power contracts, the implementation of the MOU requires the CPUC to
modify various decisions. Until the various regulatory and legislative actions
to implement the MOU are taken, or other actions occur that make such recovery
probable, SCE is not able to conclude that the regulatory assets and liabilities
related to purchased-power settlements, the unamortized loss on SCE's generating
plant sales in 1998, and various other regulatory assets and liabilities
(including income taxes previously flowed through to customers) related to
certain generating assets are probable of recovery through the rate-making
process. As a result, these balances were written off as a charge to earnings as
of December 31, 2000.
During the rate freeze period, there are three sources of revenue available to
SCE for transition cost recovery: revenue from the sale or valuation of
generation assets in excess of book values, net market revenue from the sale of
SCE-controlled generation into the ISO and PX markets and competition transition
charge (CTC) revenue. However, due to events discussed elsewhere in this report,
revenue from the sale or valuation of generation assets in excess of book values
(state legislation enacted in January 2001 prohibits the sale of SCE's remaining
generation assets until 2006) and from the sale of SCE-controlled generation
into the ISO and PX markets is no longer available to SCE. During 1998, SCE sold
all of its gas-fueled generation plants for $1.2 billion, over $500 million more
than the combined book value. Net proceeds of the sales were used to reduce
transition costs, which otherwise were expected to be collected through the TCBA
mechanism.
Net market revenue from sales of power and capacity from SCE-controlled
generation sources was also applied to transition cost recovery. Increases in
market prices for electricity affected SCE in two fundamental ways prior to the
CPUC's March 27, 2001, rate stabilization decision. First, CTC revenue decreased
because there was less or no residual revenue from frozen rates due to higher
cost PX and ISO power purchases. Second, transition costs decreased because
there was increased net market revenue due to sales from SCE-controlled
generation sources to the PX at higher prices (accumulated as an overcollection
in the coal and hydroelectric balancing accounts). Although the second effect
mitigated the first to some extent, the overall impact on transition cost
recovery was negative because SCE purchased more power than it sold to the PX.
In addition, higher market prices for electricity adversely affected SCE's
ability to recover non-transition costs during the rate freeze period. Since May
2000, market prices for electricity were extremely high and there was
insufficient revenue from customers under the frozen rates to cover all costs of
providing service during that period, and therefore there was no positive
residual CTC revenue transferred into the TCBA.
CTC revenue is determined residually (i.e., CTC revenue is the residual amount
remaining from monthly gross customer revenue under the rate freeze after
subtracting the revenue requirements for transmission, distribution, nuclear
decommissioning and public benefit programs, and ISO payments and power
purchases from the PX and ISO). The CTC applies to all customers who are using
or begin using utility services on or after the CPUC's 1995 restructuring
decision date. Residual CTC revenue is calculated through the TRA mechanism.
Under CPUC decisions in existence prior to March 27, 2001, positive residual CTC
revenue
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Notes to Consolidated Financial Statements
(TRA overcollections) was transferred to the TCBA monthly; TRA undercollections
were to remain in the TRA until they were offset by overcollections, or the rate
freeze ended, whichever came first. Pursuant to the March 27, 2001, rate
stabilization decision, both positive and negative residual CTC revenue is
transferred to the TCBA on a monthly basis, retroactive to January 1, 1998.
Upon recalculating the TCBA balance based on the new decision, SCE has received
positive residual CTC revenue (TRA overcollections) of $4.7 billion to recover
its transition costs from the beginning of the rate freeze (January 1, 1998)
through April 2000. As a result of sustained higher market prices, SCE
experienced the first month in which costs exceeded revenue in May 2000. Since
then, SCE's costs to provide power have continued to exceed revenue from frozen
rates and as a result, the cumulative positive residual CTC revenue flowing into
the TCBA mechanism has been reduced from $4.7 billion to $1.4 billion as of
December 31, 2000. The cumulative TCBA undercollection (as recalculated) is $2.9
billion as of December 31, 2000. A summary of the components of this cumulative
undercollection is as follows:
- -----------------------------------------------------------------------------
In millions
Transition costs recorded in the TCBA:
QF and interutility costs $ 3,561
Amortization of nuclear-related regulatory assets 3,090
Depreciation of plant assets 577
Other transition costs 634
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Total transition costs 7,862
Revenue available to recover transition costs (4,984)
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Unrecovered transition costs $ 2,878
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Unless the regulatory and legislative actions required to implement the MOU or
other actions that make recovery probable are taken, SCE is not able to conclude
that the recalculated TCBA net undercollection is probable of recovery through
the rate-making process. As a result, the $2.9 billion TCBA net undercollection
was written off as a charge to earnings as of December 31, 2000. In its interim
rate stabilization decision of March 27, 2001, the CPUC denied a December motion
by SCE to end the rate freeze, and stated that it will not end until recovery of
all specified transition costs (including TCBA undercollections as recalculated)
or March 31, 2002.
Rate Stabilization Proceeding
In January 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of transition cost recovery. On December 20,
2000, SCE filed an amended rate stabilization plan application, stating that the
CPUC must recognize that the statutory rate freeze is now over in accordance
with California law, and requesting the CPUC to approve an immediate 30%
increase to be effective, subject to refund, January 4, 2001. SCE's plan
included a trigger mechanism allowing for rate increases of 5% every six months
if SCE's TRA undercollection balance exceeds $1 billion. Hearings were held in
late December 2000.
On January 4, 2001, the CPUC issued an interim decision that authorized SCE to
establish an interim surcharge of 1(cent) per kWh for 90 days, subject to
refund. The revenue from the surcharge is being tracked through a balancing
account and applied to ongoing power procurement costs. The surcharge resulted
in rate increases, on average, of approximately 7% to 25%, depending on the
class of customer. As noted in the decision, the 90-day period allowed
independent auditors engaged by the CPUC to perform a comprehensive review of
SCE's financial position, as well as that of Edison International and other
affiliates.
On January 29, 2001, independent auditors hired by the CPUC issued a report on
the financial condition and solvency of SCE and its affiliates. The report
confirmed what SCE had previously disclosed to the
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Southern California Edison Company
CPUC in public filings about SCE's financial condition. The audit report covers,
among other things, cash needs, credit relationships, accounting mechanisms to
track stranded cost recovery, the flow of funds between SCE and Edison
International, and earnings of SCE's California affiliates. On April 3, 2001,
the CPUC adopted an order instituting investigation (originally proposed on
March 15, 2001). The order reopens the past CPUC decision authorizing the
utilities to form holding companies and initiates an investigation into: whether
the holding companies violated company requirements to give priority to the
capital needs of their respective utility subsidiaries; whether ring-fencing
actions by Edison International and PG&E Corporation and their respective
nonutility affiliates also violated the requirements to give priority to the
capital needs of their utility subsidiaries; whether the payment of dividends by
the utilities violated requirements that the utilities maintain dividend
policies as though they were comparable stand-alone utility companies; any
additional suspected violations of laws or CPUC rules and decisions; and whether
additional rules, conditions, or other changes to the holding company decisions
are necessary. An assigned commissioner's ruling on March 29, 2001, required SCE
to respond within 10 days to document requests and questions that are
substantially identical to those included in the March 15 proposed order
instituting investigation. The MOU calls for the CPUC to adopt a decision
clarifying that the first priority condition in SCE's holding company decision
refers to equity investment, not working capital for operating costs. SCE cannot
provide assurance that the CPUC will adopt such a decision, or predict what
effects this investigation or any subsequent actions by the CPUC may have on
SCE.
In its interim order adopted on March 27, 2001, the CPUC granted SCE a rate
increase in the form of a 3(cent) per kWh surcharge applied only to electric
power costs, effective immediately, and affirmed that the 1(cent) interim
surcharge granted on January 4, 2001, is now permanent. Although the 3(cent)
increase was authorized immediately, the surcharge will not be collected in
rates until the CPUC establishes an appropriate rate design, which is not
expected to occur until May 2001. SCE has asked the CPUC to immediately adopt an
interim rate increase that would allow the rate change to go into effect sooner.
The CPUC also ordered that the 3(cent) surcharge be added to the rate paid to
the CDWR pursuant to the interim CDWR-related decision.
Also, in the interim order, the CPUC granted a petition previously filed by The
Utility Reform Network and directed that the balance in SCE's TRA account,
whether over- or undercollected, be transferred on a monthly basis to the TCBA
account, retroactive to January 1, 1998. Previous rules called only for TRA
overcollections (residual CTC revenue) to be transferred to the TCBA. The CPUC
also ordered SCE to transfer the coal and hydroelectric balancing account
overcollections to the TRA on a monthly basis before any transfer of residual
CTC revenue to the TCBA, retroactive to January 1, 1998. Previous rules called
for overcollections in these two balancing accounts to be transferred directly
to the TCBA on an annual basis. SCE believes this interim order attempts to
retroactively transform power purchase costs in the TRA into transition costs in
the TCBA. However, the CPUC characterized the accounting changes as merely
reducing the prior residual CTC revenue recorded in the TCBA, thereby only
affecting the amount of transition cost recovery achieved to date. Based upon
the transfer of balances into the TCBA, the CPUC denied SCE's December 2000
filing to have the current rate freeze end, and stated that it will not end
until recovery of all specified transition costs or March 31, 2002; and that
balances in the TRA cannot be recovered after the end of the rate freeze. The
CPUC also said that it will monitor the balances remaining in the TCBA and
consider how to address remaining balances in the ongoing proceedings. If the
CPUC does not modify this decision in a manner consistent with the MOU, SCE
intends to challenge this decision through all appropriate means.
Although the CPUC has authorized a substantial rate increase in its March 27,
2001, order, it has allocated the revenue from the increase entirely to future
purchased-power costs without addressing SCE's past undercollections for the
costs of purchased power. The CPUC's decisions do not assure that SCE will be
able to meet its ongoing obligations or repay past due obligations. By ordering
immediate payments to the CDWR and QFs, the CPUC aggravated SCE's cash flow and
liquidity problems. Additionally, the CPUC expressed the view that AB 1X (see
CDWR Power Purchases) continues the utilities' obligations to serve their
customers, and stated that it cannot assume that the CDWR will
39
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Notes to Consolidated Financial Statements
purchase all the electricity needed above what the utilities either generate or
have under contract (the net short position) and cannot order the CDWR to do so.
This could result in additional purchased power costs with no allowed means of
recovery. To implement the MOU, it will be necessary for the CPUC to modify or
rescind these decisions. SCE cannot provide any assurance that the CPUC will do
so.
Wholesale Electricity Markets
In October 2000, SCE filed a joint petition urging the FERC to immediately find
the California wholesale electricity market to be not workably competitive,
immediately impose a cap on the price for energy and ancillary services, and
institute further expedited proceedings regarding the market failure, mitigation
of market power, structural solutions and responsibility for refunds. On
December 15, 2000, the FERC released a final order containing remedies and other
actions in response to the problems in the California electricity market. The
order, among other things, eliminated the requirement for California utilities
to buy and sell power exclusively through the ISO and PX; created a benchmark
price for wholesale bilateral power contracts; created penalties for
under-scheduling power loads; provided for an independent governing board for
the ISO; and established a breakpoint of $150/MWh so that bids below $150 may
clear at a single market-clearing price at or below $150/MWh and bids above $150
will be paid as bid. On December 18, 2000, SCE filed with the FERC an emergency
request for rehearing and expedited action seeking reconsideration of the
December 15 order. On January 12, 2001, the FERC issued an order granting
rehearing for the purpose of further consideration. The PX did not immediately
implement the $150/MWh breakpoint and on February 26, 2001, made a compliance
filing with the FERC, which requested the FERC's guidance on an acceptable
recalculation methodology. On April 6, 2001, the FERC issued an order providing
guidance to the PX, which should reduce SCE's energy costs owed to the PX for
the month of January 2001.
On December 13, 2000, the ISO announced that generators of electricity were
refusing to sell into the California market due to concerns about the financial
stability of SCE and Pacific Gas and Electric Company. In response to this
announcement, on December 14, 2000, the United States Secretary of Energy issued
an order requiring power companies to make arrangements to generate and deliver
electricity as requested by the ISO after the ISO certifies that it has been
unable to acquire adequate supplies of electricity in the market. After being
renewed multiple times, the order expired on February 6, 2001. However, on
February 7, 2001, a federal court judge issued a temporary restraining order
requiring power suppliers to sell to the California grid. On March 21, 2001, a
federal court judge ordered one of the power suppliers to continue to sell power
to the California grid. The three other power suppliers have signed an agreement
with the judge voluntarily agreeing to continue to sell power to the grid while
awaiting a review of the issue by the FERC. On April 6, 2001, the United States
Court of Appeals issued a stay order, suspending the lower court's March 21
order until a final appeals ruling can be issued.
On December 26, 2000, SCE filed an emergency petition in the federal Court of
Appeals challenging the FERC order and seeking a writ of mandamus requiring the
FERC to immediately establish cost-based wholesale rates. On January 5, 2001,
the court denied SCE's petition. The effect of the denial is to leave in place
the FERC's market controls that have allowed wholesale prices to climb to
current levels. SCE's petition for rehearing remains pending. SCE cannot predict
what action the FERC may take. SCE is considering the possibility of judicial
appeals and other actions.
On March 9, 2001, FERC directed 13 wholesale sellers of energy to refund $69
million or submit cost-of-service information to FERC to justify their prices
above $273/MWh during ISO Stage 3 emergencies in January 2001. SCE will oppose
the order as inadequate, particularly because the FERC is unwilling to exercise
any control over sellers exercise of market power during periods other than
Stage 3 emergencies. On March 16, 2001, the FERC ordered six wholesale sellers
of energy to refund an additional $55 million or submit cost-of-service
information to the FERC to justify their prices above $430/MWh during ISO Stage
3 emergencies in February 2001. A Stage 3 emergency refers to 1.5% or less in
reserve power, which could trigger rotating blackouts in some neighborhoods.
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Southern California Edison Company
Memorandum of Understanding with the CDWR
On April 9, 2001, Edison International and SCE signed an MOU with the CDWR
regarding the California energy crisis and its effects on SCE. The Governor of
California and his representatives participated in the negotiation of the MOU,
and the Governor endorsed implementation of all the elements of the MOU. The MOU
sets forth a comprehensive plan calling for legislation, regulatory action and
definitive agreements to resolve important aspects of the energy crisis, and
which, if implemented, is expected to help restore SCE's creditworthiness and
liquidity. Key elements of the MOU include:
o SCE will sell its transmission assets to the CDWR, or another authorized
California state agency, at a price equal to 2.3 times their aggregate book
value, or approximately $2.76 billion. If a sale of the transmission assets
is not completed under certain circumstances, SCE's hydroelectric assets
and other rights may be sold to the state in their place. SCE will use the
proceeds of the sale in excess of book value to reduce its undercollected
costs and retire outstanding debt incurred in financing those costs. SCE
will agree to operate and maintain the transmission assets for at least
three years, for a fee to be negotiated.
o Two dedicated rate components will be established to assist SCE in
recovering the net undercollected amount of its power procurement costs
through January 31, 2001, estimated to be approximately $3.5 billion. The
first dedicated rate component will be used to securitize the excess of the
undercollected amount over the expected gain on sale of SCE's transmission
assets, as well as certain other costs. Such securitization will occur as
soon as reasonably practicable after passage of the necessary legislation
and satisfaction of other conditions of the MOU. The second dedicated rate
component would not be securitized and would not appear in rates unless the
transmission sale failed to close within a two-year period. The second
component is designed to allow SCE to obtain bridge financing of the
portion of the undercollection intended to be recovered through the gain on
the transmission sale.
o SCE will continue to own its generation assets, which will be subject to
cost-based ratemaking, through 2010. SCE will be entitled to collect
revenue sufficient to cover its costs from January 1, 2001, associated with
the retained generation assets and existing power contracts. The MOU calls
for the CPUC to adopt cost recovery mechanisms consistent with SCE
obtaining and maintaining an investment-grade credit rating.
o The CDWR will assume the entire responsibility for procuring the
electricity needs of retail customers within SCE's service territory
through December 31, 2002, to the extent that those needs are not met by
generation sources owned by or under contract to SCE. (The unmet needs are
referred to as SCE's net short position.) SCE will resume procurement of
its net short position after 2002. The MOU calls for the CPUC to adopt cost
recovery mechanisms to make it financially practicable for SCE to reassume
this responsibility.
o SCE's authorized return on equity will not be reduced below its current
level of 11.6% before December 31, 2010. Through the same date, a
rate-making capital structure for SCE will not be established with
different proportions of common equity or preferred equity to debt than set
forth in current authorizations. These measures are intended to enable SCE
to achieve and maintain an investment-grade credit rating.
o Edison International and SCE will commit to make capital investments in
SCE's regulated businesses of at least $3 billion through 2006, or a lesser
amount approved by the CPUC. The equity component of the investments will
be funded from SCE's retained earnings or, if necessary, from equity
investments by Edison International.
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Notes to Consolidated Financial Statements
o An affiliate of Edison International will execute a contract with the CDWR
or another state agency for the provision of power to the state at
cost-based rates for ten years from a power project currently under
development. The Edison International affiliate will use all commercially
reasonable efforts to place the first phase of the project into service
before the end of summer 2001.
o SCE will grant perpetual conservation easements over approximately 21,000
acres of lands associated with SCE's Big Creek and Eastern Sierra
hydroelectric facilities. The easements initially will be held by a trust
for the benefit of the State of California, but ultimately may be assigned
to nonprofit entities or certain governmental agencies. SCE will be
permitted to continue utility uses of the subject lands.
o After the other elements of the MOU are implemented, SCE will enter into a
settlement of or dismiss its federal district court lawsuit against the
CPUC seeking recovery of past undercollected costs. The settlement or
dismissal will include related claims against the State of California or
any of its agencies, or against the federal government.
The sale of SCE's transmission system and other elements of the MOU must be
approved by the FERC. Edison International, SCE and the CDWR committed in the
MOU to proceed in good faith to sponsor and support the required legislation and
to negotiate in good faith the necessary definitive agreements. The MOU may be
terminated by either SCE or the CDWR if required legislation is not adopted and
definitive agreements executed by August 15, 2001, or if the CPUC does not adopt
required implementing decisions within 60 days after the MOU was signed, or if
certain other adverse changes occur. SCE cannot provide assurance that all the
required legislation will be enacted, regulatory actions taken, and definitive
agreements executed before the applicable deadlines.
CDWR Power Purchases
Pursuant to an emergency order signed by the Governor, the CDWR began making
emergency power purchases for SCE's customers on January 18, 2001. On February
1, 2001, Assembly Bill 1 (First Extraordinary Session) (AB 1X) was enacted into
law. The new law authorized the CDWR to enter into contracts to purchase
electric power and sell power at cost directly to retail customers being served
by SCE, and authorized the CDWR to issue revenue bonds to finance electricity
purchases. The new law directed the CPUC to determine the amount of the CPA as a
residual amount of SCE's generation-related revenue, after deducting the cost of
SCE-owned generation, QF contracts, existing bilateral contracts and ancillary
services. The new law also directed the CPUC to determine the amount of the CPA
that is allocable to the power sold by the CDWR, which will be payable to the
CDWR when received by SCE. On March 7, 2001, the CPUC issued an interim order in
which it held that the CDWR's purchases are not subject to prudency review by
the CPUC, and that the CPUC must approve and impose, either as a part of
existing rates or as additional rates, rates sufficient to enable the CDWR to
recover its revenue requirements.
On March 27, 2001, the CPUC issued an interim CDWR-related order requiring SCE
to pay the CDWR a per-kWh price equal to the applicable generation-related
retail rate per kWh for electricity (based on rates in effect on January 5,
2001), for each kWh the CDWR sells to SCE's customers. The CPUC determined that
the generation-related retail rate should be equal to the total bundled electric
rate (including the 1(cent) per kWh temporary surcharge adopted by the CPUC on
January 4, 2001) less certain nongeneration-related rates or charges. For the
period January 19 through January 31, 2001, the CPUC ordered SCE to pay the CDWR
at a rate of 6.277(cent) per kWh for power delivered on an interim basis to
SCE's customers. The CPUC determined that the applicable rate component is
7.277(cent) per kWh (which will increase to 10.277(cent) per kWh for electricity
delivered after March 27, 2001, due to the 3(cent) surcharge discussed in Rate
Stabilization Proceeding), for electricity delivered by the CDWR to SCE's retail
customers after February 1, 2001, until more specific rates are calculated. The
CPUC ordered SCE to pay the CDWR within 45 days after the CDWR supplies power to
retail customers, subject to penalties for each day the
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Southern California Edison Company
payment is late. Using these rates, SCE has billed customers $196 million for
sales made by the CDWR during the period January 19 through March 31, 2001, and
has forwarded $52 million to the CDWR on behalf of these customers as of March
31, 2001.
On April 3, 2001, the CPUC adopted the method (originally proposed in the March
27 CDWR-related order discussed above) it will use to calculate the CPA (which
was established by AB 1X) and then applied the method to calculate a
company-wide CPA rate for SCE. The CPUC used that rate to determine the CPA
revenue amount that can be used by the CDWR for issuing bonds. The CPUC stated
that its decision is narrowly focused to calculate the maximum amount of bonds
that the CDWR may issue and does not dedicate any particular revenue stream to
the CDWR. The CPUC determined that SCE's CPA rate is 1.120(cent) per kWh, which
generates annual revenue of $856 million. In its calculation of the CPA, the
CPUC disregarded all of the adjustments requested by SCE in its comments filed
on March 29 and April 2, 2001. SCE's comments included, among other things, a
forecast showing that the net effect of the rate increases (discussed in Rate
Stabilization Proceeding), as well as the March 27 QF payment decision
(discussed in Note 2) and the payments ordered to be made to CDWR, could result
in a shortfall in the CPA calculation of $1.7 billion for SCE during 2001. SCE
estimates that its future revenue will not be sufficient to cover its retained
generation, purchased-power and transition costs. To implement the MOU, the CPUC
will need to modify the calculation methods and provide reasonable assurance
that SCE will be able to recover its ongoing costs.
SCE believes that the intent of AB 1X was for the CDWR to assume full
responsibility for purchasing all power needed to serve the retail customers of
electric utilities, in excess of the output of generating plants owned by the
electric utilities and power delivered to the utilities under existing
contracts. However, the CDWR has stated that it is only purchasing power that it
considers to be reasonably priced, leaving the ISO to purchase in the short-term
market the additional power necessary to meet system requirements. The ISO, in
turn, takes the position that it will charge SCE for the costs of power it
purchases in this manner. If SCE is found responsible for any portion of the
ISO's purchases of power for resale to SCE's customers, SCE will continue to
incur purchased-power costs in addition to the unpaid costs described above. In
its March 27, 2001, interim order, the CPUC stated that it cannot assume that
the CDWR will pay for the ISO purchases and that it does not have the authority
to order the CDWR to do so. Litigation among certain power generators, the ISO
and the CDWR (to which SCE is not a party), and proceedings before the FERC (to
which SCE is a party), may result in rulings clarifying the CDWR's financial
responsibility for purchases of power. On April 6, 2001, the FERC issued an
order confirming that the ISO must have a creditworthy buyer for any
transactions. In any event, SCE takes the position that it is not responsible
for purchases of power by the CDWR or the ISO on or after January 18, 2001, the
day after the Governor signed the order authorizing the CDWR to begin purchasing
power for utility customers. SCE cannot predict the outcome of any of these
proceedings or issues. The recently executed MOU states that the CDWR will
assume the entire responsibility for procuring the electricity needs of retail
customers within SCE's service territory through December 31, 2002, to the
extent those needs are not met by generation sources owned by or under contract
to SCE (SCE's net short position). SCE will resume buying power for its net
short position after 2002. The MOU calls for the CPUC to adopt cost-recovery
mechanisms to make it financially practicable for SCE to reassume this
responsibility.
Hydroelectric Market Value Filing
In 1999, SCE filed an application with the CPUC establishing a market value for
its hydroelectric generation-related assets at approximately $1.0 billion
(almost twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based, revenue-sharing mechanism. If
approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-indexed operations and maintenance allowance, as well as a reasonable
return on capital investment. A revenue-sharing arrangement would be activated
if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue
to ratepayers or recover 90% of any shortfall from ratepayers. If the MOU is
implemented, SCE's hydroelectric assets
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Notes to Consolidated Financial Statements
will be retained through 2010 under cost-based rates, or they may be sold to the
state if a sale of SCE's transmission assets is not completed under certain
circumstances.
Note 4. Financial Instruments
SCE's risk management policy allows the use of derivative financial instruments
to manage financial exposure on its investments, fluctuations in interest rates
and energy prices, but prohibits the use of these instruments for speculative or
trading purposes.
SCE used the mark-to-market accounting method for its gas call options, which
were used to mitigate SCE's transition cost recovery exposure to increases in
energy prices. Gains and losses from monthly changes in market prices were
recorded as income or expense. In addition, the options' costs and market price
changes were included in the TCBA. As a result, the mark-to-market gains or
losses had no effect on earnings. In October 2000, SCE sold its gas call options
resulting in a $190 million gain. The options covered various periods through
2001. The gains were credited to the TCBA.
The PX block forward market allowed SCE to purchase monthly blocks of energy and
ancillary services for six days a week (excluding Sundays and holidays) for 8 to
16 hours a day, up to 12 months in advance of the delivery date.
SCE purchased block forward energy contracts through the PX, with various terms
and prices, to hedge its exposure to fluctuations in energy prices. Due to the
downgrades in SCE's credit ratings and SCE's failure to pay its obligations to
the PX, the PX suspended SCE's market trading privileges and sought to liquidate
SCE's block forward contracts. On February 2, 2001, SCE's motion for a
preliminary injunction was denied, freeing the PX to liquidate the contracts and
apply the proceeds to amounts owed by SCE to the PX. On the same day, the State
seized the contracts for the benefit of the State before they could be sold by
the PX. The State must compensate SCE for the reasonable value of the contracts.
The PX has indicated that it will also seek to recover the monies that SCE owes
to the PX from any proceeds realized from those contracts. After other elements
of the MOU are implemented, SCE would relinquish all claims against the State
for seizing these contracts. At December 31, 2000, these contracts had a nominal
value of $234 million.
SCE also has bilateral forward contacts, which are considered normal purchases
under accounting rules. At December 31, 2000, these contracts had a nominal
value of $798 million. Due to its deteriorating credit ratings, SCE has been
unable to purchase additional bilateral forward contracts, and $379 million
(nominal value) of its existing contracts were terminated by the counterparties
in early 2001. SCE is exposed to credit loss in the event of nonperformance by
the counterparties to its bilateral forward contracts, but does not expect the
counterparties to fail to meet their obligations. The counterparties are
required to post collateral depending on the creditworthiness of each
counterparty. SCE is exposed to market risk resulting from changes in the spot
market price for power. Changes in the value of bilateral forward contracts
affects purchased power expense in the period when the power is delivered.
SCE used an interest rate swap to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At December 31, 2000, and December
31, 1999, SCE had an interest rate swap agreement which fixed the interest rate
at 5.585% for $196 million of debt due 2008; the receive rate on the swap
averaged 3.839% in 2000. As a result of the downgrade in SCE's credit rating
below the level allowed under the interest rate hedge agreement, on January 5,
2001, the counterparty on this interest rate swap terminated the agreement. As a
result of the termination of the swap, SCE is paying a floating rate on $196
million of its debt due 2008. The realized loss of $26 million will be amortized
over a period ending in 2008.
On January 1, 2001, SCE adopted a new accounting standard for derivative
instruments and hedging activities. The new standard requires all derivatives to
be recognized on the balance sheet at fair value.
44
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Southern California Edison Company
Gains or losses from changes in fair value will be recognized in earnings in the
period of change unless the derivative is designated as a hedging instrument.
Gains or losses from hedges of a forecasted transaction or foreign currency
exposure will be recorded as a separate component of shareholder's equity under
the caption "Accumulated other comprehensive income." Gains or losses from
hedges of a recognized asset or liability or a firm commitment would be
reflected in earnings for the ineffective portion of the hedge. SCE's
derivatives qualify for hedge accounting under the new standard. On the
implementation date, SCE recorded its interest rate swap agreement (terminated
January 5, 2001) and its block forward power purchase contracts (seized by the
State on February 2, 2001) at fair value on its balance sheet. SCE does not
anticipate any earnings impact from its derivatives, since it expects that any
market price changes will be recovered in rates.
Fair values of financial instruments were:
In millions December 31, 2000 1999
- -----------------------------------------------------------------------------------------------------------
Cost Fair Cost Fair
Basis Value Basis Value
- -----------------------------------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $1,720 $2,505 $1,650 $2,509
Equity investments -- -- -- 33
Gas call options -- -- 28 20
Financial liabilities:
DOE decommissioning and
decontamination fees 36 31 40 35
Interest rate swap -- 21 -- 13
Long-term debt 5,631 5,178 5,137 5,044
Preferred stock subject to
mandatory redemption 256 157 256 259
- -----------------------------------------------------------------------------------------------------------
Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts, equity investments and gas call options. Financial
liabilities are recorded at cost. Financial liabilities' fair values are based
on: quoted market prices for the interest rate swap; brokers' quotes for
long-term debt and preferred stock; and discounted future cash flows for U.S.
Department of Energy (DOE) decommissioning and decontamination fees. Due to
their short maturities, amounts reported for cash equivalents and short-term
debt approximated fair value at December 31, 2000, and 1999.
As a result of investors' concerns regarding SCE's liquidity difficulties, its
short-term debt and long-term debt fair values have decreased approximately $150
million and $500 million, respectively, from amounts reported at year-end.
Gross unrealized holding gains on debt and equity securities were:
In millions December 31, 2000 1999
- ----------------------------------------------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $193 $239
Stocks 384 454
U.S. government issues 136 119
Short-term and other 72 47
- ----------------------------------------------------------------------------------------------------------------
785 859
Equity investments -- 33
- ----------------------------------------------------------------------------------------------------------------
Total $785 $892
- ----------------------------------------------------------------------------------------------------------------
There were no unrealized holding losses on debt and equity securities for the
years presented.
45
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Note 5. Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged
first and refunding mortgage bonds as security for borrowed funds obtained from
pollution control bonds issued by government agencies. SCE uses these proceeds
to finance construction of pollution control facilities. Bondholders have
limited discretion in redeeming certain pollution-control bonds, and SCE has
arrangements with securities dealers to remarket or purchase them if necessary.
As a result of investors' concerns regarding SCE's liquidity difficulties and
overall financial condition, SCE has had to repurchase $549 million of pollution
control bonds in December 2000 and early 2001 that could not be remarketed in
accordance with their terms.
Debt premium, discount and issuance expenses are amortized over the life of each
issue. Under CPUC rate-making procedures, debt reacquisition expenses are
amortized over the remaining life of the reacquired debt or, if refinanced, the
life of the new debt.
Commercial paper intended to be refinanced for a period exceeding one year and
used to finance nuclear fuel scheduled to be used more than one year after the
balance sheet date is classified as long-term debt.
In December 1997, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable
right known as transition property. Transition property is a current property
right created by the restructuring legislation and a financing order of the CPUC
and consists generally of the right to be paid a specified amount from
nonbypassable rates charged to residential and small commercial customers. The
rate reduction notes are being repaid over 10 years through these nonbypassable
residential and small commercial customer rates which constitute the transition
property purchased by SCE Funding LLC. The notes are secured by the transition
property and are not secured by, or payable from, assets of SCE or Edison
International. SCE used the proceeds from the sale of the transition property to
retire debt and equity securities. Although, as required by accounting
principles generally accepted in the United States, SCE Funding LLC is
consolidated with SCE and the rate reduction notes are shown as long-term debt
in the consolidated financial statements, SCE Funding LLC is legally separate
from SCE. The assets of SCE Funding LLC are not available to creditors of SCE or
Edison International and the transition property is legally not an asset of SCE
or Edison International. Due to SCE's recent credit downgrade, in January 2001,
SCE began remitting its customer collections related to the rate-reduction notes
on a daily basis.
46
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Southern California Edison Company
Long-term debt consisted of:
In millions December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------
First and refunding mortgage bonds:
2002-2026 (5.625% to 7.25%) $1,175 $1,400
Rate reduction notes:
2001-2007 (6.17% to 6.42%) 1,724 1,970
Pollution-control bonds:
2008-2040 (5.125% to 7.2% and variable) 1,216 1,196
Bonds repurchased (420) --
Funds held by trustees (20) (2)
Debentures and notes:
2001-2029 (5.875% to 7.625% and variable) 2,450 1,000
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 79 71
Long-term debt due within one year (646) (571)
Unamortized debt discount-- net (27) (27)
- -------------------------------------------------------------------------------------------------------------------
Total $5,631 $5,137
- -------------------------------------------------------------------------------------------------------------------
Long-term debt maturities and sinking-fund requirements for the next five years
are: 2001 -- $646 million; 2002 -- $746 million; 2003 -- $1.4 billion; 2004 --
$371 million; and 2005 -- $246 million.
As a result of its liquidity crisis, SCE has taken steps to conserve cash, and
has been forced to consider further alternatives for conserving cash, so that it
can continue to provide service to its customers. As a part of this process, SCE
has temporarily suspended payments of certain obligations. As of March 31, 2001,
SCE has failed to pay $206 million of maturing principal and accrued interest on
its 5-7/8% notes. Under the indenture for SCE's senior unsecured notes, the
failure to pay principal was an immediate event of default as to the one series
of notes on which the principal was due. If an event of default occurs as to any
series of senior unsecured notes, the trustee or the holders of 25% in principal
amount of the notes of such series may declare the principal of the notes of
that series to be immediately due and payable. In addition, SCE's failure to pay
any obligation for borrowed money in an aggregate amount in excess of $10
million would constitute an event of default with respect to all of the senior
unsecured notes and SCE's outstanding quarterly income preferred securities if
not cured within 30 days after notice from the trustee of holders of the
securities. No such notice has been received by SCE.
If a notice of default is received, SCE could cure the default only by paying
$700 million in overdue principal and interest to holders of commercial paper
and the 5-7/8% notes. (SCE has also deferred payment of maturing commercial
paper. See Note 6 for a further discussion.) Making such payment would further
impact SCE's liquidity. If a notice of default were received and not cured, and
the trustee or noteholders declare an acceleration of the outstanding principal
amount of the senior unsecured notes, SCE would not have the cash to pay the
obligation and could be forced to declare bankruptcy.
In January 2001, three rating agencies lowered their credit ratings of SCE to
substantially below investment grade. In mid-April, one agency removed SCE's
credit ratings from review for possible downgrade. The ratings remain under
review for possible downgrade by the other two agencies.
Note 6. Short-Term Debt
Short-term debt is used to finance fuel inventories, balancing account
undercollections and general cash requirements, including PX and ISO payments.
Commercial paper intended to finance nuclear fuel scheduled to be used more than
one year after the balance sheet date is classified as long-term debt in
connection with refinancing terms under five-year term lines of credit with
commercial banks.
47
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Short-term debt consisted of:
In millions December 31, 2000 1999
- -------------------------------------------------------------------------------
Commercial paper $ 700 $ 696
Bank loans 835 --
Floating rate notes -- 175
Amount reclassified as long-term debt (79) (71)
Unamortized discount (5) (4)
- -------------------------------------------------------------------------------
Total $1,451 $ 796
- -------------------------------------------------------------------------------
Weighted average interest rates 6.9% 6.1%
At December 31, 2000, SCE had lines of credit totaling $1.65 billion, with $125
million available for the refinancing of certain variable-rate pollution control
debt. The lines can be drawn at negotiated or bank index rates.
As of January 2001, SCE had borrowed the entire $1.65 billion in funds available
under its credit line. The proceeds were used in part to repurchase $420 million
of pollution control bonds; the balance was retained as a liquidity reserve.
In late 2000, SCE was unable to complete the syndication of a $1 billion
revolving credit agreement that was intended to finance current and expected
balancing account undercollections and other operating requirements. In
addition, SCE has been unable to market its commercial paper and other
short-term financial instruments. And, in SCE's efforts to conserve cash, SCE
has deferred payment of approximately $506 million of maturing commercial paper
as of March 31, 2001.
Note 7. Preferred Stock
Authorized shares of preferred and preference stocks are: $25 cumulative
preferred -- 24 million; $100 cumulative preferred -- 12 million; and preference
- -- 50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund provisions.
When preferred shares are redeemed, the premiums paid are charged to common
equity.
Preferred stock redemption requirements for the next five years are: 2001 --
zero; 2002 --$105 million; 2003 -- $9 million; 2004 -- $9 million; and 2005 --
$9 million.
48
- --------------------------------------------------------------------------------
Southern California Edison Company
Cumulative preferred stocks consisted of:
Dollars in millions, except per share amounts December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------
December 31, 2000
-----------------
Shares Redemption
Outstanding Price
----------- ----------
Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000 $25.50 $ 25 $ 25
4.24 1,200,000 25.80 30 30
4.32 1,653,429 28.75 41 41
4.78 1,296,769 25.80 33 33
- -------------------------------------------------------------------------------------------------------------------
Total $ 129 $ 129
- -------------------------------------------------------------------------------------------------------------------
Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000 $100.00 $ 75 $ 75
6.45 1,000,000 100.00 100 100
7.23 807,000 100.00 81 81
- -------------------------------------------------------------------------------------------------------------------
Total $ 256 $ 256
- -------------------------------------------------------------------------------------------------------------------
In 1998, SCE redeemed 2.2 million shares of Series 5.8% and 193,000 shares of
Series 7.23% preferred stock. SCE did not issue any preferred stock in the last
three years.
SCE's Board of Directors did not declare the regular quarterly dividend for its
cumulative preferred stock in 2001. As long as these dividends remain unpaid,
SCE cannot declare or pay future cash dividends on any series of preferred stock
or on its common stock, and SCE cannot repurchase any shares of its common
stock. As a result of the $2.5 billion charge to earnings during fourth quarter
2000, SCE's retained earnings are now in a deficit position and therefore under
California law, SCE will be unable to pay dividends as long as a deficit
remains.
Note 8. Income Taxes
SCE and its subsidiaries are included in Edison International's consolidated
federal income tax and combined state franchise tax returns. Under an income tax
allocation agreement approved by the CPUC, SCE calculates its tax liability on a
stand-alone basis.
Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. Investment tax credits are
amortized over the lives of the related properties.
49
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
The components of the net accumulated deferred income tax liability were:
In millions December 31, 2000 1999
- -----------------------------------------------------------------------------------------------------
Deferred tax assets:
Decommissioning $ 98 $ 127
Accrued charges 379 247
Investment tax credits 81 113
Property-related 277 184
Regulatory balancing accounts 1,763 67
Unbilled revenue 101 122
Unrealized gains or losses 420 453
Other 56 92
- -----------------------------------------------------------------------------------------------------
Total $3,175 $1,405
- -----------------------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $2,184 $2,629
Capitalized software costs 264 225
Regulatory balancing accounts 1,632 448
Unrealized gains and losses 317 351
Other 242 502
- -----------------------------------------------------------------------------------------------------
Total $4,639 $4,155
- -----------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net $1,464 $2,750
- -----------------------------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $2,009 $2,938
Included in current assets 545 188
The current and deferred components of income tax expense were:
In millions Year ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------
Current:
Federal $ (104) $299 $450
State -- 79 101
- ----------------------------------------------------------------------------------------------------------------
(104) 378 551
- ----------------------------------------------------------------------------------------------------------------
Deferred--federal and state:
Accrued charges (133) (76) (43)
Investment and energy tax credits-- net (41) (45) (74)
Property related (302) (194) (169)
Regulatory asset amortization 251 7 63
Regulatory balancing accounts (740) 371 177
State tax--privilege year 31 7 --
Unbilled revenue 20 (5) (67)
Other (4) (5) 4
- ----------------------------------------------------------------------------------------------------------------
(918) 60 (109)
- ----------------------------------------------------------------------------------------------------------------
Total $ (1,022) $438 $442
- ----------------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income $(1,007) $451 $445
Included in other income (15) (13) (3)
The composite federal and state statutory income tax rate was 40.551% for all
years presented.
50
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Southern California Edison Company
The federal statutory income tax rate is reconciled to the effective tax rate
below:
Year ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software -- (2.4) (0.7)
Investment and energy tax credits 1.4 (4.4) (6.8)
Property-related and other (6.6) 9.3 11.4
State tax-- net of federal deduction 3.7 8.5 6.9
- --------------------------------------------------------------------------------------------------------------
Effective tax rate 33.5% 46.0% 45.8%
- --------------------------------------------------------------------------------------------------------------
Note 9. Employee Compensation and Benefit Plans
Employee Savings Plan
SCE has a 401(k) defined-contribution savings plan designed to supplement
employees' retirement income. The plan received employer contributions of $29
million in 2000, $25 million in 1999 and $17 million in 1998.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers employees
meeting minimum service requirements. SCE recognizes pension expense as
calculated by the actuarial method used for ratemaking. In April 1999, SCE
adopted a cash balance feature for its pension plan.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $2,075 $2,251
Service cost 63 66
Interest cost 155 146
Plan amendment -- (22)
Actuarial loss (gain) 90 (224)
Benefits paid (183) (142)
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $ 2,200 $2,075
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $3,078 $2,552
Actual return on plan assets 143 620
Employer contributions 29 48
Benefits paid (183) (142)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $3,067 $3,078
- -------------------------------------------------------------------------------------------------------------------
Funded status $867 $1,003
Unrecognized net loss (gain) (745) (1,018)
Unrecognized transition obligation 22 28
Unrecognized prior service cost 118 132
- -------------------------------------------------------------------------------------------------------------------
Recorded asset $262 $ 145
- -------------------------------------------------------------------------------------------------------------------
Discount rate 7.25% 7.75%
Rate of compensation increase 5.0% 5.0%
Expected return on plan assets 8.5% 7.5%
51
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Expense components were:
In millions Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Service cost $ 63 $ 66 $ 59
Interest cost 155 146 141
Expected return on plan assets (266) (188) (170)
Net amortization and deferral (40) 12 14
- -------------------------------------------------------------------------------------------------------------------
Expense under accounting standards (88) 36 44
Regulatory adjustment-- deferred 88 14 11
- -------------------------------------------------------------------------------------------------------------------
Total expense recognized $ -- $ 50 $ 55
- -------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service are
eligible for postretirement health and dental care, life insurance and other
benefits.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $ 1,462 $ 1,545
Service cost 39 46
Interest cost 121 109
Actuarial loss (gain) 202 (185)
Benefits paid (62) (53)
- -------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $ 1,762 $ 1,462
- -------------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 1,283 $ 1,029
Actual return on plan assets (40) 185
Employer contributions 19 122
Benefits paid (62) (53)
- -------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 1,200 $ 1,283
- -------------------------------------------------------------------------------------------------------------------
Funded status $ (562) $ (179)
Unrecognized net loss (gain) 141 (207)
Unrecognized transition obligation 323 349
- -------------------------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (98) $ (37)
- -------------------------------------------------------------------------------------------------------------------
Discount rate 7.5% 8.0%
Expected return on plan assets 8.2% 7.5%
Expense components were:
In millions Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Service cost $ 39 $ 46 $ 41
Interest cost 121 109 99
Expected return on plan assets (106) (79) (62)
Net amortization and deferral 27 27 28
- -------------------------------------------------------------------------------------------------------------------
Total expense $ 81 $ 103 $ 106
- -------------------------------------------------------------------------------------------------------------------
The assumed rate of future increases in the per-capita cost of health care
benefits is 11.0% for 2001, gradually decreasing to 5.0% for 2008 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 2000, by $277 million and
annual aggregate service and interest costs by $30 million. Decreasing the
health care cost trend
52
- --------------------------------------------------------------------------------
Southern California Edison Company
rate by one percentage point would decrease the accumulated obligation as of
December 31, 2000, by $239 million and annual aggregate service and interest
costs by $25 million.
Stock Option Plans
In 1998, Edison International shareholders approved the Edison International
Equity Compensation Plan, replacing the Long-Term Incentive Compensation Program
(prior program), which had been adopted by shareholders in 1992. Under the prior
program, options on 1.5 million shares of Edison International common stock
remain outstanding to officers and senior managers of SCE. The 1998 plan
authorizes a limited annual award of Edison International common shares and
options on shares. The annual authorization is cumulative, allowing subsequent
issuance of previously unutilized awards. In May 2000, Edison International
adopted an additional plan, the 2000 Equity Plan, which did not require
shareholder approval.
Under the 1998 and 2000 plans, options on 8.6 million shares of Edison
International common stock are currently outstanding to officers and senior
managers of SCE.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. Options expire 10 years after the
date of grant, and vest over a period of up to five years. A portion of the
executive long-term incentive program was awarded in the form of performance
shares. The performance shares were restructured as retention incentives in
December 2000, which will pay as a combination of Edison International common
stock and cash if the executive remains employed at the end of the performance
period. Performance shares may still be awarded in 2001 and 2002. No special
stock options may be exercised before five years have passed unless the stock
appreciates to $25 (based on the average of 20 consecutive trading day closing
prices). Edison International stock options awarded between 1994 and 1999
included a dividend equivalent feature. Dividend equivalents are accrued to the
extend dividends are declared on Edison International common stock, and are
subject to reduction unless certain performance criteria are met. Only a portion
of the 1999 Edison International stock option awards included a dividend
equivalent feature. The 2000 stock option awards did not include dividend
equivalents. Future stock option awards are not expected to include dividend
equivalents.
All stock options have 10-year terms. Options issued after 1997 generally vest
in 25% annual installments over a four-year period, although the vesting period
for the May 2000 grants does not begin until May 2001. Stock options issued
prior to 1998 had a three-year vesting period with one-third of the total award
vesting after each of the first three years of the award term. If an option
holder retires, dies or is permanently and totally disabled (qualifying event)
during the vesting period, the unvested options will vest on a pro rata basis.
Unvested options of any person who has served in the past on the SCE Management
Committee (which was dissolved in 1993) will vest and be exercised upon a
qualifying event. If a qualifying event occurs, the vested options may continue
to be exercised within their original terms by the recipient or beneficiary. If
an option holder is terminated other than by a qualifying event, options which
had vested as of the prior anniversary date of the grant are forfeited unless
exercised within 180 days of the date of termination. All unvested options are
forfeited on the date of termination.
The performance shares values are accrued ratably over a three-year performance
period. SCE measures compensation expense related to stock-based compensation by
the intrinsic value method. Compensation expense recorded under the
stock-compensation programs was $4 million in 2000, $5 million in 1999 and $8
million in 1998.
53
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Stock-based compensation expense under the fair value method of accounting would
have resulted in pro forma net income (loss) available for common stock of
$(2.054) billion in 2000, $484 million in 1999 and $491 million in 1998.
The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:
December 31, 2000 1999
- ----------------------------------------------------------------------------
Expected life 7 years--10 years 7 years
Risk-free interest rate 4.7%--6.0% 5.0% - 5.5%
Expected volatility 17%--46% 18%
- ----------------------------------------------------------------------------
The application of fair-value accounting to calculate the pro forma disclosures
above is not an indication of future income statement effects. The pro forma
disclosures do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.
The weighted-average fair value of options granted during 2000 and 1999 was
$5.50 per share option and $4.37 per share option, respectively. The
weighted-average remaining life of options outstanding as of December 31, 2000,
and December 31, 1999, was 7 years.
Note 10. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems for
which each participant provides its own financing. SCE's share of expenses for
each project is included in the consolidated statements of income.
The investment in each project as of December 31, 2000, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 41 $ 11 $ 1 60%
Pacific Intertie 230 80 6 50
Generating stations:
Four Corners Units 4 and 5 (coal) 463 351 3 48
Mohave (coal) 327 240 3 56
Palo Verde (nuclear)(1) 1,624 1,399 15 16
San Onofre (nuclear)(1) 4,268 3,874 22 75
- -------------------------------------------------------------------------------------------------------------------
Total $ 6,953 $ 5,955 $50
- -------------------------------------------------------------------------------------------------------------------
(1) Regulatory assets, which were written off as a charge to earnings as of
December 31, 2000, as discussed in Notes 1 and 3.
54
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Southern California Edison Company
Note 11. Commitments
Leases
SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.
Estimated remaining commitments for noncancellable leases at December 31, 2000,
were:
Year ended December 31, In millions
- ----------------------------------------------------------------------------
2001 $ 15
2002 12
2003 10
2004 9
2005 6
Thereafter 14
- -----------------------------------------------------------------------------
Total $ 66
- -----------------------------------------------------------------------------
Nuclear Decommissioning
Decommissioning is estimated to cost $2.1 billion in current-year dollars, based
on site-specific studies performed in 1998 for San Onofre and Palo Verde.
Changes in the estimated costs, timing of decommissioning, or the assumptions
underlying these estimates could cause material revisions to the estimated total
cost to decommission in the near term. SCE estimates that it will spend
approximately $8.6 billion through 2060 to decommission its nuclear facilities.
This estimate is based on SCE's current dollar decommissioning costs, escalated
at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.
These costs are expected to be funded from independent decommissioning trusts,
which, effective June 1999, receive contributions of approximately $25 million
per year. SCE estimates annual after-tax earnings on the decommissioning funds
of 3.9% to 4.9%.
SCE plans to decommission its nuclear generating facilities by a prompt removal
method authorized by the Nuclear Regulatory Commission. The operating licenses
expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo
Verde units. SCE could decommission San Onofre Units 2 and 3 as early as 2013.
Palo Verde is planned to be decommissioned at the end of its operating license.
Decommissioning costs, which are recovered through nonbypassable customer rates
over the term of each nuclear facility's operating license, are recorded as a
component of depreciation expense.
Decommissioning of San Onofre Unit 1 (shut down in 1992 per CPUC agreement)
started in 1999 and will continue through 2008. All of SCE's San Onofre Unit 1
decommissioning costs will be paid from its nuclear decommissioning trust funds.
Decommissioning expense was $106 million in 2000, $124 million in 1999 and $164
million in 1998. The accumulated provision for decommissioning, excluding San
Onofre Unit 1 and unrealized holding gains, was $1.4 billion at December 31,
2000, and $1.3 billion at December 31, 1999. The estimated costs (recorded as a
liability) to decommission San Onofre Unit 1 is approximately $342 million as of
December 31, 2000.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
55
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Trust investments (cost basis) include:
Maturity
- ------------------------------------------------------------------------------------------------------------------
In millions Dates December 31, 2000 1999
- ------------------------------------------------------------------------------------------------------------------
Municipal bonds 2001--2034 $ 548 $ 684
Stocks -- 531 482
U.S. government issues 2001--2029 421 351
Short-term and other 2001 220 133
- ------------------------------------------------------------------------------------------------------------------
Total $ 1,720 $1,650
- ------------------------------------------------------------------------------------------------------------------
Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $38
million in 2000, $58 million in 1999 and $63 million in 1998. Proceeds from
sales of securities (which are reinvested) were $4.7 billion in 2000, $2.6
billion in 1999 and $1.2 billion in 1998. Approximately 90% of the trust fund
contributions were tax-deductible.
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase. Certain SCE gas and coal fuel contracts require payment
of certain fixed charges whether or not gas or coal is delivered.
SCE has power-purchase contracts with certain qualifying facilities
(cogenerators and small power producers) and other utilities. These contracts
provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There are
no requirements to make debt-service payments. As a result of the utility
industry restructuring, SCE has entered into purchased-power settlements to end
its contract obligations with certain qualifying facilities. The settlements are
reported as power purchase contracts on the balance sheets.
SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another utility.
Minimum payments are based, in part, on the debt-service requirements of the
provider, whether or not the plant or transmission line is operable. SCE's
minimum commitment under both contracts is approximately $159 million through
2017. The purchased-power contract is expected to provide approximately 5% of
current or estimated future operating capacity, and is reported as power
purchase contracts (approximately $31 million). The transmission service
contract requires a minimum payment of approximately $6 million a year.
Certain commitments for the years 2001 through 2005 are estimated below:
In millions 2001 2002 2003 2004 2005
- -------------------------------------------------------------------------------------------------------------------
Fuel supply contracts $150 $107 $115 $ 97 $ 97
Purchased-power capacity payments 647 644 637 635 632
- -------------------------------------------------------------------------------------------------------------------
SCE's projected construction expenditures for 2001 total approximately $602
million. The construction program is subject to periodic review and revision,
and actual construction costs may vary from estimates because of numerous
factors.
Note 12. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in other
legal, tax and regulatory proceedings before various courts and governmental
agencies regarding matters arising in the ordinary course of business. SCE
believes the outcome of these other proceedings will not materially affect its
results of operations or liquidity.
56
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Southern California Edison Company
Energy Crisis Issues
In December 2000, a first amended complaint to a class action securities lawsuit
(originally filed in October 2000) was filed in federal district court in Los
Angeles against SCE and Edison International. On March 5, 2001, a second amended
complaint was filed that alleges that SCE and Edison International are engaging
in fraud by over-reporting and improperly accounting for the TRA
undercollections. The second amended complaint is supposedly filed on behalf of
a class of persons who purchased Edison International common stock beginning
June 1, 2000, and continuing until such time as TRA-related undercollections are
recorded as a loss on SCE's income statement. The response to the second amended
complaint was due April 2, 2001. The response has been deferred pending
resolution of motions to consolidate this lawsuit with another lawsuit filed on
March 15, 2001. SCE believes that its current and past accounting for the TRA
undercollections and related items is appropriate and in accordance with
accounting principles generally accepted in the United States.
As of April 13, 2001, 17 additional lawsuits have been filed against SCE by QFs.
The lawsuits have been filed by various parties, including geothermal or wind
energy suppliers or owners of cogeneration projects. The lawsuits are seeking
payments of at least $420 million for energy and capacity supplied to SCE under
QF contracts, and in some cases for damages as well. Many of these QF lawsuits
also seek an order allowing the suppliers to stop providing power to SCE and
sell the power to other purchasers. SCE is seeking coordination of all of the
QF-related lawsuits that have commenced in various California courts. On April
13, 2001, an order was issued assigning all pending cases to a coordination
motion judge and setting a hearing on SCE's coordination petition by May 30,
2001. SCE cannot predict the outcome of any of these matters.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
SCE records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site using
currently available information, including existing technology, presently
enacted laws and regulations, experience gained at similar sites, and the
probable level of involvement and financial condition of other potentially
responsible parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure. Unless
there is a probable amount, SCE records the lower end of this reasonably likely
range of costs (classified as other long-term liabilities at undiscounted
amounts).
SCE's recorded estimated minimum liability to remediate its 44 identified sites
is $114 million. The ultimate costs to clean up SCE's identified sites may vary
from its recorded liability due to numerous uncertainties inherent in the
estimation process, such as: the extent and nature of contamination; the
scarcity of reliable data for identified sites; the varying costs of alternative
cleanup methods; developments resulting from investigatory studies; the
possibility of identifying additional sites; and the time periods over which
site remediation is expected to occur. SCE believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed its
recorded liability by up to $272 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. SCE has sold all of its gas-fueled generation
plants and has retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites,
representing $45 million of its recorded liability, through an incentive
mechanism. Under this mechanism, SCE will recover 90% of
57
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Notes to Consolidated Financial Statements
cleanup costs through customer rates; shareholders fund the remaining 10%, with
the opportunity to recover these costs from insurance carriers and other third
parties. SCE has successfully settled insurance claims with all responsible
carriers. Costs incurred at SCE's remaining sites are expected to be recovered
through customer rates. SCE has recorded a regulatory asset of $75 million for
its estimated minimum environmental-cleanup costs expected to be recovered
through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can now be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation expenditures in each of the next several years are expected to range
from $5 million to $15 million. Recorded expenditures for 2000 were $13 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from
this secondary level, effective June 1994. The maximum deferred premium for each
nuclear incident is $88 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its ownership
interests, SCE could be required to pay a maximum of $175 million per nuclear
incident. However, it would have to pay no more than $20 million per incident in
any one year. Such amounts include a 5% surcharge if additional funds are needed
to satisfy public liability claims and are subject to adjustment for inflation.
If the public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million also has been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued by a mutual insurance company owned by
utilities with nuclear facilities. If losses at any nuclear facility covered by
the arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up to $19
million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the DOE is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste.
Such a facility was to be in operation by
58
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Southern California Edison Company
January 1998. However, the DOE did not meet its obligation. It is not certain
when the DOE will begin accepting spent nuclear fuel from San Onofre or from
other nuclear power plants.
SCE, as operating agent, has primary responsibility for the interim storage of
its spent nuclear fuel at San Onofre. Current capability to store spent fuel is
estimated to be adequate through 2005. SCE has not determined the costs for
spent-fuel storage beyond that period, which would require new and separate
interim storage facilities. Extended delays by the DOE could lead to
consideration of costly alternatives involving siting and environmental issues.
SCE has paid the DOE the required one-time fee applicable to nuclear generation
at San Onofre through April 6, 1983 (approximately $24 million, plus interest).
SCE is also paying the required quarterly fee equal to one mill per
kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003
for Unit 2, and until 2004 for Units 1 and 3. Arizona Public Service Company,
operating agent for Palo Verde, is constructing an interim fuel storage facility
that is expected to be completed in 2002.
- -------------------------------------------------------------------------------------------------------------------
Quarterly Financial Data
2000 1999
------------------------------------------ -----------------------------------------
In millions Total Fourth Third Second First Total Fourth Third Second First
- -------------------------------------------------------------------------------------------------------------------
Operating revenue $7,870 $1,755 $2,432 $1,853 $1,830 $7,548 $1,827 $2,310 $1,726 $1,685
Operating income (loss) (1,652) (2,402) 273 250 227 855 224 257 198 176
Net income (loss) (2,028) (2,485) 177 161 119 509 146 168 112 83
Net income (loss) available for
common stock (2,050) (2,491) 172 156 113 484 141 160 106 77
Common dividends declared 279 -- 92 91 96 666 117 269 111 169
- -------------------------------------------------------------------------------------------------------------------
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59
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Responsibility for Financial Reporting
The management of Southern California Edison Company (SCE) is responsible for
the integrity and objectivity of the accompanying financial statements. The
statements have been prepared in accordance with accounting principles generally
accepted in the United States and are based, in part, on management estimates
and judgment.
SCE maintains systems of internal control to provide reasonable, but not
absolute, assurance that assets are safeguarded, transactions are executed in
accordance with management's authorization and the accounting records may be
relied upon for the preparation of the financial statements. There are limits
inherent in all systems of internal control, the design of which involves
management's judgment and the recognition that the costs of such systems should
not exceed the benefits to be derived. SCE believes its systems of internal
control achieve this appropriate balance. These systems are augmented by
internal audit programs through which the adequacy and effectiveness of internal
controls and policies and procedures are monitored, evaluated and reported to
management. Actions are taken to correct deficiencies as they are identified.
SCE's independent public accountants, Arthur Andersen LLP, are engaged to audit
the financial statements in accordance with auditing standards generally
accepted in the United States and to express an informed opinion on the
fairness, in all material respects, of SCE's reported results of operations,
cash flows and financial position.
As a further measure to assure the ongoing objectivity of financial information,
the audit committee of the Board of Directors, which is composed of outside
directors, meets periodically, both jointly and separately, with management, the
independent public accountants and internal auditors, who have unrestricted
access to the committee. The committee recommends annually to the Board of
Directors the appointment of a firm of independent public accountants to conduct
audits of its financial statements; considers the independence of such firm and
the overall adequacy of the audit scope and SCE's systems of internal control;
reviews financial reporting issues; and is advised of management's actions
regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing personnel to
assure that its operations are conducted in conformity with applicable laws and
is committed to maintaining the highest standards of personal and corporate
conduct. Management maintains programs to encourage and assess compliance with
these standards.
/s/ Thomas M. Noonan /s/ Stephen E. Frank
Thomas M. Noonan Stephen E. Frank
Vice President Chairman of the Board, President
and Controller and Chief Executive Officer
April 12, 2001
60
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Report of Independent Public Accountants Southern California Edison Company
To the Shareholders and the Board of Directors,
Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE, a California corporation) and its subsidiaries
as of December 31, 2000, and 1999, and the related consolidated statements of
income (loss), comprehensive income (loss), cash flows and changes in common
shareholder's equity for each of the three years in the period ended December
31, 2000. These financial statements are the responsibility of SCE's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of SCE and its subsidiaries as of
December 31, 2000, and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States.
The accompanying financial statements have been prepared assuming that SCE will
continue as a going concern. As discussed in Notes 2 and 3 to the consolidated
financial statements, the current energy crisis in California has resulted in
SCE incurring a loss from operations in the current year due to the uncertainty
associated with its ability to collect certain costs through the regulatory
process and has resulted in legal, regulatory and legislative uncertainties
which have adversely impacted SCE's liquidity. These issues raise substantial
doubt about SCE's ability to continue as a going concern. Management's plans in
regard to these matters are also described in Notes 2 and 3. The financial
statements do not include any adjustments relating to the recoverability and
classification of asset carrying amounts or the amount and classification of
liabilities that might result should SCE be unable to continue as a going
concern.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
April 12, 2001
61
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Board of Directors Southern California Edison Company
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Warren Christopher Charles D. Miller Robert H. Smith
Senior Partner, Retired Chairman of the Board, Managing Director,
O'Melveny & Myers, Avery Dennison Corporation, Smith and Crowley Incorporated,
Los Angeles, California Pasadena, California Pasadena, California
Stephen E. Frank Luis G. Nogales Thomas C. Sutton
Chairman of the Board, President and President, Chairman of the Board and
Chief Executive Officer, Nogales Partners, Chief Executive Officer
Southern California Edison Company Los Angeles, California Pacific Life Insurance Company,
Newport Beach, California
Joan C. Hanley Ronald L. Olson
The Former General Partner and Manager, Senior Partner, Daniel M. Tellep
Miramonte Vineyards, Munger, Tolles and Olson, Retired Chairman of the Board,
Rancho Palos Verdes, California Los Angeles, California Lockheed Martin Corporation,
Bethesda, Maryland
Carl F. Huntsinger James M. Rosser Edward Zapanta, M.D.
General Partner, President, Physician and Neurosurgeon,
DAE Limited Partnership Ltd., California State University, Los Angeles, Torrance, California
Ojai, California Los Angeles, California
- -------------------------------------------------------------------------------------------------------------------
Management Team
- -------------------------------------------------------------------------------------------------------------------
Stephen E. Frank Robert C. Boada Dwight E. Nunn
Chairman of the Board, President and Vice President and Treasurer Vice President, Nuclear Engineering
Chief Executive Officer and Technical Services
Clarence Brown
Harold B. Ray Vice President, Stephen E. Pickett
Executive Vice President, Corporate Communications Vice President and General Counsel
Generation Business Unit
Bruce C. Foster Frank J. Quevedo
Pamela A. Bass Vice President, Vice President,
Senior Vice President, San Francisco Regulatory Operations Equal Opportunity
Customer Service Business Unit
A.L. Grant Joseph P. Ruiz
John R. Fielder Vice President, Engineering and Vice President and General Auditor
Senior Vice President, Technical Services
Regulatory Policy and Affairs W. James Scilacci
Lawrence D. Hamlin Vice President and
Robert G. Foster Vice President, Power Production Chief Financial Officer
Senior Vice President,
External Affairs Harry B. Hutchison Dale E. Shull, Jr.
Vice President, Vice President, Power Delivery
Richard M. Rosenblum Mass Customers
Senior Vice President, Anthony L. Smith
Transmission and Distribution James A. Kelly Vice President, Tax
Business Unit Vice President,
Regulatory Affairs David Ned Smith
Mahvash Yazdi Vice President, Major Customers
Senior Vice President and Russell W. Krieger
Chief Information Officer Vice President, Joseph J. Wambold
Nuclear Generation Vice President, Nuclear Business abd
Support Services
Emiko Banfield Michael J. Mendez
Vice President, Vice President, Labor Relations Beverly P. Ryder
Shared Services Secretary
Thomas M. Noonan
Vice President and Controller
62
Shareholder Information
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Annual Meeting of Shareholders
Monday, May 14, 2001
1:30 p.m.
DoubleTree Hotel Ontario
222 N. Vineyard Avenue
Ontario, California 91764
- -------------------------------------------------------------------------------
Stock Listing and Trading Information
SCE Preferred Stock
SCE's preferred stocks are listed on the American and Pacific stock exchanges
under the ticker symbol SCE. Previous day's closing prices, when traded, are
listed in the daily newspapers in the American Stock Exchange composite table.
The 6.05%, 6.45% and 7.23% series are not listed.
Where to Buy and Sell Stock
The listed preferred stocks may be purchased through any brokerage firm. Firms
handling unlisted series can be located through your broker.
- -------------------------------------------------------------------------------
Transfer Agent and Registrar
Wells Fargo Bank Minnesota, N.A. maintains shareholder records and is the
transfer agent and registrar for SCE preferred stock. Shareholders may call
Wells Fargo Shareowner Services, (800) 347-8625, between 7:00 a.m. and 7:00 p.m.
(Central Time), Monday through Friday, regarding:
o stock transfer and name-change requirements;
o address changes, including dividend addresses;
o electronic deposit of dividends;
o taxpayer identification number submission or changes;
o duplicate 1099 forms and W-9 forms;
o notices of, and replacement of, lost or destroyed stock certificates and
dividend checks; and
o requests for access to online account information.
The address of Wells Fargo Shareowner Services is:
161 North Concord Exchange Street
South St. Paul, MN 55075-1139
FAX: (651) 450-4033
E-mail: [email protected]
SCE Web Address:
www.edisoninvestor.com
Southern California Edison Company
2244 Walnut Grove Avenue
Rosemead, California 91770
(626) 302-1212