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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, 1998
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 (Zip Code) including area code)
offices)
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 4.78% Series
4.24% Series 5.80% Series
4.32% 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. [X]
As of March 19, 1999 there 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 $355,326,761 on or about March 19, 1999 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 March 19, 1999, were as follows:
CUMULATIVE PREFERRED STOCK $99,626,761; $100 CUMULATIVE PREFERRED STOCK
$255,700,000.
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, 1998................................... Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 1999 Annual Meeting
of Shareholders..................................... Part III
TABLE OF CONTENTS
Item Page
Part I
1. Business......................................................... 1
Competitive Environment..................................... 1
California Electric Utility Restructuring................... 1
Regulation ................................................. 4
Rate Matters................................................ 5
Fuel Supply and Purchased Power Costs....................... 10
Environmental Matters....................................... 11
Year 2000 Issue............................................. 14
2. Properties....................................................... 14
Existing Generating Facilities.............................. 14
Construction Program and Capital Expenditures............... 16
Nuclear Power Matters....................................... 16
3. Legal Proceedings................................................ 19
Wind Generators' Litigation................................. 19
Geothermal Generators' Litigation........................... 19
Electric and Magnetic Fields (EMF) Litigation............... 20
San Onofre Personal Injury Litigation....................... 21
Mohave Generating Station Environmental Litigation.......... 21
4. Submission of Matters to a Vote of Security Holders.............. 22
Executive Officers of the Registrant............................. 22
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters.............................................. 25
6. Selected Financial Data.......................................... 25
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition............................... 25
7a. Quantitative and Qualitative Disclosures About Market Risk....... 25
8. Financial Statements and Supplementary Data...................... 25
9. Changes in and Disagreements with Accountants
Accounting and Financial Disclosure.............................. 25
Part III
10. Directors and Executive Officers of the Registrant............... 25
11. Executive Compensation........................................... 26
12. Security Ownership of Certain Beneficial
Owners and Management............................................ 26
13. Certain Relationships and Related Transactions................... 26
Part IV
14. Exhibits, Financial Statement Schedules, and
Financial Reports........................................... 26
Reports on Form 8-K......................................... 27
Report of Independent Public Accountants on
Supplemental Schedules...................................... 28
Supplemental Schedules...................................... 29
Signatures.................................................. 32
Exhibit Index............................................... 33
PART I
In this form 10-K, Southern California Edison Company (SCE) uses the words
estimates, expects, anticipates, believes, and other similar expressions that
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 further actions by state and federal regulatory bodies
that sets rates and implement the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business, including the beginning of direct customer access to retail energy
suppliers and the unbundling of revenue cycle services such as metering and
billing; changes in prices of electricity and fuel costs; changes in market
interest rates; new or increased environmental liabilities; the effects of the
Year 2000 on computers; and other unforeseen events.
Item 1. Business
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. This area includes approximately 800
cities and communities and a population of more than 11 million people. SCE had
13,177 full-time employees at year-end 1998. During 1998, 31% of SCE's total
operating revenue was derived from residential customers, 33% from commercial
customers, 15% from sales to the power exchange (PX), 9% from industrial
customers, 6% from public authorities, 5% from agricultural and other customers
and 1% from resale customers. SCE comprises the major portion of the assets and
revenue of its parent holding company, Edison International.
Competitive 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. This regulatory environment is changing.
In the generation sector, SCE has experienced competition from nonutility power
producers; and regulators are restructuring California's electric utility
industry to facilitate additional competition. (See "Business of SCE --
California Electric Restructuring" below for a description of these changes.)
California Electric Utility Restructuring
Restructuring Decision -- The CPUC's December 1995 decision on restructuring
California's electric utility industry started the transition to a new market
structure; competition and customer choice began on April 1, 1998. Key elements
of the CPUC's restructuring decision included: creation of the PX and
Independent System Operator (ISO); availability of customer choice for
electricity supply and certain billing and metering services; performance-based
ratemaking (PBR) for those utility services not subject to competition;
voluntary divestiture of at least 50% of utilities' gas-fueled generation; and
implementation of the Competition Transition Charge (CTC).
Restructuring Statute -- In September 1996, the State of California enacted
legislation, Assembly Bill 1890 (AB 1890), to provide a transition to a
competitive market structure. The statute substantially adopted the CPUC's
restructuring decision by addressing stranded-cost recovery for utilities and
providing a certain cost-recovery time period for the transition costs
associated with utility-owned generation-related assets. The statute mandated
the implementation of the CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Transition costs
related to power-purchase contracts are being recovered through the terms of
their contracts while most of the remaining transition costs will be recovered
through 2001. SCE expects to be able to recover its revenue requirement during
the 1998-2001 transition period. The statute also contained provisions for
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the recovery (through 2006) of reasonable employee-related transition costs,
incurred and projected, for retraining, severance, early retirement,
outplacement, and related expenses.
Rate Reduction Notes -- In December 1997, after receiving approval from both 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. The remaining notes consist of six
classes with maturities ranging from one to nine years, and bear interest
ranging from 6.14% to 6.42%.
On November 3, 1998, California voters rejected the voter initiative designated
as Proposition 9. Approximately 73% of the total votes cast were voted against
the proposition. Proposition 9 would have prohibited the collection of the
non-bypassable charges for the payment of the rate reduction notes and would
have severely restructured SCE's recovery of transition costs.
1998 Activities -- During 1998, SCE implemented changes to comply with the
restructuring elements required by the CPUC and with the restructuring statute.
Beginning January 1, 1998:
o SCE's rates were unbundled into separate charges for energy, transmission,
distribution, the CTC, public benefit programs, and nuclear
decommissioning. The transmission component is being collected through
FERC-approved rates, subject to refund.
o SCE's costs associated with hydroelectric plants are being recovered
through a performance-based mechanism. The mechanism sets the hydroelectric
revenue requirements and establishes a formula for the duration of the
electric industry restructuring transition period, or until market
valuation of the hydroelectric facilities, whichever occurs first. The
mechanism provides that power sales revenue from hydroelectric facilities
in excess of the hydroelectric revenue requirement be credited against the
costs of transition to a competitive market environment.
o SCE's transition costs are being recovered through a non-bypassable CTC.
This charge applies to all customers who were using or began using utility
services on or after the CPUC's December 1995 restructuring decision date.
SCE has estimated transition costs to be approximately $10.6 billion (1998
net present value) from 1998 through 2030. This estimate is based on
incurred costs, forecasts of future costs, and assumed market prices.
Changes in the assumed market prices could materially affect these
estimates. Potential transition costs are comprised of $6.4 billion from
SCE's qualifying facilities contracts, which resulted from prior
legislative and regulatory mandates, and $4.2 billion (including the
effects of the sale of SCE's gas- and oil- fueled generation plants) from
costs pertaining to certain generating assets and regulatory commitments
consisting of costs incurred (whose recovery has been deferred by the CPUC)
from providing service to customers. Such commitments include the recovery
of income tax benefits previously flowed through to customers,
postretirement benefit transition costs, accelerated recovery of San Onofre
Units 2 and 3 and the Palo Verde units, and certain other costs. The issue
was separated into two phases; Phase 1 addressed the rate-making issues and
Phase 2 addressed the quantification issues.
o Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the
establishment of a transition cost balancing account and annual transition
cost proceedings; the setting of a market rate forecast for 1998 transition
costs; the requirement that generation-related regulatory assets be
amortized ratably over a 48-month period; the establishment of calculation
methodologies and procedures for SCE to collect its transition costs from
1998 through the end of the rate freeze; and the reduction of SCE's
authorized rate of return on certain assets eligible for transition cost
recovery (primarily fossil- and hydroelectric-generation related assets)
beginning July 1997, five months earlier than anticipated. SCE has filed an
application for
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rehearing on the 1997 rate of return issue. The CPUC recently issued a
decision agreeing in part with SCE. Although a lower rate of return was
applied to the hydro and fossil assets for the period July 28, 1997
through November 21, 1997, the return was set at 7.35% rather than the
7.22% that was adopted in the earlier decision. This increase will result
in an additional $425,000 in earnings compared to the original decision.
o Residential and small commercial customers who have begun receiving a 10%
rate reduction are repaying the rate reduction notes issued in December
1997 through non-bypassable charges based on electricity consumption. (See
"California Electric Utility Restructuring-Rate Reduction Notes" above for
additional discussion.)
Effective April 1, 1998:
o The ISO assumed operational control of the transmission system on March 31,
1998, after the ISO and PX began accepting bids and schedules for
electricity purchases. The restructuring implementation costs related to
the start-up and development of the PX, which are paid by the utilities,
will be recovered from all retail customers over the four-year transition
period. SCE's share of the charge is $45 million, plus interest and fees.
SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a ten-year period.
o Customers can choose to purchase energy from new retailers called Electric
Service Providers (ESPs). As of December 31, 1998, approximately 47,000
customers are purchasing their energy from ESPs. All other customers are
purchasing energy from SCE, and SCE is in turn purchasing the energy it
supplies to them from the PX. Regardless of whom the customers choose to
supply their energy, SCE provides transmission and distribution services to
all customers within its service territory. All customers of SCE
transmission and distribution services also are paying the CTC, regardless
of their choice of energy supplier.
o Customers have options regarding metering, billing, and related services
(referred to as revenue cycle services) provided by California's
investor-owned utilities. ESPs can provide their customers with one
consolidated bill for their services and the utility's services, request
the utility to provide such a consolidated bill to the customer, or elect
to have both the ESP and the utility bill for respective charges. Customers
with maximum demand above 20 kWh (primarily industrial and medium and large
commercial) can choose SCE or any other supplier to provide their metering
service. Beginning in January 1999, all customers may make these choices.
SCE may experience a reduction in revenue security as a result of this
unbundling.
o In September 1998, the CPUC issued a decision requiring SCE to provide
credits beginning on January 1, 1999, to customers who elect to obtain
revenue cycle services from an ESP. The credits are based on the net cost
savings to SCE as a result of no longer providing these services. The CPUC,
however, has also begun a proceeding to consider whether the RCS credits
should be increased to reflect the prices likely to prevail in a
competitive market for RCS services. If the CPUC adopts credits based on
this premise, SCE has advocated that the resulting difference between
payments for the credits and costs actually avoided be recovered from all
customers in a competitively neutral manner.
During 1998, SCE sold all of its gas- and oil- fueled generation plants. The
total sales price of the 12 plants was $1.2 billion, over $500 million more than
the combined book value. Net proceeds of the sales were used to reduce stranded
costs, which otherwise were expected to be collected through the CTC mechanism.
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described above, SCE would be allowed to recover
its transition costs through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be subject
to a lower authorized rate of return). In 1997, SCE discontinued application of
accounting principles for rate-regulated enterprises for its investment in
generation facilities based on new
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accounting guidance. The financial reporting effect of this discontinuance was
to segregate these assets on the balance sheet; the new guidance did not require
SCE to write off any of its generation-related assets, including related
regulatory assets. However, the new guidance did not specifically address the
application of asset impairment standards to these assets. SCE has retained
these assets on its balance sheet because AB 1890 and the restructuring plan
referred to above make probable their recovery through a non-bypassable CTC to
distribution customers. The regulatory assets relate primarily to the recovery
of accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments, and unamortized losses on
reacquired debt. The new accounting guidance also permits the recording of new
generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording 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 future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that make the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.4
billion, after tax, at December 31, 1998) as a one-time, non-cash charge against
earnings.
If events occur during the restructuring process that result in all or a portion
of the transition costs being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other revisions will
ultimately be made during the restructuring process in subsequent proceedings or
the effect, after the transition period, that competition will have on its
results of operations or financial position.
Transmission Owners Tariff and Wholesale Distribution Access Tariff -- On March
31, 1997, SCE filed a transmission owners tariff with the FERC, in conjunction
with the ISO and PX tariffs, also filed on that date. Together, these tariffs
set forth the rate design and terms and conditions for transmission service
provided over SCE's facilities over which the ISO will have operational control.
The transmission owners tariff also sets forth SCE's proposed transmission
access charge. Additionally, on March 31, 1997, SCE filed a wholesale
distribution access tariff. The FERC accepted the tariffs for filing, subject to
refund, effective April 1, 1998.
Regulation
SCE's retail operations are subject to regulation by the CPUC. The CPUC has the
authority to regulate, among other things, retail rates, issuances 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 transmission service pricing, accounting
practices, and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the 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
4
handling and disposal of hazardous materials and wastes. SCE is also subject to
regulation by the 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 Units 2 and 3. Although the units are operating, the
permit's mitigation requirements have not yet been fulfilled. 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.
The Department of Energy (DOE) has regulatory authority over certain aspects of
SCE's operations and business relating to energy conservation, solar energy
development, power plant fuel use and disposal, coal conversion, electric sales
for export, public utility regulatory policy, and natural gas pricing.
On December 16, 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. On December 31, 1997, SCE filed a preliminary
compliance plan which set forth SCE's implementation of the new affiliate
transaction rules. This preliminary compliance plan was supplemented by an
additional filing made on January 30, 1998. In September 1998, the CPUC issued a
Resolution accepting certain portions of SCE's compliance plan and rejecting
others. SCE filed a revised compliance plan in October 1998 as ordered. No party
protested that revised plan.
The new affiliate transaction rules apply to all utility transactions, including
electric utilities, with affiliates engaging in the production of products that
use electricity or the providing of services that relate to the use of
electricity. Edison International is not subject to these new affiliate
transaction rules and continues to be subject to the prior rules. The new
affiliate transaction rules are structured to address CPUC concerns regarding
market power and cross-subsidization arising out of the new competitive
electricity market in California. The new rules are categorized into
nondiscrimination standards, disclosure and information standards, and
separation standards. The new rules also set forth requirements and restrictions
on the utility's offering of certain products and services.
The CPUC has modified certain of the rules in response to petitions from various
parties. SCE is still awaiting CPUC decisions on its compliance plan (which
includes SCE's interpretation of the rule governing affiliate use of the
utility's name and logo, on a petition for limited exemptions from that rule,
and on SCE's filing relating to utility products and services that produce other
operating revenue. The CPUC decision concerning the name and logo rule may
affect the disposition of a pending complaint against SCE filed by the CPUC's
Office of Ratepayer Advocates (ORA) and The Utility Reform Network with the
CPUC, which complaint alleges a violation of that rule by Edison Source in a
bulk mailing in 1998.
SCE has not yet been materially affected by the new affiliate transaction rules,
and it projects that the rules will not materially affect its results of
operation or its financial position in the future.
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 California Electric Utility
Restructuring, the nature in which the CPUC regulates SCE is changing. The CPUC
has issued final decisions regarding direct access, transition cost recovery,
and rate unbundling in the restructuring of the electric industry. In 1998,
these decisions affected cost recovery and rate regulation, and authorized new
ratemaking mechanisms which were implemented,
5
replacing the Electric Revenue Adjustment Mechanism, Energy Cost Adjustment
Clause (ECAC) and base rates mechanism (collectively, the "pre-restructuring
ratemaking mechanisms") described in prior annual and quarterly reports filed
with the SEC.
Total rates for all customers are frozen at June 10, 1996 levels, although
residential and small commercial customers have received a 10% reduction from
the June 10, 1996 rate levels beginning on January 1, 1998. These rate levels
will remain in effect for the remainder of the transition period. 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 Commission directives
to: 1) consolidate authorized rates and revenue requirements associated with
various proceedings and mechanisms; 2) verify the residual CTC revenue
calculation in the Transition Revenue Account; 3) verify the regulatory account
balances which were transferred to the TCBA on January 1, 1998; 4) streamline
certain balancing and memorandum accounts; and 5) review the PX charge/credit
calculation. SCE anticipates a final 1998 RAP decision in the second quarter of
1999.
The CPUC is considering unbundling SCE's cost of capital based on major utility
functions. In May 1998, SCE filed an application on this issue and hearings were
completed in October 1998. A CPUC decision is expected in early to mid 1999.
Distribution Rates
Distribution cost recovery is made through a distribution PBR mechanism
currently authorized 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
bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders will
share gains and losses from distribution operations. (See "California Electric
Utility Restructuring-1998 Activities" above for additional discussion.)
Transmission Rates
With the commencement of the ISO and PX on March 31, 1998, transmission cost
recovery is now under FERC authority. Prior to such commencement, transmission
cost recovery was combined with distribution cost recovery through a
transmission and distribution PBR mechanism.
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.
Generation Rates
Effective with the commencement of the ISO and PX operations, generation costs
are subject to recovery through the market price and the CTC. Revenue available
to recover the uneconomic generation costs subject to recovery through the CTC
will be determined residually by subtracting the other rate components from the
total rates. This residual revenue will first be allocated to recovery of
FERC-authorized ISO charges for transmission support and for purchases from the
PX, and then to recovery of transition costs. Transition costs associated with
QF (Qualifying Facilities) and interutility contracts and the acceleration of
sunk cost recovery will be subject to annual reasonableness review by the CPUC.
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Transition cost recovery for most utility generation assets will terminate on
the earlier of March 31, 2002, or when these costs are fully collected. (See
"California Electric Utility Restructuring-1998 Activities" above for additional
discussion.)
Annual Transition Cost Proceeding (ATCP)
In 1997, the CPUC established the ATCP as the proceeding to determine whether
SCE's Transition Cost Balancing Account (TCBA) entries are recorded pursuant to
applicable CPUC decisions and AB 1890, and that certain expenses are justified.
This proceeding includes matters that for periods prior to July 1, 1998, were
considered by the CPUC pursuant to ECAC proceedings. (See "Annual Energy Cost
Adjustment Clause Proceedings" below for additional discussion.)
On September 1, 1998, SCE filed its first ATCP Report with the CPUC and
requested 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 Commission
decisions and AB 1890. In addition, SCE requested the Commission to find for the
record period that SCE's: 1) purchased power contract administration is
justified; 2) coal contract costs are justified; 3) gas fuel procurement and
management activities are justified; 4) recorded employee-related costs are
justified; 5) proposal for retaining or eliminating generation-related balancing
and memorandum accounts is justified; and 6) jurisdictional allocation of
transition costs and other generation-related costs should be based upon
recorded kWh. SCE anticipates a final 1998 ATCP decision in December, 1999.
Recovery of Restructuring Implementation Costs
The legislature, recognizing that costs accommodating the implementation of
direct access, the ISO, and the PX would have to be recovered from within the
rates that were frozen at June 1996 levels by other provisions of AB 1890,
provided a mechanism to insure that such recovery could occur without impairing
the utilities' ability to recover their stranded costs from within frozen rates.
This mechanism is contained in Section 376 of the Public Utilities Code. In May
1998, Edison filed an application with the CPUC to identify the categories of
costs which satisfy the conditions of Section 376, and to establish the
reasonableness of those costs incurred in 1997. The CPUC split the application
into two phases. Evidentiary hearings on Phase 1, which addressed the
eligibility of cost categories for recovery pursuant to Section 376, concluded
in November 1998. A proposed decision on Phase 1 was issued by the
administrative law judge (ALJ) on March 11, 1999, accompanied by an alternate
decision drafted by the assigned commissioner in the proceeding. The alternate
decision differs in only minor respects from that of the ALJ. Neither of these
decisions is binding on any party until acted upon by the full CPUC, which may
adopt one or the other of these proposed decisions, modify them, or issue an
entirely new decision. Both of these proposed decisions reject SCE's request for
a determination of eligibility under Section 376 for several major categories of
costs. These proposed decisions further state that even for the cost categories
they approve for Section 376 eligibility, costs incurred in those categories
after December 31, 1998 would not be eligible. Instead, these proposed decisions
would have SCE recover many of the costs identified in its application from
"market revenues," although the decisions fail to identify that market and no
specific mechanism or authority to recover such costs from any market has yet
been established. SCE disagrees with much of the conclusions reached in these
proposed decisions and will file comments to that effect. A final decision from
the CPUC is currently scheduled for April 22, 1999, but may be delayed beyond
that date. Under both of the proposed decisions, the reasonableness of 1997 and
1998 expenditures for eligible costs under Section 376 would be addressed in a
separate application later this year.
Annual Energy Cost Adjustment Clause Proceedings
Ending in 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. These matters are respectively referred to herein as "non-QF
matters" and "QF matters."
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QF MATTERS
In a decision issued in September 1998, the CPUC found SCE's administration of
QF contracts and payments to QF projects (hereinafter referred to as "SCE's QF
activities") for the 1992 ECAC to be reasonable. Review of purchases from three
QF projects were deferred because of a pending civil proceeding. The 1992 ECAC
was closed, subject to a petition to reopen or modify the decision regarding the
deferred QF projects.
The 1993 through 1997 ECAC applications were consolidated for purposes of
reviewing QF activities for these years. ORA issued its review in two different
reports in 1998. ORA contested only the reasonableness of SCE's administration
of one QF contract known as the Arbutus project. ORA claimed $3.6 million should
be disallowed from recovery. On January 21, 1999 an administrative law judge
(ALJ) issued a decision finding SCE's actions with respect to the administration
of the Arbutus contract to be reasonable. The ALJ also confirmed a disallowance
of $16.3 million related to the Mojave Cogeneration Company project for the
years 1992 through 1997. On March 4, 1999, the CPUC issued its decision,
upholding the recommendations of the ALJ. Accordingly, SCE will credit its
Electric Deferred Refund Account in the amount of $16.3 million, plus applicable
interest, within 30 calendar days after the effective date of the decision. Any
recovery SCE receives from the Arbutus bankruptcy proceeding will be credited to
SCE's TCBA. This decision closes the 1993, 1994, 1995, 1996, and 1997
Applications, subject to being reopened for the limited purpose of considering
issues related to the three projects deferred from the 1992 ECAC proceeding.
ORA issued its report on the 1998 ECAC period on February 19, 1999. ORA did not
identify any reasonableness issues associated with SCE's QF activities during
the 1998 period.
NON-QF MATTERS
1994 Annual ECAC Record Period
SCE filed its non-QF Reasonableness of Operations Report on May 27, 1994 for the
period April 1, 1993 through March 31, 1994. This report addresses power
purchases and exchanges, and the operation of hydroelectric, coal, gas, and
nuclear resources. The non-QF issues were bifurcated, with the gas procurement
issues being separated from other non-QF issues. On August 2, 1996, the CPUC
issued a decision finding that SCE's non-QF, non-gas procurement activities were
reasonable.
ORA recommended a $13.3 million disallowance for costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas supply and
transportation contracts.
On October 17, 1996, the ALJ granted ORA's motion to consolidate the 1994 and
1995 record periods for the limited purpose of addressing the gas reasonableness
issues.
On July 11, 1997, ORA and SCE executed a Settlement Agreement. The basic
elements of the settlement include: 1) a $39 million disallowance for Canadian
gas costs incurred through December 31, 1996; 2) a disallowance of $257,000 per
month, per contract, for each of SCE's four supply contracts for Canadian gas
costs beginning after January 1, 1997, and continuing until each of the
commodity contracts are terminated (one supply agreement was terminated on May
1, 1997, and the remaining three supply agreements were terminated on July 1,
1997); 3) a cost sharing mechanism in lieu of reasonableness review, whereby
shareholders would absorb at least 20% of the termination or restructuring costs
associated with the Canadian supply and transportation contracts and at least 5%
of the termination or restructuring costs associated with the El Paso
transportation contract which the CPUC has already found reasonable (a portion
of these termination or restructuring costs associated with the cost sharing
mechanisms would be flowed through to ratepayers through the Energy Deferred
Refund Account); and 4) agreement that all other costs incurred under these
contracts, including the termination, buy-down and/or buy-out costs are
reasonable and should be determined to be reasonable by the CPUC.
8
On December 3, 1997, the CPUC issued a decision approving the settlement between
SCE and ORA. On March 12, 1998, the CPUC approved an advice letter ordering SCE
to refund $65 million covering all settlement costs for the 1994, 1995, 1996,
and 1997 ECAC record periods. The settlement has been fully reflected in SCE's
financial statements.
1995 Annual ECAC Record Period
SCE filed its reasonableness of operations testimony on May 26, 1996 for the
period April 1, 1994 through March 31, 1995 addressing power purchases and
exchanges, and the operation of hydroelectric, coal, gas, and nuclear resources
for the period April 1, 1994, through March 31, 1995. In May 1996, ORA issued
its reasonableness report on several non-QF reasonableness issues. The report
recommended a $6.6 million disallowance for replacement fuel expenses associated
with 64 outage days due to the Palo Verde Unit 2 steam generator tube rupture in
1993, and for nuclear fuel expenses that were later withdrawn by ORA. SCE and
ORA executed a stipulation on December 18, 1997, subsequently approved by the
CPUC on February 19, 1998, resolving the Palo Verde issue by agreeing to a
disallowance of $318,540 plus interest which is the replacement fuel expense
associated with six outage days.
1997 Annual ECAC Record Period
On May 30, 1997, SCE filed its annual reasonableness report requesting that the
CPUC find reasonable its fuel and purchased-power costs recorded during the
period of April 1, 1996, through March 31, 1997.
ORA's review of the non-QF operations and costs has been consolidated with its
review of the non-QF operations and costs for the 1996 ECAC record period. ORA
filed its report on August 18, 1997. In its report, ORA recommended, among other
things: 1) a disallowance of $360,000 associated with an outage at the
coal-fired Four Corners Generating Station; 2) a $200,000 adjustment to the
costs recorded in SCE's Catastrophic Events Memorandum Account, and 3) a
recommendation that SCE's execution of its natural gas transportation contract
with Southwest Gas Corporation be found unreasonable for purposes of CTC
eligibility. The January 1998 hearings resulted in a CPUC decision issued on
October 22, 1998, adopting the proposed disallowances. The decision found the
execution of the Southwest Gas contract reasonable and therefore, any uneconomic
costs associated with the contract will be subject to CTC recovery. The
remainder of SCE's non-QF costs and expenses were also found reasonable.
On December 21, 1998, SCE filed a petition for modification of the above
decision alleging that it erroneously stated that SCE may seek recovery of its
Nuclear Unit Incentive Procedure (NUIP) rewards in the Revenue Allocation
Proceeding. The CPUC found that SCE's calculation of the NUIP reward was
reasonable and it was an error for the Commission to order another
reasonableness review of these rewards which totaled $15,238,778 plus interest.
The February 18, 1999, CPUC decision granted SCE's petition to modify the 1998
decision and authorized the booking of the NUIP rewards into the TCBA.
1998 Annual ECAC Record Period
On February 19, 1999, ORA issued its Reasonableness Report and made the
following recommendations. ORA found that SCE's costs ($239.1 million) recorded
in the ISO/PX Implementation Delay Memorandum Account (IPDMA) properly reflected
the ISO/PX expenses that accrued during the three month delay in the
commencement of ISO/PX operations. ORA also required SCE to include a showing
that it undertook all practicable steps to minimize the delay with its request
for the recovery of IPDMA costs. ORA found no evidence to show that SCE caused a
delay in the ISO/PX implementation. ORA found that SCE had correctly calculated
its NUIP rewards for Palo Verde Units 2 and 3. The NUIP rewards calculated for
Unit 2 and 3 were $2.5 million and $1.6 million, respectively. ORA recommended
two coal generation related disallowances seeking replacement fuel costs based
on December 1997 outages of Mojave Units 1 and 2 in the amount of $2.4 million,
and a $1.6 million disallowance related to an outage at Four Corners Unit 5. ORA
also recommended disallowances totaling $5.6 million plus interest, to correct
for audit errors. SCE is investigating the facts behind these recommended
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disallowances recommendations and expects to file rebuttal testimony on April
26, 1999. Hearings are scheduled in May 1999.
Palo Verde
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 CTC mechanism. The existing nuclear unit
incentive procedure will continue only for purposes of calculating a reward for
performance of any unit above an 80% capacity factor for a fuel cycle. Beginning
in 2002, SCE will be required to share the net benefits received from the
operation of Palo Verde equally with ratepayers.
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 4.0(cent)
per kWh through December 31, 2003. Beginning January 1, 1998, the accelerated
plant recovery and incremental cost incentive pricing became part of the CTC
mechanism. Beginning in 2004, SCE will be required to share the net benefits
received from operation of San Onofre Units 2 and 3 equally with ratepayers.
New Accounting Rules
A recently issued accounting rule requires that costs related to start-up
activities be expensed as incurred, effective January 1, 1999. SCE does not
expect this new accounting rule to materially affect its results of operations
or its financial position.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to 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 reflected in 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 anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
Fuel Supply and Purchased Power Costs
Since April 1, 1998, SCE has been required to purchase all power for
distribution to retail customers from the PX. In 1998, fuel and purchased-power
costs, excluding that purchased from the PX, were approximately $3.1 billion,
which was a 20% decrease from the costs in 1997.
SCE's sources of energy during 1998 were as follows: 54% purchased power; 4%
natural gas; 22% nuclear; 13% coal; and 7% hydro.
Average fuel costs, expressed in (cent) per kWh, for the year ended December 31,
1998, were: oil, 6.03(cent); natural gas, 3.06(cent); nuclear, 0.48(cent); and
coal, 1.23(cent).
10
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.
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.
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 DOE provide
for the disposal of utility spent nuclear fuel beginning January 31, 1998. The
DOE 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 2000. Independent of arrangements made by
other participants, SCE will furnish its share of uranium concentrates
requirement through at least 1999 from existing contracts. Contracts covering
100% requirements are in place for conversion through 1998, enrichment through
2002, and fabrication through 2016.
Assuming normal operation and regulatory approval for more condensed on-site
spent fuel storage, Palo Verde Units 1, 2, and 3 will maintain full-core offload
reserve until the spring of 2002, fall of 2002, and spring of 2003,
respectively. Arizona Public Service, operating agent for Palo Verde, has
commenced construction of an interim fuel storage facility that it projects will
be completed in 2002.
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.
The Clean Air Act (CAA) provides the statutory framework to implement a program
for achieving national ambient air quality standards in areas exceeding such
standards and provides for maintenance of air quality in areas already meeting
such standards.
The CAA as amended in 1990, and as implemented within the South Coast Air
Quality Management District (SCAQMD) and other California districts, required
SCE to reduce emissions of oxides of nitrogen from its generating stations.
During 1998, SCE sold all of its oil- and gas-fueled generating stations
11
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 SCAQMD. The remaining plant, the Pebbly Beach Generating
Station, supplies power to Santa Catalina Island. After the sale of its oil- and
gas-fueled generating stations, SCE commenced operation of the facilities under
operation and maintenance contracts with the individual owners except for two
plants that ceased operation during 1998. SCE will continue to operate or, where
applicable, commence operating those divested facilities as active generating
stations for the required two-year period specified by California's
restructuring statute implementing deregulation of electric utilities in the
state. SCE's operation of the stations under these operation and maintenance
contracts is at the direction and expense of the new owners. SCE is responsible
for maintaining the environmental permits for the plants. The new owners, not
SCE, are responsible for the purchase and installation of emissions control
equipment, and for obtaining trading credits required for the plants under the
Regional Clean Air Incentives Market within the SCAQMD.
The CAA does not require any other significant emissions control expenditures
that are identifiable at this time. The Environmental Protection Agency (EPA)
plans to issue its final rulemaking regarding regional haze regulations in
mid-1999. The EPA and SCE are also expected to conclude a cooperative tracer
study of sulfur dioxide emissions from the Mohave Generating Station (Mohave) in
early 1999. The study is currently evaluating potential impact from Mohave
emissions on haze within the Grand Canyon National Park. On February 19, 1998,
the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court
of Nevada against SCE and the other co-owners of Mohave alleging violations,
over the last five years of the CAA, the Nevada State Implementation Plan, and
applicable air quality permits relating to opacity and sulfur dioxide emission
limits. (See, "Southern California Edison Company-Mohave Generating Station
Environmental Litigation" below for additional discussion.) SCE has asked
Business for Social Responsibility and Environment Now, two well respected
organizations, to convene a collaborative of interested stakeholders to discuss
the best way to resolve this issue. In anticipation of this dialogue, SCE has
proposed to install a dry scrubber, baghouse, and low-NOx burners at Mohave by
2008. This proposal, however, is subject to discussion and modification as part
of the collaborative. The acid rain provisions of the amended CAA also put an
annual limit on sulfur dioxide emissions allowed from power plants. SCE has
received more sulfur dioxide allowances than required for its projected
operations. Until the collaborative process is completed and a firm requirement
adopted, SCE expects to meet all of the present regulations through improved
operations at Mohave.
The CAA 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 required. 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.
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.
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.
12
The Resource Conservation and Recovery Act (RCRA) provides the statutory
authority for the EPA to implement a regulatory program for the safe treatment,
recycling, storage, and disposal of solid and hazardous wastes. An unresolved
issue remains regarding the degree to which coal wastes should be regulated
under the RCRA. Increased regulation may result in increased expenses relating
to the operation of Mohave.
The Toxic Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use, and disposal of
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 49 identified sites
is $171 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 $247 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 and has retained some liability associated with the divested
properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $88 million of its recorded liability, through an incentive
mechanism (SCE may ask 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 $141 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
$4 million to $10 million. Recorded costs for 1998 were $7 million.
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.
13
SCE's projected environmental capital expenditures are $900 million for the
1999-2003 period. These expenditures are mainly for aesthetic treatment,
including undergrounding certain transmission and distribution lines.
Year 2000 Issue
Many of SCE's existing computer systems identify a date by using only six digits
instead of eight. If not appropriately addressed, these programs could fail or
create erroneous results when attempting to process information containing dates
after December 31, 1999. This situation has been referred to generally as the
Year 2000 Issue.
SCE has a comprehensive program in place to address potential Year 2000 impacts.
SCE divides Year 2000 activities into five phases: inventory, impact assessment,
remediation, testing, and implementation. Edison International provides overall
coordination of this effort, working with SCE and their business units.
Remediation of SCE's key financial systems for the Year 2000 Issue was completed
in 1997. SCE's informational and operational systems have been assessed, and
detailed plans have been developed to address modifications required to be
completed, tested, and operational by December 31, 1999. Year 2000 readiness
preparations for SCE's mainframe financial systems were completed in the fourth
quarter of 1997, and preparations for SCE's material management system were
completed in the second quarter of 1998. SCE's customer information and billing
system is in the process of being replaced with a system designed to be Year
2000-ready and final conversion activities are expected to be completed by the
first quarter of 1999. SCE's distributed computing assets include operations and
business information systems. SCE's critical operations information systems
include outage management, power management, and plant monitoring and access
retrieval systems. SCE's business information systems include a data acquisition
system for billing, the computer call center support system, credit support, and
maintenance management. SCE's current estimate of the costs to complete these
modifications, including the cost of new hardware and software application
modification, is $72 million, about 40% of which is expected to be capital
costs. SCE's Year 2000 costs expended through December 31, 1998, were $35
million. SCE expects current rate levels for providing electric service to be
sufficient to provide funding for utility-related modifications. SCE expects its
Year 2000 date conversion project to be completed on a timely basis, with no
material adverse impact to its results of operations or financial position.
Another aspect of SCE's program involves developing contingency plans. Final
drafts of such plans are expected to be completed by March 1999, with management
approval thereof scheduled for May 1, 1999. These plans will continue to be
revised and enhanced as the year 2000 approaches.
SCE's objectives for the Year 2000 readiness of critical systems was to be 75%
complete by year-end 1998, and to be 100% complete by July 1999. SCE was 80%
complete at year-end 1998 and is on track to meet its July 1999 goal.
SCE's Year 2000 date conversion project includes an assessment of critical
interfaces with the computer systems of others, and it does not expect a
material adverse effect on its operating and business functions from the Year
2000 Issue. (See item 7, Management's Discussion and Analysis of Results of
Operations and Financial Condition -- "Year 2000 Issue" below for additional
discussion.)
Item 2. Properties
Existing Generating Facilities
SCE owns and operates one diesel-fueled generating plant located on Santa
Catalina island, 36 hydroelectric plants, and an undivided 75.05% interest
(1,614 MW net) in Units 2 and 3 at San Onofre.
14
These plants are located in Central and Southern California. By the end of 1998,
SCE had sold all 12 of its gas-fueled generating plants.
SCE also owns a 15.8% share of the Palo Verde (579 MW net) Nuclear Generating
Station which is located near Phoenix, Arizona. SCE owns a 48% undivided
interest (754 MW) in Units 4 and 5 at the Four Corners Generating Station, which
is a coal-fueled steam electric generating plant located in New Mexico. Palo
Verde and Four Corners are operated by other utilities. SCE operates and owns a
56% undivided interest (885 MW) in the Mohave Generating Station, which consists
of two coal-fueled steam electric generating units in Clark County, Nevada. At
year-end 1998, the existing SCE-owned generating capacity (summer effective
rating) was divided approximately as follows: 43.9% nuclear, 32.8% coal, 23.1%
hydroelectric, and 0.2% oil.
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 36 hydroelectric plants, some with related reservoirs, currently having 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, 30 to 50 year governmental
licenses that expire at various times between 1998 and 2026. 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, 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 effective operating capacity of 115.57
MW are pending. The SCE hydroelectric projects that are undergoing relicensing
and whose long-term licenses have expired, have been issued annual licenses,
which will be renewed until the new licenses are issued.
In 1998, SCE's peak demand was 19,935 MW, set on August 31, 1998. 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
$2.5 billion in principal amount was outstanding on December 31, 1998. 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 unsubstantial 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 the Four Corners Project, 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 Interior, and the possible invalidity of the Trust Indenture
lien against SCE's interest in the easement, lease, and improvements on the Four
Corners Project.
15
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $861 million in 1998,
and $685 million in 1997 and $616 million in 1996. Construction expenditures for
the 1999-2003 period are forecasted at $3.9 billion.
In addition to cash required for construction expenditures for the next five
years as discussed above, $2.4 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 2003
assume, among other things, 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.
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 these 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. AB
1890, 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 for each kWh of energy
generated at San Onofre during the eight-year period. AB 1890 allows for the
continuation of the incentive pricing plan through December 31, 2003. SCE was
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 fuel consumed
for generation of replacement energy for periods in which San Onofre will not
generate power through ECAC filings and, beginning in 1998, as part of ATCP. AB
1890 also allows SCE to continue to collect funds for decommissioning expenses
through traditional ratemaking treatment.
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, ORA, and TURN entered into a settlement agreement,
which was approved by the CPUC on December 20, 1996, regarding SCE's Palo Verde
Proposal Application which now 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 AB 1890. The settling parties agreed that SCE would recover its
share of Palo Verde
16
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 which
case, SCE must demonstrate that the aggregate amount of the costs exceeding the
forecast in that year are reasonable. If the annual Palo Verde site Gross
Capacity Factor (GCF) is less than 55% in a calendar year, SCE will bear the
burden of proof to demonstrate that the site's operations causing the GCF 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% GCF may be disallowed.
Beginning in 2002, the 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.
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 access its Nuclear Decommissioning Trust Funds for Unit 1 for
the purpose of commencing decommissioning of Unit 1 in 2000.
The Units 2 and 3 steam generators have performed relatively well through the
first 15 years of operation, with low rates of ongoing steam generator tube
degradation. During the Unit 2 scheduled refueling and inspection outage, which
was completed in 1997, an increased rate of degradation was identified, which
resulted in the removal of more tubes from service than had been expected. The
present design analysis, which is being reviewed for a potential increase,
allows for the removal of up to 10% of the steam generator tubes before the
unit's capacity must be re-evaluated. As a result of the increased degradation,
a mid-cycle outage was conducted in early 1998 for Unit 2. Continued degradation
was found during this inspection. A favorable (decreasing) trend in degradation
was observed during inspection in the scheduled refueling outage in January
1999. The results of the January 1999 inspection are being analyzed to determine
if there is a need for a mid-cycle inspection outage in early 2000. With the
results from the January 1999 outage, 7.5% of the tubes have now been removed
from service. In September 1998, San Onofre Unit 2 experienced a small amount of
leakage from a steam generator tube plug, which required an 11-day outage to
repair.
During Unit 3's refueling outage, which was completed in July 1997, inspections
of structural supports for steam generator tubes identified several areas where
the thickness of the supports had been reduced, apparently by erosion during
normal plant operation. A follow-up mid-cycle inspection indicated that the
erosion had been stabilized. Additional monitoring inspections are planned
during the next scheduled refueling outage in 1999. To date, 5% of Unit 3's
tubes have been removed from service.
During Unit 2's February 1998 mid-cycle outage, similar tube supports showed no
significant levels of such erosion.
Palo Verde Nuclear Generating Station
Based on latest available data, APS estimates that the Unit 1 and Unit 3 steam
generators should operate for the 40 year licensed operating life of those
units, although APS continues to monitor the situation. APS has disclosed that
it believes that it will be economically desirable to replace the Unit 2 steam
generators, which have been most affected by tube cracking, in four to nine
years. APS has indicated to the participants that it believes that replacement
of the Unit 2 steam generators would cost between $100 million and $150 million.
SCE estimates that this cost could be higher, such that its share of this cost
would be between $16 million and $30 million plus replacement power costs.
Unanimous approval of the Palo Verde participants is required for capital
improvements, including steam generator replacement. In December 1997, the Palo
Verde participants unanimously agreed to purchase two spare
17
steam generators at a cost of approximately $82 million; however, SCE has not
yet decided whether it supports replacement of the Unit 2 steam generators.
During 1998, Palo Verde Nuclear Generating Station generated 30 billion kWh of
electricity. It was the first time an American power plant of any kind crossed
the 30-billion-kilowatt-hour threshold in a single year. Palo Verde broke its
own record of 29.5 billion kWh that it set in 1997 and was the nation's top
power producer for the fourth consecutive year. The year-end station capacity
factor was 92.5%. Units 1 and 3 were each refueled in 36-day outages - a site
record. Unit 2 operated on-line the entire year and at year's end had operated
continuously for 430 days.
Nuclear Facility Decommissioning
With the exception of San Onofre Unit 1, SCE plans to decommission its nuclear
generating facilities at the end of each facility's operating license by a
prompt removal method authorized by the NRC. On December 21, 1998, SCE filed an
application with the CPUC requesting the authority to access its decommissioning
trust funds for San Onofre Unit 1 for the purpose of decommissioning commencing
in 2000. Decommissioning is estimated to cost $1.9 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. Decommissioning is scheduled to begin in 2000 at San Onofre Unit
1. SCE expects decommissioning San Onofre Units 2 and 3 and Palo Verde to occur
after its generating licenses expire in 2013 and 2024 respectively.
Decommissioning expense was $164 million in 1998 and $154 million in 1997. The
accumulated provision for decommissioning was $1.2 billion at December 31, 1998,
and $1.1 billion at December 31, 1997. The estimated costs to decommission San
Onofre Unit 1 ($368 million in 1998 dollars) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts which,
together with accumulated earnings, will be utilized solely for decommissioning.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.8
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. SCE,
however, would have to pay no more than $20 million per incident in any one
year. Such premium amounts include a 5% surcharge if additional funds are needed
to satisfy public liability claims and are subject to periodic 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 primarily by mutual insurance companies
owned by utilities with nuclear
18
facilities. If losses at any nuclear facility covered by these arrangements were
to exceed the accumulated funds for these insurance programs, SCE could be
assessed retrospective premium adjustments of up to $22 million per year.
Insurance premiums are charged to operating expense.
Item 3. Legal Proceedings
Wind Generators' Litigation
SCE was named as a defendant in a series of eight lawsuits brought by
independent power producers of wind generation. Seven of the lawsuits were filed
in Los Angeles County Superior Court and one was filed in Kern County Superior
Court. The lawsuits alleged that SCE incorrectly interpreted contracts with the
plaintiffs by limiting fixed energy payments to a single ten-year period rather
than beginning a new ten-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the plaintiffs'
allegations. In each of the lawsuits, the plaintiffs sought declaratory relief
regarding the proper interpretation of the contracts. Plaintiffs alleged a
combined total of approximately $189 million in damages, which included
consequential damages claimed in seven of the eight lawsuits. A ninth lawsuit
was subsequently filed in Los Angeles County raising claims similar to those
alleged in the first eight. SCE responded to the complaint in the new lawsuit by
denying its material allegations.
After receiving a favorable decision in the liability phase of the lead case,
SCE agreed to settle with the plaintiffs in seven of the lawsuits on terms
whereby SCE waived its rights to recover costs against such plaintiffs in
exchange for their agreement that there is only one fixed price period under
each of their power purchase contracts with SCE and a mutual dismissal with
prejudice of claims. SCE also entered into a settlement agreement with the
plaintiff in another of the lawsuits which resolved the issue of multiple fixed
price periods on the same terms and which also resolved a related issue unique
to that plaintiff in exchange for a nominal payment by SCE. This settlement was
approved by the bankruptcy court in proceedings involving the plaintiff. On
January 28, 1999, SCE finalized a settlement with the remaining plaintiffs on
terms effectively the same as those in the initial group of settlements except
that the settlement agreement also resolved, on terms favorable to SCE, certain
claims which SCE had asserted in the lead case by way of cross-complaint.
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. The complaint sought termination of the contracts and
damages for excess power purchase payments made to the Coso parties. The Coso
parties' motion to transfer venue to Inyo County Superior Court was granted on
August 31, 1997. On June 1, 1998, the court struck SCE's request for termination
of the contracts, leaving SCE with its claim for damages and other relief. On
February 16, 1999, the court denied the Coso Parties' motion for judgment on the
pleadings directed to SCE's first amended complaint.
The Coso parties have also asserted various claims against SCE, The Mission
Group, and Mission Power Engineering Company (Mission parties) in a cross
complaint filed in the action commenced by SCE as well as in a separate action
filed against SCE by three of the Coso parties in Inyo County Superior Court. In
November 1997, the court struck all but two causes of action asserted in the
separate action on the grounds that they should have been raised as part of the
Coso parties' cross-complaint, and ordered the remaining two causes of action
consolidated for all purposes with the action filed by SCE.
19
The Coso parties subsequently filed second and third amended cross-complaints.
The third amended cross-complaint names SCE, the Mission parties, and Edison
International. As against SCE, the third amended cross-complaint purports causes
of action for declaratory relief, breach of the covenant of good faith and fair
dealing; inducing breach of agreements between the Coso parties and their former
employees; breach of an earlier settlement agreement between the Mission parties
and the Coso parties; slander and disparagement, injunctive relief and
restitution for unfair business practices; anticipatory breach of the contracts;
and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As against the
Mission parties, the third amended cross-complaint seeks damages for breach of
warranty of authority with respect to the settlement agreement, and for
equitable indemnity. The Coso parties voluntarily dismissed Edison International
from the third amended cross-complaint on December 4, 1998. As against SCE, the
third amended 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.
On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting affirmative
defenses. In addition, SCE filed a cross-complaint for reformation of the
contracts alleging that if they are not susceptible to SCE's interpretation,
they should be reformed to reflect the parties' true intention. The Coso
defendants demurred to SCE's cross-complaint and, in January 1999, their
demurrer was sustained with leave to amend. In light of this new ruling, SCE
recently filed an amended cross-complaint for reformation.
Following various pre-trial motions filed by the Mission parties and Edison
International, the Coso Parties, on December 23, 1998, purported to file a
fourth amended cross-complaint against the Mission Parties only. The Mission
Parties' demurrer to and motion to strike directed to the fourth amended
cross-complaint was heard and taken under submission on March 10, 1999.
On December 15, 1998, the Court granted the Coso parties leave to file a second
amended complaint in the separately filed (now consolidated) action. The second
amended complaint which names SCE and Edison International, alleges that SCE
engaged in anti-competitive conduct, false advertising, and conduct proscribed
by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and
punitive damages. On January 20, 1999, SCE filed three motions to strike several
portions of the second amended complaint on the grounds, among others, that the
CPUC or FERC have either exclusive or primary jurisdiction over the matters
asserted therein, and that SCE's alleged conduct was in furtherance of
constitutionally protected rights of free speech and petition and therefore not
actionable. These matters were heard on February 22, 1999, and taken under
submission at that time.
Discovery and motion practice related to discovery is active. The Court has set
a trial date of March 1, 2000. The materiality of net final judgments against
SCE in these actions would be largely dependent on the extent to which any
damages or additional payments which might result therefrom are recoverable
through rates.
Electric and Magnetic Fields (EMF) Litigation
SCE is involved in lawsuits alleging that various plaintiffs developed cancer as
a result of exposure to EMF from SCE facilities.
In December 1995, the court granted SCE's motion for summary judgment in the
first lawsuit and dismissed the case. Plaintiffs filed a notice of appeal.
Following a settlement conference ordered by the Court of Appeal, the case was
dismissed in January 1999.
Following dismissal of the second lawsuit by the plaintiffs, a wrongful death
action was filed by the husband and children of one of the original plaintiffs
who had subsequently died. This wrongful death action was dismissed by the court
without leave to amend on September 16, 1998. Plaintiffs' appeal in the wrongful
death action was dismissed following a settlement conference in the Court of
Appeal in January 1999.
20
San Onofre Personal Injury Litigation
SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. 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 have been 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. A trial date has not yet been set.
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 and the parties are
awaiting a date for oral argument to be set by the court. A decision is not
expected until early 2000.
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. This case, with only the son as plaintiff, is expected to go to trial
in late 1999.
On November 20, 1997, a former contract worker at San Onofre and his wife sued
SCE in the Superior Court of California, County of San Diego. The case was
removed to the U.S. District Court for the Southern District of California. On
May 11, 1998, the plaintiffs filed a first amended complaint. On May 22, 1998,
SCE filed an answer denying the material allegations of the first amended
complaint. Pursuant to a stipulation of the parties, the court, on January 4,
1999, dismissed the plaintiffs' complaint in this matter with prejudice.
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 trial pending the results of the
case currently before the Ninth Circuit Court of Appeal. The parties agreed that
if the plaintiffs/petitioners do not receive a favorable determination on appeal
then the two cases at the District Court level will be dismissed. If, however,
the plaintiffs/petitioners receive a favorable determination on appeal, then the
two District Court cases will be set for trial.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although, as indicated
above, SCE was successful in removing itself from those actions, the impact on
SCE, if any, from further proceedings in these cases against the remaining
defendants can not be determined at this time.
Mohave Generating Station Environmental Litigation
On February 19, 1997, the Sierra Club and the Grand Canyon Trust filed suit in
the U.S. District Court of Nevada against SCE and the other three co-owners of
Mohave Generating Station. The lawsuit alleges that Mohave has been violating
various provisions of the CAA, the Nevada state implementation plan, certain EPA
orders, and applicable pollution permits relating to opacity and sulfur dioxide
emission limits over the last five years. The plaintiffs seek declaratory and
injunctive relief as well as civil penalties. Under the CAA, the maximum civil
penalty obtainable is $25,000 per day per violation. SCE and the co-owners
obtained an extension to respond to the complaint pending the court's ruling on
a motion to dismiss filed by the defendants.
On June 4, 1998, the plaintiffs served SCE and its co-owners with a 60-day
supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On November 12,
1998, the court bifurcated the liability and damage phases of the case.
21
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, 1998 Company Position
- ------------------------------------ ------------------------- -------------------------------------------------------
John E. Bryson 55 Chairman of the Board, Chief Executive Officer and
Director
Stephen E. Frank 57 President, Chief Operating Officer and Director
Bryant C. Danner 61 Executive Vice President and General Counsel
Alan J. Fohrer 48 Executive Vice President and Chief Financial Officer
Harold B. Ray 58 Executive Vice President, Generation Business Unit
Pamela A. Bass 51 Senior Vice President, Customer Service Business Unit
Theodore F. Craver, Jr. 47 Senior Vice President and Treasurer
John R. Fielder 53 Senior Vice President, Regulatory Policy and Affairs
Robert G. Foster 51 Senior Vice President, Public Affairs
Lillian R. Gorman 45 Senior Vice President, Human Resources
Richard M. Rosenblum 48 Senior Vice President, T&D Business Unit
Bruce C. Foster 46 Vice President, San Francisco Regulatory Affairs
Thomas J. Higgins 53 Vice President, Corporate Communications
Thomas M. Noonan(2) 47 Vice President and Controller
Anthony L. Smith 50 Vice President, Tax
- --------------
(1) Executive Officers are defined by Rule 3b-7 of the General Rules and
Regulations under the Securities Exchange Act of 1934, as amended.
Executive Officers, Bryson, Danner, Fohrer, Craver, Robert Foster, Gorman,
Higgins, Noonan and Smith hold the same positions with Edison
International. Edison International is the parent holding company of SCE.
(2) Richard K. Bushey resigned as Vice President and Controller of SCE
effective March 1, 1999.
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 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
Stephen E. Frank, Theodore F. Craver, Jr., Lillian R. Gorman, and Thomas
J. Higgins. Those
22
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 President, Chief Operating Officer and June 1995 to present
Director
President and Chief Operating Officer, August 1990 to January 1995
Florida Power and Light Company(1)
Bryant C. Danner Executive Vice President and General Counsel June 1995 to present
Senior Vice President and General Counsel July 1992 to May 1995
Alan J. Fohrer Executive Vice President and Chief Financial September 1996 to present
Officer
Executive Vice President, Chief Financial February 1996 to August 1996
Officer and Treasurer
Executive Vice President and Chief Financial May 1995 to January 1996
Officer
Senior Vice President and Chief Financial January 1993 to April 1995
Officer
Harold B. Ray Executive Vice President, Generation June 1, 1995 to present
Business Unit
Senior Vice President, Power Systems June 1990 to May 1995
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
Division Vice President, ENvest August 1993 to December 1995
Theodore F. Craver, Jr. Senior Vice President and Treasurer February 1998 to present
Vice President and Treasurer September 1996 to February 1998
Executive Vice President and Corporate September 1990 to August 1996
Treasurer, First Interstate Bancorp(1)
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present
Affairs
Vice President, Regulatory Policy and Public February 1992 to January 1998
Affairs
Robert G. Foster Senior Vice President, Public Affairs November 1996 to present
Vice President, Public Affairs November 1993 to October 1996
Lillian R. Gorman Senior Vice President, Human Resources March 1999 to present
Vice President, Human Resources July 1996 to February 1999
Executive Vice President and Human Resources October 1990 to May 1996
Director, First Interstate Bancorp(1)
Richard M. Rosenblum Senior Vice President, T&D Business Unit February 1998 to present
Vice President, Distribution Business Unit January 1996 to January 1998
Vice President, Nuclear Engineering and June 1993 to December 1995
Technical Services
23
Bruce C. Foster Vice President, San Francisco January 1995 to present
Regulatory Affairs
Regional Vice President, San Francisco Office January 1992 to December 1994
Thomas J. Higgins Vice President, Corporate Communications April 1995 to present
Vice President, Corporate Communications April 1995 to January 1996
President, The Laurel Company(1)(2) January 1994 to December 1994
Thomas M. Noonan Vice President and Controller March 1999 to present
Assistant Controller September 1993 to February 1999
Anthony L. Smith Vice President, Tax March 1999 to present
Assistant Controller January 1998 to February 1999
(1) This entity is not a parent, subsidiary or other affiliate of SCE.
(2) As President of The Laurel Company, Thomas J. Higgins provided advice on
planning and financing for mergers and acquisitions for clients in the
managed health care business.
24
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, 1998, (Annual Report) under "Quarterly Financial Data" on
page 35 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: 1994-1998 on page 38 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 1 through 12 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 4 through 5 and is incorporated herein by reference to
General Instruction G(2).
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
13 through 35, 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 is included in
the Joint Proxy Statement (Proxy Statement) filed with the Commission in
connection with SCE's Annual Meeting to be held on April 15, 1999, under the
heading, "Election of Directors of Edison International and SCE" on pages 4
through 7 and "Section 16(a) Beneficial Ownership Reporting Compliance" on page
23, and is incorporated herein by reference pursuant to General Instruction
G(3).
25
Item 11. Executive Compensation
Information responding to Item 11 is included in the Proxy Statement beginning
with the section under the heading "Executive Compensation Table - Edison
International and SCE" on pages 10 through 22, 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 is included in the Proxy Statement under the
headings "Stock Ownership of Directors and Executive Officers of Edison
International and SCE" on pages 8 through 9 and "Stock Ownership of Certain
Shareholders" on page 26, and is incorporated herein by reference pursuant to
General Instruction G(3).
Item 13. Certain Relationships and Related Transactions
Information responding to Item 13 is included in the Proxy Statement under the
heading "Certain Relationships and Transactions of Nominees and Executive
Officers" on page 23 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 1998 Annual Report to Shareholders are
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, 1998,
1997 and 1996
Consolidated Statements of Retained Earnings -- Years Ended December 31,
1998, 1997 and 1996
Consolidated Balance Sheets -- December 31, 1998, and 1997
Consolidated Statements of Cash Flows -- Years Ended December 31, 1998,
1997 and 1996
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(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 30
Schedule II--Valuation and Qualifying Accounts for the Years
Ended December 31, 1997, 1996 and 1995 31
26
Schedules I through V, inclusive, except those referred to above, are omitted as
not required or not applicable.
(3) Exhibits
See Exhibit Index on page 35 of this report.
(b) Reports on Form 8-K
November 13, 1998
Item 5: Other Events Proposition 9
27
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements included in the 1998 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 February
4, 1999. Our audits of the consolidated financial statements were made for the
purpose of forming an opinion on those basic consolidated financial statements
taken as a whole. The supplemental schedules listed in Part IV of this Form
10-K, which are the responsibility of SCE's management, are presented for
purposes of complying with the Securities and Exchange Commission's rules and
regulations, and are not part of the basic consolidated financial statements.
These supplemental schedules have been subjected to the auditing procedures
applied in the audits of the basic 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 basic consolidated financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
February 4, 1999
28
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.
29
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
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 $ 24,390 $ 20,597 -- $ 20,742 $ 24,245
All other 1,689 1,180 -- 661 2,208
----------- ----------- --------- ----------- -----------
Total $ 26,079 $ 21,777 -- $ 21,403(a) $ 26,453
======= ======= ====== ======= =======
Group B:
DOE Decontamination
and Decommissioning $ 48,789 -- $ 1,089(b) $ 5,542(c) $ 44,336
Purchased-power settlements 107,700 -- 67,320(d) 29,380(e) 145,640
Pension and benefits 180,927 $102,193 17,624(f) 89,544(g) 211,200
Insurance, casualty and
other 86,509 57,749 -- 65,797(h) 78,461
----------- ---------- ----------- ----------- -----------
Total $423,925 $159,942 $ 86,033 $190,263 $479,637
======= ======= ======= ======== =======
- -----------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents additional payments to be made under agreements to
terminate purchased-power contract.
(e) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(f) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(g) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(h) Amounts charged to operations that were not covered by insurance.
30
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1996
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 $ 22,126 $ 21,831 -- $ 19,567 $ 24,300
All other 2,013 376 -- 700 1,689
----------- ----------- --------- ----------- -----------
Total $ 24,139 $ 22,207 -- $ 20,267(a) $ 26,079
======= ======= ====== ======= =======
Group B:
DOE Decontamination
and Decommissioning $ 52,742 $ -- $ 1,468(b) $ 5,5421(c) $ 48,789
Purchased-power settlements -- -- 107,700(d) -- 107,700
Pension and benefits 196,662 8,547 21,869(e) 46,151(f) 180,927
Insurance, casualty and
other 94,788 59,123 -- 67,402(g) 86,509
----------- ----------- ----------- ----------- -----------
Total $344,192 $ 67,670 $131,037 $118,974 $423,925
======= ======= ======= ======== =======
- ------------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents payments to be made under an agreement to
terminate a purchased-power contract.
(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.
31
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: March 24, 1999
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:
John E. Bryson* Chairman of the Board, March 24, 1999
Chief Executive Officer
and Director
Principal Financial Officer:
Alan J. Fohrer* Executive Vice President March 24, 1999
and Chief Financial Officer
Controller or Principal
Accounting Officer:
Thomas M. Noonan* Vice President and March 24, 1999
Controller
Board of Directors:
Winston H. Chen* Director March 24, 1999
Warren Christopher* Director March 24, 1999
Stephen E. Frank* Director March 24, 1999
Joan C. Hanley* Director March 24, 1999
Carl F. Huntsinger* Director March 24, 1999
Charles D. Miller* Director March 24, 1999
Luis G. Nogales* Director March 24, 1999
Ronald L. Olson* Director March 24, 1999
James M. Rosser* Director March 24, 1999
E. L. Shannon, Jr.* Director March 24, 1999
Robert H. Smith* Director March 24, 1999
Thomas C. Sutton* Director March 24, 1999
Daniel M. Tellep* Director March 24, 1999
James D. Watkins* Director March 24, 1999
Edward Zapanta* Director March 24 1999
*By Kenneth S. Stewart
-----------------------------------------
Kenneth S. Stewart
Assistant General Counsel
32
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 June 23, 1997 (File
No. 1-2313, Form 10-Q for the quarter ended September 30, 1997)*
3.3 Bylaws of SCE as adopted by the Board of Directors on
February 18, 1999
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)*
10.1 1981 Deferred Compensation Agreement (File No. 1-2313,
Form 10-K for the year ended December 31, 1981)*
10.2 1985 Deferred Compensation Agreement for Executives (File No.
1-2313, Form 10-K for the year ended December 31, 1986)*
10.3 1985 Deferred Compensation Agreement for Directors
(File No. 1-2313, Form 10-K for the year ended
December 31, 1986)*
10.4 Director Deferred Compensation Plan (File No. 1-2313,
Form 10-Q for the quarter ended June 30, 1998)*
10.5 Director Grantor Trust Agreement (File No. 1-9936,
Form 10-K for the year ended December 31, 1995)*
10.6 Executive Deferred Compensation Plan (File No. 1-2313,
Form 10-Q for the quarter ended March 31,
1998)*
10.7 Executive Grantor Trust Agreement (File No. 1-2313,
Form 10-K for the year ended December 31, 1995)*
10.8 Executive Supplemental Benefit Program (File No. 1-2313,
Form 10-K for the year ended December 31, 1980)*
10.9 Executive Retirement Plan (File No. 1-2313,
Form 10-K for the year ended December 31, 1995)*
10.10 Executive Incentive Compensation Plan (File No. 1-2313,
Form 10-K for the year ended December 31, 1997)*
10.11 Executive Disability and Survivor Benefit Program
(File No. 1-2313, Form 10-K for the year ended
December 31, 1994)*
10.12 Retirement Plan for Directors (File No. 1-2313,
Form 10-Q for the quarter ended June 30, 1998)*
10.13 Officer Long-Term Incentive Compensation Plan
(File No. 1-2313, Form 10-Q for the quarter ended
March 31, 1998)*
10.13.1 Form of Agreement for 1989-1995 Awards under the Officer
Long-Term Incentive Compensation Plan (File No. 1-2313,
Form 10-K for the year ended December 31, 1995)*
10.13.2 Form of Agreement for 1996 Awards under the Officer Long-Term
Incentive Compensation Plan (File No. 1-2313,
Form 10-K for the year ended December 31, 1996)*
33
Exhibit
Number Description
- ------- -----------
10.13.3 Form of Agreement for 1997 Awards under the Officer and
Management Long-Term Incentive Compensation Plans
(File No. 1-2313, Form 10-K for the year ended December 31, 1997)*
10.14 Equity Compensation Plan (File No. 1-2313, Form 10-Q for the
quarter ended June 30, 1998)*
10.14.1 Form of Agreement for 1998 Employee Awards under the Equity
Compensation Plan (File No. 1-2313,
Form 10-Q for the quarter ended June 30, 1998)*
10.14.2 Form of Agreement for 1998 Director Awards under the Equity
Compensation Plan (File No. 1-2313,
Form 10-Q for the quarter ended June 30, 1998)*
10.15 Estate and Financial Planning Program (File No. 1-2313,
Form 10-K for the year ended December 31, 1995)*
10.16 Option Gain Deferral Plan (File No. 1-2313, Form 10-Q for
the quarter ended March 31, 1998)*
10.17 Employment Letter Agreement with Bryant C. Danner
(File No. 1-2313, Form 10-K for the year ended
December 31, 1992)*
10.18 Employment Letter Agreement with Stephen E. Frank
(File No. 1-2313, Form 10-K for the year ended
December 31, 1995)*
10.19 Election Terms for Warren Christopher (File No. 1-2313,
Form 10-K for the year ended December 31, 1997)*
10.20 Dispute resolution amendment of 1981 Executive Deferred
Compensation Plan, 1985 Executive and Director Deferred
Compensation Plans and Executive Supplemental Benefit Program
10.21 Retirement Agreement with Richard K. Bushey
12. Computation of Ratios of Earnings to Fixed Charges
13. Annual Report to Shareholders for year ended December 31, 1997
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
27. Financial Data Schedule
- ------------
* Incorporated by reference pursuant to Rule 12b-32.
EXHIBIT 3.3
To Holders of the Company's Bylaws:
Effective February 18, 1999, Article II,
Section 11, was amended to be consistent with
California law which provides that proxies include
electronic and oral telephonic authorizations by shareholders.
BEVERLY P. RYDER
Corporate Secretary
BYLAWS
OF
SOUTHERN CALIFORNIA EDISON COMPANY
AS AMENDED TO AND INCLUDING
FEBRUARY 18, 1999
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. Regular Meetings..........................................11
Section 7. Special 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 President's 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
ARTICLE V -- OTHER PROVISIONS (Cont.)
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 18, 1999
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 designated 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 annual meeting of shareholders shall be held on the third Thursday of
the month of April of each year at 10:00 a.m. 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 the
same time and place on the next day thereafter ensuing which is not a legal
holiday.
1
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
2
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 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
3
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
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
4
of the corporation on the record date determined in accordance with Section 8 of
this Article.
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
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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
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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
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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 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
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name, promissory notes, bonds, debentures, deeds of trust, mortgages,
pledges, hypothecations or other evidences of debt and securities therefor.
Section 2. Number of Directors.
The authorized number of directors shall be not less than fifteen nor more
than twenty 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.
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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 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. Regular Meetings.
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.
Regular meetings of the Board shall be held at the principal office of the
corporation without notice on the third Thursday of the months of February,
April, May, July and September, and on the second Thursday in December, at the
hour of 9:00 a.m. or as soon thereafter as the regular meeting of the Board of
Directors of Edison International is adjourned, and on the third Thursday in
March, at the hour of 8:00 a.m. or as soon thereafter as the regular meeting of
the Board of Directors of Edison International is adjourned. Call and notice of
all regular meetings of the Board are not required.
Section 7. Special Meetings.
Special 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.
Special meetings of the Board shall be held upon four days' written notice
or forty-eight hours' notice given personally or by telephone, 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 as it is shown upon the records of the corporation or as may have been
given to
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the corporation by the director for purposes of notice or, if such address
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 special 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. Oral notice shall be deemed to have been given at the time it is
communicated, in person or by telephone, radio 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.
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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(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.
15
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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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'
and their names and addresses who are entitled to vote for the election of
directors 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.
22
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.
23
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
24
corporation for breach of duty to the corporation and its 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.
25
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.
26
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
27
this 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
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
RESOLUTION OF THE COMPENSATION COMMITTEE
OF THE BOARD OF DIRECTORS OF
SOUTHERN CALIFORNIA EDISON COMPANY
Adopted November 30, 1989
RE: AMENDMENT OF DISPUTE RESOLUTION PROCEDURES
IN NON-QUALIFIED BENEFIT PLANS
WHEREAS, the Board of Directors ("Board") has previously adopted certain
non-qualified benefit plans (the "Plans") for eligible executives and directors
of the corporation, including the (a) 1981, 1987, 1988, and 1989 Deferred
Compensation Plans for executives, (b) the Executive Supplemental Benefit
Program, (c) the Executive Retirement Plan, (d) the 1985 Deferred Compensation
Plan for executives, (e) the Retirement Plan for Directors, and (f) the 1985,
1987, 1988 and 1989 Deferred Compensation Plans for directors; and
WHEREAS, these Plans have been adopted, among other things, to attract and
retain the corporation's team of executives and directors, provide financial
incentives to reinforce and recognize performance and accomplishments, and make
the corporation's compensation programs for executives and directors more
competitive within the electric utility industry and general industry; and
WHEREAS, it is now deemed desirable to amend these Plans to provide dispute
resolution procedures which will guarantee speedy and fair review of any claims
that may arise under the Plans;
NOW, THEREFORE, BE IT RESOLVED, that the Plans, be and they hereby are,
amended as set forth in the attached "Exhibit A".
EXHIBIT A
RE: AMENDMENT OF DISPUTE RESOLUTION PROCEDURES
1. 1981, 1987, 1988. and 1989 Deferred Compensation Plans.
------------------------------------------------------
Section 11 of each of these plans is amended to read as follows:
"The Board (either directly or through its designees) will have power and
authority to interpret, construe, and administer this Agreement; provided that,
the Board's authority to interpret this Agreement shall not cause the Board's
decisions in this regard to be entitled to a deferential standard of review in
the event that a Participant or beneficiary seeks review of the Board's decision
as described below. In addition, the Board shall have the power to prospectively
modify or terminate this Agreement, provided that any such modification or
termination does not result in the elimination of any rights that the
Participant or beneficiary may have under this Agreement. Absent the consent of
the Participant, however, the Board shall in no event have any authority to
modify this section.
"No member of the Board, nor its designee, shall be liable to any person
for any action taken or omitted in connection with the interpretation and
administration of this Agreement.
"In the event of Plan amendment or termination, the benefit payable from
the account balance of a retired or deceased Participant shall not be impaired,
and the benefit from the account balances of other Participants shall not be
less than the benefit to which each such Participant would have been entitled
from his or her account balance immediately prior to such amendment or
termination.
"Because it is agreed that time will be of the essence in determining
whether any payments are due to Participant or his or her beneficiary under this
Agreement, a Participant or beneficiary may, if he or she desires, submit any
claim for payment under this Agreement to arbitration. This right to select
arbitration shall be solely that of the Participant or beneficiary and the
Participant or beneficiary may decide whether or not to arbitrate in his or ber
discretion. The "right to select arbitration" is not mandatory on the
Participant or beneficiary, and the Participant or beneficiary may choose in
lieu thereof to bring an action in an appropriate civil court. Once an
arbitration is commenced, however, it may not be discontinued without the mutual
consent of both parties to the arbitration. During the lifetime of the
Participant only he or she can use the arbitration procedure set forth in this
section.
"Any claim for arbitration may be submitted as follows: if Participant or
beneficiary has submitted a request to be paid under this Agreement and the
claim is finally denied by the
Company in whole or in part, such claim may be filed in writing with an
arbitrator of Participant's or beneficiary's choice who is selected by the
method described in the next three sentences. The first step of the selection
shall consist of the Participant or beneficiary submitting a list of five
potential arbitrators to the Company. Each of the five arbitrators must be
either (1) a member of the National Academy of Arbitrators located in the State
of California or (2) a retired California Superior Court or Appellate Court
judge. Within one week after receipt of the list, the Company shall select one
of the five arbitrators as the arbitrator for the dispute in question. If the
Company fails to select an arbitrator within one week after receipt of the list,
the Participant or beneficiary shall then designate one of the five arbitrators
for the dispute in question.
"The arbitration hearing shall be held within seven days (or as soon
thereafter as possible) after the picking of the arbitrator. No continuance of
said hearing shall be allowed without the mutual consent of Participant or
beneficiary and the Company. Absence from or nonparticipation at the hearing by
either party shall not prevent the issuance of an award. Hearing procedures
which will expedite the hearing may be ordered at the arbitrator's discretion,
and the arbitrator may close the hearing in his or her sole discretion when he
or she decides he or she has heard sufficient evidence to satisfy issuance of an
award.
"The arbitrator's award shall be rendered as expeditiously as possible and
in no event later than one week after the close of the hearing.
"In the event the arbitrator finds that the Company has breached this
Agreement, he or she shall order the Company to pay to Participant or
beneficiary within two business days after the decision is rendered the amount
then due the Participant or beneficiary, plus, notwithstanding anything to the
contrary in this Agreement, an additional amount equal to 20% of the amount
actually in dispute. This additional amount shall constitute an additional
benefit under this Agreement. The award of the arbitrator shall be final and
binding upon the parties.
"The award may be enforced in any appropriate court as soon as possible
after its rendition. The Company will be considered the prevailing party in a
dispute if the arbitrator determines (1) that the Company has not breached this
Agreement and (2) the claim by Participant or his or her beneficiary was not
made in good faith. Otherwise, the Participant or his or her beneficiary will be
considered the prevailing party. In the event that the Company is the prevailing
party, the fee of the arbitrator and all necessary expenses of the hearing
(excluding any attorneys' fees incurred by the Company) including stenographic
reporter, if employed, shall be paid by the losing party. In the event that the
Participant or his or her beneficiary is the prevailing party, the fee of the
arbitrator and all necessary expenses of the hearing (including all attorneys,
fees incurred by Participant or his or her beneficiary in pursuing his or her
claim), including the fees of a stenographic reporter if employed, shall be
paid by the Company."
2. Executive Supplemental Benefit Program.
--------------------------------------
Section 7 of Part E of the Program is amended by inserting the words
"Subject to Section 8 of Part E," at the beginning.
Section 8 of Part E is amended to read identically to the amendment set
forth in Section 1 of this Exhibit A, except that (1) instead of the word
"Agreement" the word "Program" shall be used and (2), in lieu of paragraph three
of said amendment, the following paragraph shall be substituted:
"In the event of an amendment or termination of any Part of this Program,
the benefits payable on account of a retired or deceased Participant shall not
be impaired, and the benefits of other Participants shall not be less than the
benefits to which each such Participant would have been entitled immediately
prior to such amendment or termination of any Part (or Parts) of the Program."
3. Executive Retirement Plan.
-------------------------
Section 12 of the plan is amended to read identically to the amendment set
forth in Section 1 of this Exhibit A, except that (1) instead of the word
"Agreement" the word "Plan" shall be used, the words "Eligible Employee" shall
be used in lieu of the word "Participant," and (3), in lieu of paragraph three
of said amendment, the following paragraph shall be substituted:
"In the event of Plan amendment or termination which has the effect of
eliminating or reducing a benefit under the Plan, the benefit payable on account
of a retired Eligible Employee or survivor or other beneficiary shall not be
impaired, and the benefits of other Eligible Employees shall not be less than
the benefit to which each such Eligible Employee would have been entitled if he
or she had retired immediately prior to such amendment or termination."
4. 1985 Deferred Compensation Plan for Executives.
----------------------------------------------
Section 10 of the plan is amended to read identically to the amendment set
forth in Section 1 of this Exhibit A.
5. Retirement Plan for Directors.
-----------------------------
Article V of the plan is amended to delete the third and fourth sections
thereof. New Article VI entitled "Plan Interpretation" is added to read
identically to the amendment set forth in Section 1 of this Exhibit A, except
that (1) instead of the word "Agreement" the word "Plan" shall be used, the
words "Eligible Director" shall be used in lieu of the word
"Participant," and (3), in lieu of paragraph three of said amendment, the
following paragraph shall be substituted: "In the event of Plan amendment or
termination which has the effect of eliminating or reducing a benefit under the
Plan, the benefit payable on account of a retired Eligible Director or survivor
or other beneficiary shall not be impaired, and the benefits of other Eligible
Directors shall not be less than the benefit to which each such Eligible
Director would have been entitled if he or she had retired immediately prior to
such amendment or termination."
6. 1995, 1987, 1988 and 1989 Deferred Compensation Plans for Directors
-------------------------------------------------------------------
Section 9 of each of these plans is amended to read identically to the
amendment set forth in Section 1 of this Exhibit A.
EXHIBIT 10.21
RETIREMENT AGREEMENT
This Retirement Agreement ("Agreement"), is entered into by and between Richard
K. Bushey ("RKB") an individual, and Edison International ("EI"), a corporation.
In consideration of the covenants undertaken and the releases contained in this
Agreement and of RKB's more than 35 years of valued service, RKB on the one
hand, and EI on the other hand, agree as follows:
1. RKB will irrevocably resign as an officer of EI and Southern California
Edison ("SCE") effective December 31, 1998, by executing a letter
substantially in the form attached hereto as Exhibit A and incorporated
herein by reference. RKB will irrevocably retire from employment with EI
and SCE effective on the later of (a) April 1, 1999, or (b) the date when
an amendment providing for a lump sum payment option from the SCE Qualified
Retirement Plan (the "Qualified Plan") becomes effective. The date of RKB's
retirement as an employee of EI and SCE shall be referred to in this
Agreement as the "Effective Date". RKB will continue as an employee of EI
and SCE at no less than his current salary until the Effective Date and
agrees to provide services to EI and SCE, or to others on behalf of EI or
SCE, as mutually agreed upon by RKB and EI's Chief Financial Officer from
January 1, 1999, to the Effective Date.
2. RKB will be entitled to severance benefits equal to RKB's final annual
salary which will be credited to RKB's account under the Edison
International Executive Deferred Compensation Plan (the "Executive DCP") as
of the Effective Date.
3. Notwithstanding his resignation as an officer, RKB shall be considered an
SCE vice president-level executive for all executive benefit plan purposes
during the remainder of his employment, and upon his retirement, he shall
be entitled to benefits under such plans on the same basis as any SCE vice
president retiring
1
in 1999. RKB and his dependents will be entitled to health care benefits on
the same basis as other active SCE executives retiring in 1999.
4. RKB will be eligible for bonus award consideration under the Executive
Incentive Plan for 1998 and for the portion of 1999 that he works in
accordance with the terms of the plan.
5. RKB has Edison International nonqualified stock options outstanding under
the Equity Compensation Plan or predecessor plans. Notwithstanding any
terms in the option agreements to the contrary, and subject to approval of
the EI Compensation and Executive Personnel Committee ("CEP Committee"),
all of RKB's outstanding unvested options will vest on the Effective Date
and be exercisable for the full original terms of the agreements granting
such options.
6. RKB will receive retirement benefits under the Qualified Plan and the SCE
Executive Retirement Plan ("ERP"). With respect to RKB's benefits under the
Qualified Plan and the ERP, the parties understand and agree as follows:
a. RKB will receive, at his option, either a joint and survivor life
annuity or a lump sum payment under the Qualified Plan. The monthly
pension benefit payment available to RKB under the Qualified Plan
determined in accordance with plan practice assuming an April 1, 1999
Effective Date, is estimated to be approximately $6,609; the
actuarially determined lump sum payment equivalent to the joint and
survivor annuity is estimated to be approximately $885,000 based on
current interest rates. The lump sum amount that will be available to
RKB on the Effective Date will be based on the interest rate,
determined in accordance with plan practice, used for discounting
purposes that is in effect on the Effective Date.
b. RKB has elected the 120-month benefit payment option under the ERP.
The monthly benefit payments to RKB under the ERP will commence one
month after the Effective Date and will be payable for 120 months. The
initial monthly payment will be approximately $6,975 assuming an April
1, 1999 Effective Date. In accordance with plan practice, interest
will be credited
2
annually at the end of each calendar year and the monthly payment for
the following year will be recomputed to reflect the credited
interest.
c. Benefits under the Qualified Plan will continue for RKB's lifetime,
and upon his death, his eligible surviving spouse will commence
receiving a 50% survivor annuity payable under the terms of the
Qualified Plan for the balance of her life, unless RKB elects a lump
sum payment option for the Qualified Plan benefit, in which event RKB
shall be ineligible for the lifetime annuity and his surviving spouse
will not be eligible for a survivor annuity.
d. Based upon RKB's projected accrued sick leave, the total unused sick
leave allowance payable under the Qualified Plan and/or the ERP is
estimated to be $93,000. This amount is subject to change depending
upon sick leave usage prior to the Effective Date.
e. The maximum benefits payable under the Qualified Plan are subject to
IRS limitations. Because of these limitations, the portions of the
retirement benefits payable from the Qualified Plan and the ERP may
vary from the amounts shown in this Paragraph 6; however, the total of
the retirement benefits payable under the Qualified Plan and the ERP
will remain approximately as estimated.
7. Subject to approval of the CEP Committee of RKB's request to defer
commencement of payments from the EI Executive Deferred Compensation Plan,
the 1981A Deferred Compensation Plan and the 1985 Deferred Compensation
Plan, payments will commence on May 1, 2000. Interest will be credited to
RKB's Plan accounts at the rate of 8.16% per annum from the Effective Date
to April 30, 2000. Thereafter, interest will be credited at the rates and
subject to the terms and conditions of the respective plans.
8. EI will credit to RKB's Executive DCP account the sum of $100,000 on the
Effective Date, and will pay to RKB an additional $100,000 one year later,
and an additional $100,000 two years later, as retainer fees for RKB to
remain available as a consultant for a period of 36 months commencing on
the Effective Date to provide upon request by the EI Chief Financial
Officer, or his delegate,
3
information and assistance to EI or its affiliates with respect to any
matters handled by RKB or with which he became familiar while he was
employed by EI and SCE. RKB will receive no additional hourly or other
compensation for performing these consulting services, but EI will
reimburse RKB for any expenses incurred in connection with the providing
of such information and assistance as a consultant. EI agrees that it will
give RKB reasonable prior notice of its need for his assistance or
provision of information, which shall be no more than 39 hours per month,
and EI agrees that it shall set all meetings at reasonable times convenient
to RKB's schedule. RKB shall submit written statements accounting for his
expenses on a monthly basis, and EI will reimburse RKB for these expenses
within two weeks after each submittal.
9. On the Effective Date RKB will become the owner at no cost to RKB of the
personal computer and related equipment, the facsimile machine and selected
furniture and office decorations that EI provided for his use as identified
on the schedule attached hereto as Exhibit B and selected by RKB. The
values of such items are taxable income to RKB and subject to applicable
withholding of taxes pursuant to Paragraph 13 of this Agreement.
10. For the 36-month period immediately following the Effective Date, RKB will
not engage in any activity which is directly competitive with EI or any of
its affiliates, or serve on the Board of Directors of any corporation
engaged in any such business, or render services to any organization or
individual in connection with any matter in which the position of such
organization or individual is known to RKB to be adverse to the position of
EI, or any affiliate of EI, except with the written consent of the Chief
Executive Officer or General Counsel of EI.
11. RKB acknowledges that he is in possession of confidential trade secret and
business information not publicly available concerning EI and its
affiliates. RKB specifically agrees that he will not at any time, in any
fashion, form, or manner use or divulge, disclose or communicate to any
person, firm, or corporation, in any manner whatsoever, any confidential
information concerning any matters affecting or relating to the business of
EI and any of its affiliates.
4
12. RKB and EI expressly agree that, except to the extent this Agreement
imposes obligations upon the parties, this Agreement will never, at any
time, for any purpose whatsoever, be considered as an admission of
liability or responsibility of the parties or any of them. Moreover,
neither this Agreement nor anything in this Agreement will be construed to
be nor will be admissible in any proceeding as evidence of or an admission
by EI or any of its affiliates of any violation of its or their policies or
procedures, or of state or federal laws or regulations. This Agreement may
be introduced, however, in any proceeding to enforce the terms of this
Agreement. Such introduction must be pursuant to an order protecting the
confidentiality of this Agreement.
13. EI may withhold from any compensation or benefits payable under this
Agreement all federal, state and other taxes as may be required pursuant to
any law or governmental regulation or ruling. RKB agrees that he will be
exclusively liable for the payment of all federal and state taxes that may
be due from him as the result of the consideration received from EI herein.
14. If RKB has a right as a former employee and retiree to receive other plan
benefits not specifically addressed herein (by way of example and not by
way of limitation, benefits under the Stock Savings Plus Plan and other
executive retirement and post-retirement survivor benefits), RKB and his
beneficiaries will continue to have the right to such other benefits in
accordance with the terms of the respective plans.
15. This Agreement will be administered by EI, which will have the general
responsibility of reasonably interpreting this Agreement. Any controversy
or claim arising out of or relating to this Agreement or breach or alleged
breach of this Agreement, or to enforce or interpret this Agreement, which
cannot be resolved by the parties will be settled by arbitration to be held
in the County of Los Angeles in accordance with the Rules of the American
Arbitration Association, and judgment upon the award rendered by the
arbitrator(s) may be entered in any court having jurisdiction thereof. The
parties will equally divide the arbitrators' fees. The prevailing party
will be entitled to recover against the
5
other party reasonable attorney's fees, expenses and costs incurred in
connection with such proceedings including his or its one-half share
of the arbitrators' fees.
16. This Agreement will be binding upon any successor in interest of EI.
Neither this Agreement nor any right or interest hereunder will be
assignable by RKB without EI's prior written consent. Nothing herein will
restrict RKB's right to designate beneficiaries under any of the plans in
which he is a participant, provided such designations are not prohibited by
the applicable plan documents and are otherwise lawful, or to transfer
rights to income to any trust or other entity which he may establish for
estate planning purposes. Except as required by law, no right to receive
payments under this Agreement will be subject to anticipation, commutation,
alienation, sale, assignment, encumbrance, charge, pledge, or hypothecation
or to execution, attachment, levy, or similar process or assignment by
operation of law, and any attempt to effect such action will be null, void
and of no effect.
17. No provision of this Agreement may be amended, modified, or waived except
by written agreement signed by the parties hereto.
18. RKB acknowledges and understands that the confidentiality of this Agreement
is of the utmost concern to EI and that this Agreement would not have been
entered into by EI without his promise to keep such matter confidential.
Accordingly, RKB agrees that, except to the extent disclosure is required
by law or formal government demand, he will keep the terms and conditions
of this Agreement and the Agreement document itself confidential and he
will not disclose them to any other person, other than his wife, immediate
family members, legal advisors and/or other professional advisors, who will
also be advised of its confidentiality and who will agree to be bound by
this confidentiality agreement.
19. RKB acknowledges and understands that EI would not enter into this
Agreement without it serving as the means to compromise, resolve, settle,
and terminate any dispute or claim that may exist between them with respect
to RKB's
6
employment with EI and SCE and his retirement therefrom. RKB and
EI therefore agree that all of the payments, benefits and rights accruing
to RKB from EI pursuant to the terms of this Agreement are hereby made
expressly contingent upon RKB's delivery to EI of a fully executed and
valid release in the form attached as Exhibit C (the "Release") no earlier
than 30 days, nor later than 7 days, prior to the Effective Date.
20. This Agreement will be deemed to have been entered into in the State of
California and all questions concerning its validity, interpretation or
performance of any of its terms or provisions, or of any rights or
obligations of the parties hereto, will be governed and resolved in
accordance with the laws of the State of California. Furthermore, no
provision of this Agreement is to be interpreted for or against either
party because that party, or his legal representative, drafted such
provision.
21. RKB represents and agrees that he has carefully read and understands this
Agreement, and agrees that neither EI nor any officer, agent, or employee
of EI or any of its affiliates has made any representations other than
those contained herein. EI agrees that neither RKB nor any of his
representatives has made any representations other than those contained
herein. Further, RKB and EI expressly agree that they have entered into
this Agreement freely and voluntarily and without pressure or coercion from
the other or from their respective officers, agents, employees, or anyone
else acting on their behalf. RKB further expressly agrees that prior to the
execution of this Agreement, he was advised to seek independent legal
advice concerning the terms, conditions and effect of this Agreement.
22. RKB and EI represent and agree that this Agreement and the Release contain
the entire agreement and understanding between the parties hereto
concerning RKB's employment with and retirement from EI and SCE, and other
subject matters addressed herein. RKB and EI further represent and agree
that the Agreement and Release supersede and replace all prior negotiations
and agreements, proposed or otherwise, whether written or oral, concerning
the
7
subject matter hereof and that the Agreement and Release constitute an
integrated agreement, the terms of which are contractual in nature and not
a mere recital.
23. If any provision of this Agreement or the application thereof is held
invalid, the invalidity will not affect the other provisions or
applications, and to this extent, the provisions of this Agreement are
declared to be severable.
24. This Agreement may be executed in counterparts, and each counterpart, when
executed, will have the efficacy of a signed original. Photographic copies
of such signed counterparts may be used in lieu of the original for any
purpose.
IN WITNESS WHEREOF, RKB and EI have executed this Agreement on the dates
opposite their signatures.
I declare under penalty of perjury under the laws of the State of California
that I have carefully read the foregoing Agreement and know and fully understand
the terms and content thereof and I accept and agree to the provisions it
contains and hereby execute it voluntarily and as my own free act with full
understanding of its consequences.
Dated: September 15, 1998, at Richard K. Bushey
-----------------------------
Arcadia, California Richard K. Bushey
I warrant and represent that I have the authority to execute this Agreement on
behalf of EI.
EDISON INTERNATIONAL
Dated: October 5, 1998 at Alan J. Fohrer
-----------------------------
Rosemead, California Alan J. Fohrer
Its: Executive Vice President
& Chief Financial Officer
8
SPOUSE'S STATEMENT
I have carefully read the foregoing Agreement and I know and fully understand
the terms and content thereof. I understand that California is a community
property state, and to the extent I now or in the future may have any right,
title or interest in anything released, bargained for, received, or agreed to in
the Agreement, I hereby expressly agree to be completely bound by all provisions
of the Agreement. I have signed this statement as my own free act.
Dated: September 15, 1998 Janeil D. Bushey
-------------------------------
Arcadia, California Janeil D. Bushey
WITNESSED BY:
Dated: September 15, 1998 Karen M. Whitehill
---------------------------------
Karen M. Whitehill
9
EXHIBIT A
RICHARD K. BUSHEY
1030 Don Alvarado Drive
Arcadia, California 91006
February 18, 1999
Edison International
2244 Walnut Grove Avenue
Rosemead, California 91770
ATTENTION: Corporate Secretary
Ladies and Gentlemen:
This is to advise you that effective March 1, 1999, I hereby irrevocably and
voluntartily elect to resign as controller of Edison International ("EI"), and
Southern California Edison Company ("SCE") and that effective April 1, 1999, I
hereby irrevocably and voluntarily elect to resign as vice president of EI and
SCE and from other officer and/or director positions held with other affiliates
of EI and SCE. I am also electing to retire as an employee of EI and SCE
effective April 2, 1999. Subsequent to my retirement as an employee of EI and
SCE, I will not seek reemployment with EI, SCE or any of its other affiliates.
With your agreement and acceptance below, this letter will serve to supersede
and (1) amend the effective dates of my retirement and resignation as set forth
in the Retirement Agreement ("Agreement") which I executed on September 15,
1998, and Alan J. Fohrer executed on behalf of EI on October 5, 1998, and (2)
further amend such effective dates as set forth in a letter dated December 19,
1998, which amended the Agreement.
Please return one signed copy of this letter to me for my files.
Sincerely,
Richard K. Bushey
-----------------
Richard K. Bushey
SSN 561-52-9412
AGREED TO AND ACCEPTED:
EDISON INTERNATIONAL
By: Beverly P. Ryder Date: March 1, 1999
----------------
Beverly P. Ryder
Its: Corporate Secretary
10
EXHIBIT B
Description of Computer Equipment, Facsimile and Office Furnishings
Available to RKB at No Cost
1. Computer Equipment:
Dell Notebook
Dell Docking Station
Monitor, Speakers and Headphones
Keyboard
Mouse
HP Printer
Printer Table
2. Facsimile:
Brothers Model 6550MC
3. Office Furnishings:
Desk Unit
Sofa, Wing Chair, Coffee Table, End Table, Chow Table
Desk Chair
Side Chairs (4)
Pictures (3)
Desk Pad, Pen Set, Memo Pad Holders, Water Carafe, Clock
Lamps (2)
11
RELEASE
Richard K. Bushey ("RKB") and Edison International ("EI"), have entered into a
retirement agreement ("Retirement Agreement") whereby RKB has agreed to
irrevocably retire from employment with EI and Southern California Edison
("SCE") effective on the later of (a) April 1, 1999, or (b) the date when an
amendment providing for a lump sum payment option from the SCE Qualified
Retirement Plan becomes effective. As part of RKB's consideration under the
Retirement Agreement, and as a condition precedent to the additional payments
and benefits he will be entitled to receive pursuant to the Retirement
Agreement, RKB promised to deliver this executed Release to EI no sooner than 30
days nor later than 7 days prior to the effective date of the Retirement
Agreement. Now, therefore, RKB agrees as follows:
1. Except for obligations granted by or arising out of the Retirement
Agreement, and any applicable retirement, deferred compensation, stock
option, or welfare benefit plan, RKB, on his own behalf, and on the behalf
of his descendants, dependents, heirs, executors, administrators, assigns
and successors, as such, does hereby covenant not to sue and acknowledges
complete satisfaction of and hereby releases, absolves and discharges EI,
and its successors, assigns, subsidiaries, divisions and affiliated
corporations, past and present (including without limitation SCE and its
affiliates), and their trustees, directors, officers, shareholders, agents,
attorneys, insurers, and employees, past and present, and each of them, as
such (hereinafter in this Release collectively referred to as "EI
Releasees") with respect to and from any and all claims, demands, liens,
agreements, contracts, covenants, actions, suits, causes of action, wages,
obligations, debts, expenses, attorney's fees, damages, judgments, orders
and liabilities of whatever kind or nature in law, equity or otherwise,
without any exception whatsoever, and any and all claims, demands,
agreements, obligations, and causes of action, known or unknown, suspected
or
12
unsuspected, by RKB arising out of or in any way concerning the events
and/or circumstances surrounding his employment with EI and SCE or
separation and retirement therefrom.
2. RKB understands and expressly agrees that the release given by him in
Paragraph 1, above, without any exception whatsoever, extends to all
claims, injuries, damages or losses to his person and property, whether
known, unknown, foreseen, patent or latent, which he may have against the
EI Releasees or any of them. RKB specifically and expressly waives all his
rights under SECTION 1542 of the CALIFORNIA CIVIL CODE which provides as
follows:
"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT
KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE,
WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE
DEBTOR."
3. RKB expressly acknowledges and agrees that by entering into this Release,
he is waiving any and all rights or claims that he may have arising from
the Age Discrimination in Employment Act of 1967, as amended, which have
arisen on or before the date of execution of this Release. RKB further
acknowledges and agrees that:
o In return for executing this Release, he will receive compensation
beyond that which he was already entitled to receive before entering
into this Release;
o He is hereby advised in writing to consult with an attorney before
signing this Release;
o He was given a copy of this Release on February 5, 1999, and informed
that he has 21 days within which to consider the release and
voluntarily executed this Release before expiration of that 21-day
period; and
13
o He was informed that he has seven days following the date of execution
of this Release in which to revoke it.
IN WITNESS WHEREOF, RKB has executed this Release on the date opposite his
signature.
I declare under penalty of perjury under the laws of the State of California
that I have carefully read the foregoing Release and know and fully understand
the terms and content thereof and I accept and agree to the provisions it
contains and hereby execute it voluntarily and as my own free act with full
understanding of its consequences.
Dated: February 23, 1999, at Richard K. Bushey
Rosemead, California ------------------------------
Richard K. Bushey
14
EXHIBIT 12
SOUTHERN CALIFORNIA EDISON COMPANY AND CONSOLIDATED UTILITY-RELATED SUBSIDIARIES
RATIOS OF EARNINGS TO FIXED CHARGES AND PREFERRED AND PREFERENCE STOCK
(Thousands of Dollars)
Year Ended December 31,
- --------------------------------------------------------------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
- --------------------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES
AND FIXED CHARGES:
Income before interest expense(1) $1,127,275 $1,081,800 $1,143,477 $1,108,410 $1,049,866 $ 999,910
Add:
Taxes on income (2) 408,033 452,091 509,632 511,819 520,468 442,356
Rentals(3) 3,463 3,512 4,018 3,269 2,639 2,208
Allocable portion of interest
on long-term-term Contracts for
the purchase of power(4) 1,890 1,870 1,848 1,824 1,797 1,767
Spent nuclear fuel interest(6) 487 68 - - - -
Amortization of previously capitalized
fixed charges 4,878 2,271 1,185 814 1,127 1,571
- --------------------------------------------------------------------------------------------------------------------------
Total earnings before income
Taxes and fixed charges(A) $1,546,026 $1,541,612 $1,660,160 $1,626,136 $1,575,897 $1,447,812
- --------------------------------------------------------------------------------------------------------------------------
FIXED CHARGES:
- --------------------------------------------------------------------------------------------------------------------------
Interest and amortization $ 449,230 $ 443,219 $ 463,786 $ 453,015 $ 444,272 $ 484,788
Rentals(3) 3,463 3,512 4,018 3,269 2,639 2,208
Capitalized fixed charges-
nuclear fuel(5) 978 254 1,531 1,711 2,398 1,294
Allocable portion of interest on
long-term contracts for
the purchase of power(4) 1,890 1,870 1,848 1,824 1,797 1,767
Spent nuclear fuel interest(6) 487 68 - - - -
Preferred and preference stock dividend
Requirements - pre-tax basis 65,228 68,455 64,330 61,256 54,831 45,784
- --------------------------------------------------------------------------------------------------------------------------
Total fixed charges(B) $ 521,276 $ 517,378 $ 535,513 $ 521,075 $ 505,937 $ 535,841
- --------------------------------------------------------------------------------------------------------------------------
RATIO OF EARNINGS TO
FIXED CHARGES(A) (B) 2.97 2.98 3.10 3.12 3.11 2.70
- --------------------------------------------------------------------------------------------------------------------------
(1) Includes allowance for funds used during construction and accrual of
unbilled revenue.
(2) Includes allocation for 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.
(6) Represents interest on spent nuclear fuel disposal obligation.
EXHIBIT 13
Southern California Edison Company Logo
Southern California Edison Company
1998 Annual Report
- --------------------------------------------------------------------------------
A Profile of Southern California Edison Company
Southern California Edison (SCE) is the nation's second largest investor-owned
electric utility. Headquartered in Rosemead, California, SCE is a subsidiary of
Edison International, which is primarily an energy-services company.
SCE, a 113-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 Management's Discussion and Analysis of
Results of Operations and Financial Condition
13 Consolidated Financial Statements
17 Notes to Consolidated Financial Statements
35 Quarterly Financial Data
36 Responsibility for Financial Reporting
37 Report of Independent Public Accountants
38 Selected Financial and Operating Data: 1994-1998
39 Board of Directors
39 Management Team
- --------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Results of Operations
Earnings
Southern California Edison Company's (SCE) 1998 earnings were $490 million,
compared with $576 million in 1997 and $621 million in 1996. SCE's 1996 earnings
included special charges of $18 million for workforce management costs and
reserves. The $86 million earnings decline in 1998 was primarily due to lower
authorized revenue, which resulted from reduced authorized returns on generating
assets and a lower earning asset base resulting from the accelerated recovery of
investments and divestiture of gas- and oil-fueled generation assets, partially
offset by superior operating performance at the San Onofre Nuclear Generating
Station. Before special charges, 1997 earnings declined $63 million compared to
the prior year, mainly due to the extended outage and lower return at San
Onofre. The decline was partially offset by higher sales and lower non-nuclear
operating expenses.
Operating Revenue
Since April 1, 1998, SCE has been required to sell all of its generated power to
the power exchange (PX). For more details, see Competitive Environment.
Excluding the sales to the PX, operating revenue decreased 6% from 1997. The
decrease reflects lower average residential rates (mandated by legislation
enacted in September 1996), partially offset by an increase in other revenue
resulting from maintenance work SCE is providing for the new owners of the
divested gas- and oil-fueled plants, as required by the restructuring
legislation. Operating revenue increased 5% in 1997 over 1996, due to an
increase in sales volume and customer refunds in 1996. There were no comparable
refunds in 1997. The increase in volume is mainly attributable to the overall
increase in retail sales among residential and commercial customers due to
unusually warm weather during the third quarter of 1997. In 1998, over 99% of
operating revenue (excluding sales to the PX) was from retail sales. Retail
rates are regulated by the California Public Utilities Commission (CPUC) and
wholesale rates are regulated by the Federal Energy Regulatory Commission
(FERC).
Due to warmer weather during the summer months, operating revenue (excluding
sales to the PX) during the third quarter of each year is significantly higher
than other quarters.
The changes in operating revenue (excluding sales to the PX) resulted from:
In millions Year ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
Operating revenue --
Rate changes (including refunds) $(527) $173 $(522)
Sales volume changes (44) 193 206
Other 117 4 26
- -------------------------------------------------------------------------------------------------------------------
Total $(454) $370 $(290)
- -------------------------------------------------------------------------------------------------------------------
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction (financed through the issuance of rate reduction notes) for
residential and small commercial customers in 1998 and other rates to remain
frozen at June 1996 levels (system average of 10.1(cent) per kilowatt-hour). See
discussion in Competitive Environment.
Operating Expenses
Fuel expense decreased 63% in 1998, primarily due to the sale of the gas- and
oil-fueled generation plants, as well as significantly lower gas prices in the
first quarter of 1998. Fuel expense increased 40% in 1997 over 1996. The
increase was due to a $174 million gas contract termination payment during the
third quarter of 1997, combined with higher gas prices and the extended
refueling outages at San Onofre. San Onofre Unit 2 was shut down during the
entire first quarter of 1997, Unit 3 was shut down 80 days of the second quarter
and both units had a combined outage time of 30 days during the third
1
- --------------------------------------------------------------------------------
Southern California Edison Company
quarter, which resulted in an overall increase in gas-powered generation for
1997. There were no comparable outages in 1996.
Since April 1, 1998, SCE has been required to purchase all of its power from the
PX for distribution to its retail customers. SCE is continuing to purchase power
from certain nonutility generators (known as qualifying facilities) and under
existing inter-utility contracts. This purchased power is sold to the PX.
Excluding the power purchased from the PX, purchased-power expense decreased
slightly in 1998, while increasing slightly in 1997. SCE is required under
federal law to purchase power from certain qualifying facilities even though
energy prices under these contracts are generally higher than other sources. In
1998, SCE paid about $1.5 billion (including energy and capacity payments) more
for these power purchases than the cost of power available from other sources.
The CPUC has mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased in 1998, mainly due to
the rate-making treatment of the rate reduction notes. This rate-making
treatment has allowed for the deferral of the collection of a portion of the
transition-related revenue, from a four-year period to a 10-year period. This
decrease was almost completely offset by overcollections resulting from the gain
on sales of the gas- and oil-fueled generation plants during 1998 and other
transition costs, as well as overcollections related to the administration of
public-purpose funds. The provisions for regulatory adjustment clauses decreased
substantially in 1997, due to undercollections in the energy cost balancing
account as actual energy costs (including the gas termination payment discussed
above) exceeded CPUC-authorized fuel and purchased-power cost estimates. In
addition, there were undercollections associated with SCE's direct access
activities (see discussion in Competitive Environment), research and development
activities, and San Onofre. These undercollections were offset by
overcollections related to actual base-rate revenue from kilowatt-hour sales
exceeding CPUC-authorized estimates and the final settlement of SCE's Canadian
supply and transportation contracts.
Other operating expenses increased 22% in 1998, primarily due to must-run
reliability services, direct access activities, and PX and independent system
operator (ISO) costs incurred by SCE. Also, storm damage expense resulting from
the harsh winter in 1998 contributed to the increase.
Maintenance expense increased 23% in 1997, due to higher maintenance costs at
the transmission and distribution operating facilities, and the scheduled
refueling outages at the San Onofre units.
Depreciation, decommissioning and amortization expense increased 25% in 1998,
primarily due to the further acceleration of recovery of San Onofre Units 2 and
3 and the Palo Verde Nuclear Generating Station units, accelerated recovery of
the gas- and oil-fueled generation plants, and the amortization of the loss on
plant sales. The amortization of the loss on plant sales, as well as the
accelerated recoveries implemented in 1998 are part of the competition
transition charge (CTC) mechanism. Depreciation, decommissioning and
amortization expense increased 17% in 1997, mainly due to increases in plant
assets and the accelerated recovery of the Palo Verde units, effective January
1997.
Income taxes decreased 23% in 1998, primarily due to lower pre-tax income, as
well as additional amortization related to the CTC mechanism.
Property and other taxes decreased 32% in 1997, due to a reclassification of
payroll taxes to operation and maintenance expense.
Gain on sale of utility plant represents the net result from the sale of the
gas- and oil-fueled generation plants in 1998. Gains on sales of the gas- and
oil-fueled plants were used to reduce stranded costs. Losses on sales will be
recovered from customers over the transition period.
Other Income and Deductions
The provision for rate phase-in plan reflected a CPUC-authorized, 10-year rate
phase-in plan, which deferred the collection of revenue during the first four
years of operation for the Palo Verde units. The deferred revenue (including
interest) was collected evenly over the final six years of each unit's plan.
2
- --------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations
and Financial Condition
The plan ended in February 1996, September 1996 and January 1998 for Units 1, 2
and 3, respectively. The provision was a non-cash offset to the collection of
deferred revenue.
Interest and dividend income increased 49% in 1998, reflecting higher investment
balances due to the sale of the gas- and oil-fueled generation plants, as well
as increases in interest earned on higher balancing account undercollections. In
1997, interest and dividend income increased 18% due to increases in interest
earned on balancing accounts and increases in dividend income from equity
investments.
Other nonoperating income increased 81% in 1998, when compared to 1997,
primarily due to the additional accruals in 1997 for regulatory matters. These
accruals caused a substantial decrease in other nonoperating income in 1997,
when compared to 1996.
Interest Expense
Interest on long-term debt increased 22% in 1998, mainly due to the issuance of
the rate reduction notes in December 1997. In 1997, interest on long-term debt
decreased due to the early retirement of $400 million of first and refunding
mortgage bonds in July 1997, partially offset by the additional interest expense
associated with the rate reduction notes issued in December 1997. Interest on
the rate reduction notes was $148 million in 1998 and $9 million in 1997.
Other interest expense decreased substantially in 1998, mostly due to lower
overall short-term debt balances, particularly short-term debt used to finance
fuel inventories. These fuel inventories are no longer needed because of the
divestiture of the gas- and oil-fueled plants. Other interest expense increased
substantially in 1997, due to higher levels of short-term debt used to retire
first and refunding mortgage bonds.
Financial Condition
SCE's liquidity is primarily affected by debt maturities, dividend payments and
capital expenditures. Capital resources include cash from operations and
external financings.
Edison International's board of directors has authorized the repurchase of up to
$2.8 billion (increased from $2.3 billion in July 1998) of its outstanding
shares of common stock. Edison International repurchased 100.4 million shares
($2.4 billion) between January 1995 and February 4, 1999, funded by dividends
from its subsidiaries and the issuance of rate reduction notes.
SCE's cash flow coverage of dividends was 0.9 times for both 1998 and 1997 and
2.2 times in 1996. The 1998 decrease reflects the $680 million special dividend
SCE paid to Edison International in 1998 from the gas- and oil-fueled plant
sales proceeds, as well as the rate-making treatment of the gains on sales of
the gas- and oil-fueled plants. The 1997 decrease reflects the $1.2 billion
special dividend SCE paid to Edison International in December 1997 from rate
reduction note proceeds.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.0 billion in 1998, $1.7
billion in 1997 and $1.8 billion in 1996. Cash from operations exceed capital
requirements for all years presented.
Cash Flows from Financing Activities
At December 31, 1998, SCE had available lines of $1.3 billion, with $800 million
for general purpose, short-term debt and $500 million for the long-term
refinancing of its variable-rate pollution-control bonds. These unsecured lines
of credit are at negotiated or bank index rates and expire in 2002.
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Southern California Edison Company
Short-term debt is used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital expenditures.
External financings are influenced by market conditions and other factors,
including limitations imposed by SCE's articles of incorporation and trust
indenture. As of December 31, 1998, SCE could issue approximately $13.9 billion
of additional first and refunding mortgage bonds and $4.4 billion of preferred
stock at current interest and dividend rates.
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. At December 31, 1998,
SCE had the capacity to pay $794 million in additional dividends and continue to
maintain its authorized capital structure.
In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE
is the sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. The proceeds of the rate reduction notes were used by
the SPE to purchase from SCE an enforceable right known as transition property.
Transition property is a current property right created pursuant to the
restructuring legislation and a financing order of the CPUC, and consists
generally of the right to be paid a specified amount from a non-bypassable
tariff levied on residential and small commercial customers. Notwithstanding the
legal sale of the transition property by SCE to the SPE, the amounts reflected
as assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to the SPE, and the liabilities of the SPE for the rate
reduction notes are for accounting purposes reflected as long-term liabilities
on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities.
The rate reduction notes have maturities ranging from one to nine years, and
bear interest at rates ranging from 6.14% to 6.42%. The rate reduction notes are
secured solely by the transition property and certain other assets of the SPE,
and there is no recourse to SCE or Edison International.
Although the SPE is consolidated with SCE in the financial statements, as
required by generally accepted accounting principles, the SPE is legally
separate from SCE, the assets of the SPE are not available to creditors of SCE
or Edison International, and the transition property is legally not an asset of
SCE or Edison International.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, proceeds from the sale of plant (see discussion in Competitive
Environment) and funding of nuclear decommissioning trusts. Decommissioning
costs are accrued and recovered in rates over the term of each nuclear
generating facility's operating license through charges to depreciation expense.
SCE estimates that it will spend approximately $8.6 billion between 2000--2070
to decommission its nuclear facilities. This estimate is based on SCE's
current-dollar decommissioning costs ($1.9 billion), escalated at rates
averaging 5.6% annually. These costs are expected to be funded from independent
decommissioning trusts, which currently receive SCE contributions of
approximately $100 million per year. However, SCE has requested the CPUC to
authorize a reduction in the annual contributions to the decommissioning trusts
beginning January 1, 2000. The plan to decommission San Onofre Unit 1 beginning
in 2000, which is pending CPUC approval, is not expected to affect SCE's annual
contributions to the decommissioning trusts.
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in 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.
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Management's Discussion and Analysis of Results of Operations
and Financial Condition
As a result of the rate freeze established in the restructuring legislation,
SCE's transition costs are recovered as the residual component of rates once the
costs for distribution, transmission, public purpose programs, nuclear
decommissioning and the cost of supplying power to its customers through the PX
and ISO have already been recovered. Accordingly, more revenue will be available
to cover transition costs when market prices in the PX and ISO are low than when
PX and ISO prices are high. The PX and ISO market prices to date have generally
been reasonable, although some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap of $250/MW on the market for such
services until certain actions have been completed to improve the functioning of
those markets. Similarly, the ISO currently maintains a cap of $250/MWh on its
market for imbalance energy while a software problem affecting the efficient
operation of that market persists. The caps in these markets mitigate the risk
of costly price spikes that would reduce the revenue available to SCE to pay
transition costs. During the upcoming year, the ISO will be considering removing
these price caps, which could increase the risk of high market prices. SCE has
entered into hedges against high natural gas prices, since increases in natural
gas prices tend to raise the price of electricity purchased from the PX.
A 10% increase in market interest rates would result in a $7 million increase in
the fair value of SCE's interest rate hedge agreements. A 10% decrease in market
interest rates would result in a $7 million decline in the fair market value of
interest rate hedge agreements. A 10% increase in natural gas prices would
result in a $21 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in a $14 million decline in the
fair market value of gas call options. A 10% change in market rates is expected
to have an immaterial effect on SCE's other financial instruments.
Projected Capital Requirements
SCE's projected construction expenditures for the next five years are: 1999 --
$922 million; 2000 -- $831 million; 2001 -- $726 million; 2002 -- $699 million;
and 2003 -- $689 million.
Long-term debt maturities and sinking fund requirements for the next five years
are: 1999-- $401 million; 2000-- $571 million; 2001-- $646 million; 2002-- $446
million; and 2003-- $371 million.
Preferred stock redemption requirements for next five years are: 1999 through
2001 -- zero; 2002 -- $105 million; and 2003 -- $9 million.
Regulatory Matters
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction for residential and small commercial customers in 1998 and other
rates to remain frozen at June 1996 levels (system average of 10.1(cent) per
kilowatt-hour).
In 1999, revenue will be determined by various mechanisms depending on the
utility operation. Revenue related to distribution operations will be determined
through a performance-based rate-making mechanism (PBR) and the distribution
assets will have the opportunity to earn a CPUC-authorized 9.49% return. The
distribution-only PBR will extend through December 2001. Transmission revenue
will be determined through FERC-authorized rates and transmission assets will
earn a 9.43% return. These rates are subject to refund. Key elements of PBR
include: transmission and distribution (T&D) 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 bond index; standards for service reliability and safety;
and a net revenue-sharing mechanism that determines how customers and
shareholders will share gains and losses from T&D operations.
Revenue from generation-related operations will be determined through the
competitive market and the CTC mechanism, which now includes the nuclear
rate-making agreements. Revenue related to fossil and hydroelectric generation
operations is recovered from two sources. The portion that is made uneconomic by
electric industry restructuring is recovered through the CTC mechanism. The
portion that is economic is recovered through the market. In 1999, fossil and
hydroelectric generation assets will earn a 7.22% return.
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Southern California Edison Company
In 1996 and 1997, the CPUC authorized revised rate-making plans for SCE's
nuclear facilities, which call for the accelerated recovery of the nuclear
investments in exchange for a lower authorized rate of return. SCE's nuclear
assets are earning an annual rate of return of 7.35%. In addition, the San
Onofre plan authorizes a fixed rate of approximately 4(cent) per kilowatt-hour
generated for operating costs including incremental capital costs, and nuclear
fuel and nuclear fuel financing costs. The San Onofre plan commenced in April
1996, and ends in December 2001 for the accelerated recovery portion and in
December 2003 for the incentive-pricing portion. Palo Verde'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. Beginning January 1, 1998, both the
San Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
The changes in revenue from the regulatory mechanisms discussed above, excluding
the effects of other rate actions, are expected to have an approximately $20
million negative impact on 1999 earnings.
The CPUC is considering unbundling SCE's cost of capital based on major utility
function. In May 1998, SCE filed an application on this issue and hearings were
completed in October 1998. A CPUC decision is expected in early to mid-1999.
Competitive 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. This regulatory environment is changing.
The generation sector has experienced competition from nonutility power
producers and regulators are restructuring California's electric utility
industry.
California Electric Utility Industry Restructuring
Restructuring Decision and Statute -- The CPUC's December 1995 decision on
restructuring California's electric utility industry started the transition to a
new market structure involving competition and customer choice. The State of
California enacted legislation in 1996 to provide a transition to a competitive
market structure. The Statute substantially adopted the CPUC's restructuring
decision by addressing stranded-cost recovery for utilities and providing a
certain cost-recovery time period for the transition costs associated with
utility-owned generation-related assets. Transition costs related to
power-purchase contracts are being recovered through the terms of their
contracts while most of the remaining transition costs will be recovered through
2001. The Statute also 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. The Statute included a rate freeze for all
other customers, including large commercial and industrial customers, as well as
provisions for continued funding for energy conservation, low-income programs
and renewable resources. Despite the rate freeze, SCE expects to be able to
recover its revenue requirement during the 1998--2001 transition period. In
addition, the Statute mandated the implementation of the CTC that provides
utilities the opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the Statute contained provisions for the recovery
(through 2006) of reasonable employee-related transition costs, incurred and
projected, for retraining, severance, early retirement, outplacement and related
expenses. The new market structure and customer choice began on April 1, 1998.
1998 Activities -- During 1998, SCE implemented changes to comply with
restructuring elements required by the CPUC and the Statute. Beginning January
1, 1998:
o SCE's rates were unbundled into separate charges for energy, transmission,
distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component is being collected through FERC-approved rates,
subject to refund.
o SCE's costs associated with its hydroelectric plants are being recovered
through a performance-based mechanism. The mechanism sets the hydroelectric
revenue requirement and establishes a formula for extending it through the
duration of the electric industry restructuring transition
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Management's Discussion and Analysis of Results of Operations
and Financial Condition
period, or until market valuation of the hydroelectric facilities,
whichever occurs first. The mechanism provides that power sales
revenue from hydroelectric facilities in excess of the hydroelectric
revenue requirement be credited against the costs to transition to a
competitive market.
o SCE transition costs are being recovered through a non-bypassable CTC. This
charge applies to all customers who were using or began using utility
services on or after the CPUC's December 1995 restructuring decision date.
SCE has estimated its transition costs to be approximately $10.6 billion
(1998 net present value) from 1998 through 2030. This estimate was based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect these
estimates. The potential transition costs are comprised of $6.4 billion
from SCE's qualifying facilities contracts, which are the direct result of
prior legislative and regulatory mandates, and $4.2 billion (which reflects
the sale of SCE's gas- and oil-fueled generation plants) from costs
pertaining to certain generating assets and regulatory commitments
consisting of costs incurred (whose recovery has been deferred by the CPUC)
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 San Onofre Units 2 and 3
and the Palo Verde units (as discussed in Regulatory Matters), and certain
other costs.
o Residential and small commercial customers who began receiving a 10% rate
reduction are repaying the rate reduction notes issued in December 1997
(see further discussion in Cash Flows from Financing Activities) through
non-bypassable charges based on electricity consumption.
Effective April 1, 1998:
o The ISO assumed operational control of the transmission system after the
ISO and PX had begun accepting bids and schedules for electricity purchases
on March 31, 1998. The restructuring implementation costs related to the
start-up and development of the PX, which are paid by the utilities, will
be recovered from all retail customers over the four-year transition
period. SCE's share of the charge is $45 million, plus interest and fees.
SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a 10-year period.
o Customers can choose to remain utility customers with either bundled
electric service or an hourly PX pricing option from SCE (which is
purchasing its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or energy service providers (ESPs) such as power brokers, marketers and
aggregators. Electric utilities are continuing to provide the core
distribution service of delivering energy through their distribution system
regardless of a customer's choice of electricity supplier. The CPUC is
continuing to regulate the prices and service obligations related to
distribution services. As of December 31, 1998, approximately 47,000 of
SCE's 4.3 million customers have requested the direct access option.
o Customers have options regarding metering, billing and related services
(referred to as revenue cycle services) that have been provided by
California's investor-owned utilities. ESPs can provide their customers
with one consolidated bill for their services and the utility's services,
request the utility to provide such a consolidated bill to the customer or
elect to have both the ESP and the utility bill the customer for their
respective charges. Customers with maximum demand above 20 kW (primarily
industrial and medium and large commercial) can choose SCE or any other
supplier to provide their metering service. Beginning in January 1999, all
customers can make these choices. In September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they
elect to obtain revenue cycle services from someone other than SCE.
Although the decision adopted SCE's recommendation of using the net avoided
cost, it also adopted a methodology which results in higher credits to
customers but requires
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Southern California Edison Company
ESPs to pay service fees to SCE for the costs that SCE incurs as a
result of dealing with the ESP. SCE may experience a reduction in revenue
security asa result of this unbundling.
During 1998, SCE sold all of its gas- and oil-fueled generation plants. The
total sales price of the 12 plants was $1.2 billion, over $500 million more than
the combined book value. Net proceeds of the sales were used to reduce stranded
costs, which otherwise were expected to be collected through the CTC mechanism.
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described above, SCE would be allowed to recover
its transition costs through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be subject
to a lower authorized rate of return). In 1997, SCE discontinued application of
accounting principles for rate-regulated enterprises for its investment in
generation facilities based on new accounting guidance. The financial reporting
effect of this discontinuance was to segregate these assets on the balance
sheet; the new guidance did not require SCE to write off any of its
generation-related assets, including related regulatory assets. However, the new
guidance did not specifically address the application of asset impairment
standards to these assets. SCE has retained these assets on its balance sheet
because the Statute and restructuring plan referred to above make probable their
recovery through a non-bypassable CTC to distribution customers. The regulatory
assets relate primarily to the recovery of accelerated income tax benefits
previously flowed through to customers, purchased power contract termination
payments and unamortized losses on reacquired debt. The new accounting guidance
also permits the recording of new generation-related regulatory assets during
the transition period that are probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording 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 future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.4
billion, after tax, at December 31, 1998) as a one-time, non-cash charge against
earnings.
If events occur during the restructuring process that result in all or a portion
of the transition costs being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other revisions will
ultimately be made during the restructuring process in subsequent proceedings or
the effect, after the transition period, that competition will have on its
results of operations or financial position.
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 10 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 reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site. Unless
there is a probable amount, SCE records the lower end of this likely range of
costs.
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Management's Discussion and Analysis of Results of Operations
and Financial Condition
SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $171 million. One of SCE's sites, a former pole-treating facility, is
considered a federal Superfund site and represents 41% of its recorded
liability. 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. SCE believes that, due to these uncertainties, it is reasonably
possible that cleanup costs could exceed its recorded liability by up to $247
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 power plants and has retained some liability
associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $88 million of its recorded liability, through an incentive
mechanism. 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 $141 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
$4 million to $10 million. Recorded costs for 1998 were $7 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 1990 federal 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).
The act also calls for a study to determine if additional regulations are needed
to reduce regional haze in the southwestern U.S. In addition, another study is
in progress to determine the specific impact of air contaminant emissions from
the Mohave Coal Generating Station on visibility in Grand Canyon National Park.
The potential effect of these studies on sulfur dioxide emissions regulations
for Mohave is unknown.
SCE's projected environmental capital expenditures are $900 million for the
1999--2003 period, mainly for aesthetics treatment, including undergrounding
certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF) emanating
from power lines, household appliances and other electric sources may result in
adverse health effects has been the subject of scientific research. After many
years of research, scientists have not found that exposure to EMF causes disease
in humans. Research on this topic is continuing. However, the CPUC has issued a
decision, which provides for a rate-recoverable research and public education
program conducted by California electric utilities, and authorizes these
utilities to take no-cost or low-cost steps to reduce EMF in new electric
facilities. SCE is unable to predict when or if the scientific community will be
able to reach a consensus on any health effects of EMF, or the effect that such
a consensus, if reached, could have on future electric operations.
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Southern California Edison Company
San Onofre Steam Generator Tubes
The San Onofre Units 2 and 3 steam generators have performed relatively well
through the first 15 years of operation, with low rates of ongoing steam
generator tube degradation. However, during the Unit 2 scheduled refueling and
inspection outage in 1997, an increased rate of tube degradation was identified,
which resulted in the removal of more tubes from service than had been expected.
The steam generator design allows for the removal of up to 10% of the tubes
before the rated capacity of the unit must be reduced. As a result of the
increased degradation, a mid-cycle inspection outage was conducted in early 1998
for Unit 2. Continued degradation was found during this inspection. A favorable
or decreasing trend in degradation was observed during inspection in the
scheduled refueling outage in January 1999. The results of the January 1999
inspection are being analyzed to determine if there is a need for a mid-cycle
inspection outage in early 2000. With the results from the January 1999 outage,
7.5% of the tubes have now been removed from service. In September 1998, San
Onofre Unit 2 experienced a small amount of leakage from a steam generator tube
plug, which required an 11-day outage to repair.
During Unit 3's refueling outage, which was completed in July 1997, inspections
of structural supports for steam generator tubes identified several areas where
the thickness of the supports had been reduced, apparently by erosion during
normal plant operation. A follow-up mid-cycle inspection indicated that the
erosion had been stabilized. Additional monitoring inspections are planned
during the next scheduled refueling outage in 1999. To date, 5% of Unit 3's
tubes have been removed from service.
During Unit 2's February 1998 mid-cycle outage, similar tube supports showed no
significant levels of such erosion.
New Accounting Rules
A recently issued accounting rule requires that costs related to start-up
activities be expensed as incurred, effective January 1, 1999. SCE does not
expect this new accounting rule to materially affect its results of operations
or financial position.
In June 1997, a new accounting standard for reporting operating segment
information was issued. The new standard, which became effective for financial
reports issued after December 15, 1998, requires that operating segment
information be disclosed in the Notes to the Consolidated Financial Statements.
Since, in management's view, SCE currently operates as one segment, this
standard is not expected to affect SCE's consolidated financial statements and
the accompanying notes to the consolidated financial statements.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to 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 reflected in 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 anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
Year 2000 Issue
Many of SCE's existing computer systems were originally programmed to represent
any date by using six digits (e.g., 12/31/99) rather than eight digits (e.g.,
12/31/1999). Accordingly, such programs, if not appropriately addressed, could
fail or create erroneous results when attempting to process information
containing dates after December 31, 1999. This situation has been referred to
generally as the Year 2000 Issue.
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Management's Discussion and Analysis of Results of Operations
and Financial Condition
SCE has a comprehensive program in place to address potential Year 2000 impacts.
Edison International provides overall coordination of this effort, working with
SCE and its business units. SCE divides Year 2000 activities into five phases:
inventory, impact assessment, remediation, testing and implementation. SCE's
objective for the Year 2000 readiness of critical systems is to be 100% complete
by July 1999. A critical system is defined as those applications and systems,
including embedded processor technology, which if not appropriately remediated,
may have a significant impact on customers, the health and safety of the public
and/or personnel, the revenue stream, or regulatory compliance. SCE was 80%
complete at year-end 1998 (the goal was 75%) and is on track to meets its July
1999 goal.
A system, application or physical asset is deemed to be Year 2000-ready if it is
determined by SCE to be suitable for continued use through the year 2028 (or
through the last year of the anticipated life of the asset, whichever occurs
first), even though it is not fully Year 2000-compliant. A system, application,
or physical asset is Year 2000-compliant if it accurately processes date/time
data.
SCE has structured the scope of the program to focus on three principal
categories: mainframe computing, distributed computing and physical assets (also
known as embedded processors). The mainframe and distributed computing assets
consist of computer application systems (software). Physical assets include
information technology infrastructure (hardware, operating system software) and
embedded processor technology in generation, transmission, distribution, and
facilities components.
Year 2000-readiness preparations for SCE's mainframe financial systems were
completed in the fourth quarter of 1997, and preparations for SCE's material
management system were completed in the second quarter of 1998. SCE's customer
information and billing system is in the process of being replaced with a system
designed to be Year 2000-ready and final conversion activities are expected to
be completed during the first quarter of 1999. SCE's distributed computing
assets include operations and business information systems. SCE's critical
operations information systems include outage management, power management, and
plant monitoring and access retrieval systems. SCE's business information
systems include a data acquisition system for billing, the computer call center
support system, credit support and maintenance management.
Ongoing efforts in 1999 will continue to focus on guarding against
reintroduction of components that are not Year 2000-ready into Year 2000-ready
systems.
The other essential component of the SCE Year 2000-readiness program is to
identify and assess vendor products and business partners for Year 2000
readiness, as these external parties may have the potential to impact SCE's Year
2000 readiness. SCE has implemented a process to identify and contact vendors
and business partners to determine their Year 2000 status, and is evaluating the
responses. As of January 31, 1999, Edison International has contacted over 4,300
critical vendors and business partners (the largest percentage of which are
SCE's vendors and business partners). SCE's general policy requires that all
newly purchased products and services be Year 2000-ready or otherwise designed
to allow SCE to determine whether such products and services present Year 2000
issues. SCE is also working to address Year 2000 issues related to all ISO and
PX interfaces, as well as joint ownership facilities. SCE exchanges Year
2000-readiness information (including, but not limited to, test results and
related data) with certain of its affiliates and other external parties as part
of its Year 2000-readiness efforts.
SCE's current estimate of the costs to complete these modifications, including
the cost of new hardware and software application modification, is $72 million,
about 40% of which is expected to be capital costs. SCE's Year 2000 costs
expended through December 31, 1998, were $35 million. SCE expects current rate
levels for providing electric service to be sufficient to provide funding for
utility-related modifications.
Although SCE expects that its critical systems will be fully Year 2000-ready
prior to year-end 1999, there can be no assurance that the systems of other
companies on which the systems and operations of SCE rely will be converted on a
timely basis. SCE believes that prudent business practices call for the
11
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Southern California Edison Company
development of contingency plans. Such contingency plans shall include
developing strategies for dealing with the most reasonably likely worst case
scenario concerning Year 2000-related processing failures or malfunctions caused
by SCE's internal systems or from external parties. As noted above, SCE has, in
many cases, completed its Year 2000-readiness work and is currently in the
remediation and testing phases for certain of their other internal systems as
well as assessing risks posed by external parties. SCE is working with industry
groups in an effort to help define a reasonably likely worst case scenario and
in the development of contingency plans. SCE's contingency plans, which will
include scheduling of key personnel, are expected to be completed by March 1999.
As of January 31, 1999, draft component and system contingency plans were
completed and being evaluated, draft plans were in progress for generating
units, and a draft of the grid operations plan had been submitted to the Western
Systems Coordinating Council. However, contingency plans will continue to be
revised and enhanced as 2000 approaches. SCE also plans to test these
contingency plans by conducting or participating in exercises during 1999. Also,
SCE is scheduled to participate in industry-wide drills during 1999.
SCE does not expect the Year 2000 Issue to have a material adverse effect on its
results of operation or financial position; however, if not effectively
remediated, negative effects from Year 2000 issues, including those related to
internal systems, vendors, business partners, the ISO, the PX or customers,
could cause results to differ.
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 further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business, including direct customer access to retail energy suppliers and the
unbundling of revenue cycle services such as metering and billing; changes in
prices of electricity and fuel costs; changes in market interest rates; new or
increased environmental liabilities; the effects of the Year 2000 Issue; and
other unforeseen events.
12
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Consolidated Statements of Income Southern California Edison Company
In thousands Year ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
Sales to ultimate consumers $ 7,104,800 $ 7,639,417 $ 7,272,919
Sales to power exchange 1,347,579 -- --
Other 394,719 313,969 310,463
- -----------------------------------------------------------------------------------------------------------------
Operating revenue 8,847,098 7,953,386 7,583,382
- -----------------------------------------------------------------------------------------------------------------
Fuel 323,716 881,471 630,512
Purchased power-- contracts 2,625,900 2,854,002 2,705,880
Purchased power-- power exchange 1,983,922 -- --
Provisions for regulatory adjustment clauses-- net (472,519) (410,935) (225,908)
Other operating expenses 1,480,644 1,216,317 1,181,641
Maintenance 410,566 405,545 329,371
Depreciation, decommissioning and amortization 1,545,735 1,239,878 1,063,505
Income taxes 445,642 582,031 578,329
Property and other taxes 128,402 129,038 190,284
Net gains on sale of utility plant (542,608) (3,849) (3,325)
- -----------------------------------------------------------------------------------------------------------------
Total operating expenses 7,929,400 6,893,498 6,450,289
- -----------------------------------------------------------------------------------------------------------------
Operating income 917,698 1,059,888 1,133,093
- -----------------------------------------------------------------------------------------------------------------
Provision for rate phase-in plan -- (48,486) (84,288)
- -----------------------------------------------------------------------------------------------------------------
Allowance for equity funds used during construction 11,826 7,651 15,579
Interest and dividend income 66,725 44,636 37,855
Other nonoperating income (deductions)-- net (4,385) (23,036) (3,623)
Total other income (deductions)-- net 74,166 (19,235) (34,477)
- -----------------------------------------------------------------------------------------------------------------
Income before interest expense 991,864 1,040,653 1,098,616
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
Interest on long-term debt 421,857 345,592 380,812
Other interest expense 64,225 101,078 73,914
Allowance for borrowed funds used during construction (8,046) (9,213) (9,794)
Capitalized interest (1,294) (2,398) (1,711)
- -----------------------------------------------------------------------------------------------------------------
Total interest expense-- net 476,742 435,059 443,221
- -----------------------------------------------------------------------------------------------------------------
Net income 515,122 605,594 655,395
Dividends on preferred stock 24,632 29,488 34,395
- -----------------------------------------------------------------------------------------------------------------
Earnings available for common stock $ 490,490 $ 576,106 $ 621,000
- -----------------------------------------------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
In thousands Year ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
Net income $ 515,122 $605,594 $655,395
Unrealized gain on securities - net 9,275 14,641 14,900
Reclassification adjustment for gains included in net income (17,836) -- --
- -----------------------------------------------------------------------------------------------------------------
Comprehensive income $ 506,561 $620,235 $670,295
- -----------------------------------------------------------------------------------------------------------------
The accompanying notes are integral part of these financial statements.
13
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Consolidated Balance Sheets
In thousands December 31, 1998 1997
- -----------------------------------------------------------------------------------------------------------------
ASSETS
- -----------------------------------------------------------------------------------------------------------------
Transmission and distribution:
Utility plant, at original cost, subject to
cost-based rate regulation $11,771,678 $11,213,352
Accumulated provision for depreciation (6,062,562) (5,573,742)
Construction work in progress 455,233 492,614
- -----------------------------------------------------------------------------------------------------------------
6,164,349 6,132,224
- -----------------------------------------------------------------------------------------------------------------
Generation:
Utility plant, at original cost, not subject to
cost-based rate regulation 1,689,469 9,522,127
Accumulated provision for depreciation, decommissioning
and amortization (833,917) (4,970,137)
Construction work in progress 61,431 100,283
Nuclear fuel, at amortized cost 172,250 154,757
- -----------------------------------------------------------------------------------------------------------------
1,089,233 4,807,030
- -----------------------------------------------------------------------------------------------------------------
Total utility plant 7,253,582 10,939,254
- -----------------------------------------------------------------------------------------------------------------
Nonutility property -- less accumulated provision
for depreciation of $25,682 and $24,730
at respective dates 56,681 67,869
Nuclear decommissioning trusts 2,239,929 1,831,460
Other investments 179,480 171,399
- -----------------------------------------------------------------------------------------------------------------
Total other property and investments 2,476,090 2,070,728
- -----------------------------------------------------------------------------------------------------------------
Cash and equivalents 81,500 962,272
Receivables, including unbilled revenue, less allowances
of $22,230 and $26,453 for uncollectible accounts
at respective dates 1,112,630 906,388
Fuel inventory 51,299 58,059
Materials and supplies, at average cost 116,259 132,980
Accumulated deferred income taxes-- net 274,833 123,146
Regulatory balancing accounts-- net 648,781 193,311
Prepayments and other current assets 91,992 93,098
- -----------------------------------------------------------------------------------------------------------------
Total current assets 2,377,294 2,469,254
- -----------------------------------------------------------------------------------------------------------------
Regulatory asset-- unamortized nuclear investment-- net 2,161,998 --
Regulatory asset-- income tax-related deferred charges 1,463,256 1,543,380
Unamortized debt issuance and reacquisition expense 348,816 359,304
Other deferred charges 865,892 677,378
- -----------------------------------------------------------------------------------------------------------------
Total deferred charges 4,839,962 2,580,062
- -----------------------------------------------------------------------------------------------------------------
Total assets $16,946,928 $18,059,298
- -----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
14
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Southern California Edison Company
In thousands, except share amounts December 31, 1998 1997
- -----------------------------------------------------------------------------------------------------------------
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 334,031 334,031
Accumulated other comprehensive income 39,462 48,023
Retained earnings 793,625 1,407,834
- -----------------------------------------------------------------------------------------------------------------
3,335,172 3,957,942
Preferred stock:
Not subject to mandatory redemption 128,755 183,755
Subject to mandatory redemption 255,700 275,000
Long-term debt 5,446,638 6,144,597
- -----------------------------------------------------------------------------------------------------------------
Total capitalization 9,166,265 10,561,294
- -----------------------------------------------------------------------------------------------------------------
Other long-term liabilities 467,109 479,637
- -----------------------------------------------------------------------------------------------------------------
Current portion of long-term debt 400,810 692,875
Short-term debt 469,565 322,028
Accounts payable 447,484 406,704
Accrued taxes 678,955 509,270
Accrued interest 89,828 85,406
Dividends payable 91,742 95,146
Deferred unbilled revenue and other current liabilities 1,096,332 931,856
- -----------------------------------------------------------------------------------------------------------------
Total current liabilities 3,274,716 3,043,285
- -----------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 2,993,142 2,939,471
Accumulated deferred investment tax credits 250,116 326,728
Customer advances and other deferred credits 795,266 708,745
- -----------------------------------------------------------------------------------------------------------------
Total deferred credits 4,038,524 3,974,944
- -----------------------------------------------------------------------------------------------------------------
Minority interest 314 138
- -----------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $ 16,946,928 $ 18,059,298
- -----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
15
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Consolidated Statements of Cash Flows Southern California Edison Company
In thousands Year ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net income $ 515,122 $ 605,594 $ 655,395
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 1,545,735 1,239,878 1,063,505
Other amortization 163,063 81,363 90,931
Deferred income taxes and investment tax credits (94,504) 63,379 46,122
Regulatory asset related to the sale of
oil and gas plant (220,232) -- --
Net gains on sale of oil and gas plant (564,623) -- --
Other-- net (78,668) (105,986) 5,710
Changes in working capital:
Receivables (206,242) 14,695 (9,120)
Regulatory balancing accounts (455,470) (374,799) (156,379)
Fuel inventory, materials and supplies 23,481 35,707 38,791
Prepayments and other current assets 1,106 12,039 9,152
Accrued interest and taxes 174,107 16,625 (58,827)
Accounts payable and other current liabilities 205,256 120,464 93,362
- -----------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,008,131 1,708,959 1,778,642
- -----------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued -- -- 396,309
Long-term debt repaid (776,030) (916,145) (403,957)
Rate reduction notes issued -- 2,449,289 --
Rate reduction notes repaid (251,591) -- --
Preferred stock redeemed (74,300) (100,000) --
Nuclear fuel financing-- net 16,244 (20,140) 41,803
Short-term debt financing-- net 147,537 91,879 (129,359)
Capital transferred -- 153,000 --
Dividends paid (1,129,812) (1,871,944) (799,593)
- -----------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (2,067,952) (214,061) (894,797)
- -----------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (860,837) (685,320) (616,427)
Proceeds from sale of oil and gas plant 1,203,039 -- --
Funding of nuclear decommissioning trusts (162,925) (153,756) (148,158)
Unrealized gain (loss) in equity investments-- net (8,561) 14,641 14,900
Other-- net 8,333 (28,133) (75,985)
- -----------------------------------------------------------------------------------------------------------------
Net cash provided (used) by investing activities 179,049 (852,568) (825,670)
- -----------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (880,772) 642,330 58,175
Cash and equivalents, beginning of year 962,272 319,942 261,767
- -----------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of year $ 81,500 $ 962,272 $ 319,942
- -----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
16
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Notes to Consolidated Financial Statements Southern California Edison Company
Note 1. Summary of Significant Accounting Policies
Accounting Principles
Southern California Edison Company's (SCE) accounting policies conform with
generally accepted accounting principles, including the accounting principles
for rate-regulated enterprises which reflect the rate-making policies of the
California Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring legislation enacted by
the State of California and a related change in the application of accounting
principles for rate-regulated enterprises adopted by the Financial Accounting
Standards Board's Emerging Issues Task Force, during the third quarter of 1997,
SCE began accounting for its investment in generation facilities in accordance
with accounting principles applicable to enterprises in general and SCE's
balance sheets display a separate caption for its investment in generation.
Application of such accounting principles to SCE's generation assets did not
result in any adjustment of their carrying value; however, SCE's nuclear
investments were reclassified as a regulatory asset in second quarter 1998.
Competition Transition Charge (CTC)
Beginning January 1, 1998, a non-bypassable charge is being billed to all
customers, which provides SCE the opportunity to recover its costs to transition
to a competitive market.
Consolidation Policy
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated.
Estimates
Financial statements prepared in compliance with generally accepted accounting
principles 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 electric utility restructuring, decommissioning and contingencies are
further discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements,
respectively.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and
natural gas, and under the first-in, first-out method for coal.
Nature of Operations
SCE is a rate-regulated public utility, which produces and 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. This regulatory environment is changing,
as further discussed in Note 2 to the Consolidated Financial Statements. As a
result of these changes, effective April 1, 1998, SCE sells all electric energy
produced to the power exchange (PX), as mandated by state legislation and
purchases electric energy from the PX to supply to its customers. SCE's
outstanding common stock is owned entirely by its parent company, Edison
International.
Nuclear
CPUC-authorized rate phase-in plans, which deferred collection of revenue for
each unit at the Palo Verde Nuclear Generating Station during the first four
years of operation, ended in February 1996, September 1996 and January 1998 for
Units 1, 2 and 3, respectively.
17
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Notes to Consolidated Financial Statements
Under federal law, SCE is liable for its share of the estimated costs to
decommission three federal nuclear enrichment facilities (based on purchases).
These costs, which will be paid over 15 years, are recorded as a fuel cost and
recovered through non-bypassable customer rates.
In 1996 and 1997, the CPUC authorized acceleration of the recovery of SCE's
remaining investment of $2.6 billion in San Onofre Nuclear Generation Station
Units 2 and 3 and $1.2 billion in Palo Verde Units 1, 2 and 3, respectively. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. 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 2001.
Beginning January 1, 1998, San Onofre's incentive pricing plan and accelerated
plant recovery and the Palo Verde balancing account became part of the CTC
mechanism. SCE will be required to share equally with ratepayers the net
benefits received from operation of Palo Verde, beginning in 2002, and from the
operation of the San Onofre units in 2004. Palo Verde's existing nuclear unit
incentive procedure will continue only for purposes of calculating a reward for
performance of any unit above an 80% capacity factor for a fuel cycle.
Reclassifications
Certain prior-year amounts were reclassified to conform to the December 31,
1998, financial statement presentation.
Regulatory Balancing Accounts
Prior to January 1, 1998, the differences between CPUC-authorized and actual
base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy
costs were accumulated in balancing accounts until they were refunded to, or
recovered from, customers through authorized rate adjustments (with interest).
On January 1, 1998, the balances in these balancing accounts were transferred to
a transition cost balancing account. Also, beginning January 1, 1998, the
difference between generation-related revenue and generation-related costs is
being accumulated in the transition cost balancing account, effectively
eliminating all other balancing accounts except those used to assist in the
administration of public purpose funds. Additionally, gains resulting from the
divestiture of the gas- and oil-fueled generation plants were credited to the
transition cost balancing account; the losses are being amortized over the
remaining transition period and accumulated in the transition cost balancing
account. These transition costs are being recovered from utility customers (with
interest) through the CTC. For further details, see discussion under California
Electric Utility Industry Restructuring in Note 2 to the Consolidated Financial
Statements. Income tax effects on all balancing account changes are deferred.
In January 1997, in compliance with the restructuring legislation,
overcollections in the kilowatt-hour sales and energy cost balancing accounts at
December 31, 1996, were transferred to an interim balancing account and were
subsequently credited to the transition cost balancing account in January 1998.
Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant construction. If
construction does not occur, these costs are charged to expense. RD&D expenses
were $2 million in 1998, $39 million in 1997 and $21 million in 1996.
18
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Southern California Edison Company
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end
of each year. Beginning April 1, 1998, operating revenue also includes amounts
for sales to the PX.
Supplemental Cash Flows Information
SCE's supplemental cash flows information was:
In millions Year ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Payments for interest and taxes:
Interest-- net of amounts capitalized $ 264 $ 342 $ 347
Taxes 405 438 546
- --------------------------------------------------------------------------------------------------------------------
Utility Plant
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. 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.
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 4.2% for 1998, 5.2%
for 1997 and 4.2% for 1996.
During the third quarter of 1997, SCE discontinued accounting for its investment
in generation facilities using accounting principles applicable to
rate-regulated enterprises and began accounting for such investment using
accounting principles applicable to enterprises in general. The carrying value
of such investment was unaffected by this change. However, the nuclear
investments were reclassified as a regulatory asset in second quarter 1998.
Note 2. Regulatory Matters
California Electric Utility Industry Restructuring
Restructuring Decision and Statute -- The CPUC's December 1995 decision on
restructuring California's electric utility industry started the transition to a
new market structure involving competition and customer choice. The State of
California enacted legislation in 1996 to provide a transition to a competitive
market structure. The Statute substantially adopted the CPUC's restructuring
decision by addressing stranded-cost recovery for utilities and providing a
certain cost-recovery time period for the transition costs associated with
utility-owned generation-related assets. Transition costs related to
power-purchase contracts are being recovered through the terms of their
contracts while most of the remaining transition costs will be recovered through
2001. The Statute also 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. The Statute included a rate freeze for all
other customers, including large commercial and industrial customers, as well as
provisions for continued funding for energy conservation, low-income programs
and renewable resources. Despite the rate freeze, SCE expects to be able to
recover its revenue requirement during the 1998-2001 transition period. In
addition, the Statute mandated the implementation of the CTC that provides
utilities the opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the Statute contained provisions for the recovery
(through 2006) of
19
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Notes to Consolidated Financial Statements
reasonable employee-related transition costs, incurred and projected, for
retraining, severance, early retirement, outplacement and related expenses. The
new market structure and customer choice began on April 1, 1998.
1998 Activities -- During 1998, SCE implemented changes to comply with
restructuring elements required by the CPUC and the Statute. Beginning January
1, 1998:
o SCE's rates were unbundled into separate charges for energy, transmission,
distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component is being collected through FERC-approved rates,
subject to refund.
o SCE's costs associated with its hydroelectric plants are being recovered
through a performance-based mechanism. The mechanism sets the hydroelectric
revenue requirement and establishes a formula for extending it through the
duration of the electric industry restructuring transition period, or until
market valuation of the hydroelectric facilities, whichever occurs first.
The mechanism provides that power sales revenue from hydroelectric
facilities in excess of the hydroelectric revenue requirement be credited
against the costs to transition to a competitive market.
o SCE's transition costs are being recovered through a non-bypassable CTC.
This charge applies to all customers who were using or began using utility
services on or after the CPUC's December 1995 restructuring decision date.
SCE has estimated its transition costs to be approximately $10.6 billion
(1998 net present value) from 1998 through 2030. This estimate was based on
incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect these
estimates. The potential transition costs are comprised of $6.4 billion
from SCE's qualifying facilities contracts, which are the direct result of
prior legislative and regulatory mandates, and $4.2 billion (which reflects
the sale of SCE's gas- and oil- fueled generation plants) from costs
pertaining to certain generating assets and regulatory commitments
consisting of costs incurred (whose recovery has been deferred by the CPUC)
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 San Onofre Units 2 and 3
and the Palo Verde units, and certain other costs.
o Residential and small commercial customers who began receiving a 10% rate
reduction are repaying the rate reduction notes issued in December 1997
(see further discussion in Note 3 to the Consolidated Financial Statements)
through non-bypassable charges based on electricity consumption.
Effective April 1, 1998:
o The ISO assumed operational control of the transmission system after the
ISO and PX had begun accepting bids and schedules for electricity purchases
on March 31, 1998. The restructuring implementation costs related to the
start-up and development of the PX, which are paid by the utilities, will
be recovered from all retail customers over the four-year transition
period. SCE's share of the charge is $45 million, plus interest and fees.
SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a 10-year period.
o Customers can choose to remain utility customers with either bundled
electric service or an hourly PX pricing option from SCE (which is
purchasing its power through the PX), or choose direct access, which means
the customer can contract directly with either independent power producers
or energy service providers (ESPs) such as power brokers, marketers and
aggregators. Electric utilities are continuing to provide the core
distribution service of delivering energy through their distribution system
regardless of a customer's choice of electricity supplier. The CPUC is
continuing to regulate the prices and service obligations related to
distribution services.
20
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Southern California Edison Company
o Customers have options regarding metering, billing and related services
(referred to as revenue cycle services) that have been provided by
California's investor-owned utilities. ESPs can provide their customers
with one consolidated bill for their services and the utility's services,
request the utility to provide such a consolidated bill to the customer or
elect to have both the ESP and the utility bill the customer for their
respective charges. Customers with maximum demand above 20kW (primarily
industrial and medium and large commercial) can choose SCE or any other
supplier to provide their metering service. Beginning in January 1999, all
customers can make these choices. In September 1998, the CPUC issued a
decision regarding the credits that would be provided to customers if they
elect to obtain revenue cycle services from someone other than SCE.
Although the decision adopted SCE's recommendation of using the net avoided
cost, it also adopted a methodology which results in higher credits to
customers but requires ESPs to pay service fees to SCE for the costs that
SCE incurs as a result of dealing with the ESP.
During 1998, SCE sold all of its gas- and oil-fueled generation plants. The
total sales price of the 12 plants was $1.2 billion, over $500 million more than
the combined book value. Net proceeds of the sales were used to reduce stranded
costs, which otherwise were expected to be collected through the CTC mechanism.
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described above, SCE would be allowed to recover
its transition costs through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be subject
to a lower authorized rate of return). In 1997, SCE discontinued application of
accounting principles for rate-regulated enterprises for its investment in
generation facilities based on new accounting guidance. The financial reporting
effect of this discontinuance was to segregate these assets on the balance
sheet; the new guidance did not require SCE to write off any of its
generation-related assets, including related regulatory assets. However, the new
guidance did not specifically address the application of asset impairment
standards to these assets. SCE has retained these assets on its balance sheet
because the Statute and restructuring plan referred to above make probable their
recovery through a non-bypassable CTC to distribution customers. The regulatory
assets relate primarily to the recovery of accelerated income tax benefits
previously flowed through to customers, purchased power contract termination
payments and unamortized losses on reacquired debt. The new accounting guidance
also permits the recording of new generation-related regulatory assets during
the transition period that are probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording 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 future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.4
billion, after tax, at December 31, 1998) as a one-time, non-cash charge against
earnings.
If events occur during the restructuring process that result in all or a portion
of the transition costs being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other revisions will
ultimately be made during the restructuring process in subsequent proceedings or
the effect, after the transition period, that competition will have on its
results of operations or financial position.
21
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Notes to Consolidated Financial Statements
Note 3. Financial Instruments
Cash Equivalents
Cash and equivalents include tax-exempt investments ($78 million at December 31,
1998, and $936 million at December 31, 1997), and time deposits and other
investments ($4 million at December 31, 1998, and $26 million at December 31,
1997) with maturities of three months or less.
Derivative Financial Instruments
SCE's risk management policy allows the use of derivative financial instruments
to manage financial exposure on its investments and fluctuations in interest
rates, but prohibits the use of these instruments for speculative or trading
purposes.
SCE uses the hedge accounting method to record its derivative financial
instruments, except for gas call options. 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.
SCE has gas call options that mitigate its exposure to increases in natural gas
prices. Increases in natural gas prices tend to increase the price of
electricity purchased from the PX. The options cover various periods from 1998
through 2001.
SCE uses the mark-to-market accounting method for its gas call options. Gains
and losses from monthly changes in market prices are recorded as income or
expense. However, the costs of the options and the market price changes are
included in the transition cost balancing account. As a result, the
mark-to-market gains or losses have no effect on earnings.
Interest rate swaps are used to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At the balance sheet dates of
December 31, 1998, and December 31, 1997, SCE had an interest rate swap
agreement which fixed the interest rate at 5.585% for $196 million of debt due
2008; it expires February 28, 2008. The interest rate swap agreement requires
the parties to pledge collateral according to bond rating and market interest
rate changes. At December 31, 1998, SCE had pledged $25 million as collateral
due to a decline in market interest rates. SCE is exposed to credit loss in the
event of nonperformance by the counterparty to the agreement, but does not
expect the counterparty to fail to meet its obligation.
Fair Value of Financial Instruments
Fair values of financial instruments were:
In millions December 31, 1998 1997
- ------------------------------------------------------------------------------------------------------------------
Cost Fair Cost Fair
Basis Value Basis Value
- ------------------------------------------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $1,534 $2,240 $1,371 $1,831
Equity investments 7 72 9 90
Gas call options 39 31 34 34
Financial liabilities:
DOE decommissioning and
decontamination fees 45 40 50 43
Interest rate hedges -- 28 -- 24
Long-term debt 5,447 5,699 6,145 6,456
Preferred stock subject to
mandatory redemption 256 274 275 293
- -----------------------------------------------------------------------------------------------------------------
22
- --------------------------------------------------------------------------------
Southern California Edison Company
Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts and equity investments and on financial models for
gas call options. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs 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 approximate fair value.
Gross unrealized holding gains (losses) on financial assets were:
In millions December 31, 1998 1997
- --------------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $196 $131
Stocks 365 190
U.S. government issues 115 91
Short-term and other 30 48
- --------------------------------------------------------------------------------
706 460
Equity investments 65 81
- --------------------------------------------------------------------------------
Gas call options (8) --
Total $763 $541
- --------------------------------------------------------------------------------
There were no unrealized holding losses on financial assets for the years
presented, other than the unrealized holding loss on the gas call options in
1998.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to 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 reflected in 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 anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
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.
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
arranged with securities dealers to remarket or purchase them if necessary.
23
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
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.
Long-term debt maturities and sinking-fund requirements for the five years are:
1999-- $401 million; 2000-- $571 million; 2001-- $646 million; 2002-- $446
million; and 2003-- $371 million.
In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE
is the sole member, issued approximately $2.5 billion of rate reduction notes to
Bankers Trust Company of California, as certificate trustee for the California
Infrastructure and Economic Development Bank Special Purpose Trust SCE-1
(Trust), which is a special purpose entity established by the State of
California. The terms of the rate reduction notes generally mirror the terms of
the pass-through certificates issued by the Trust, which are known as rate
reduction certificates. The proceeds of the rate reduction notes were used by
the SPE to purchase from SCE an enforceable right known as transition property.
Transition property is a current property right created pursuant to the
restructuring legislation and a financing order of the CPUC and consists
generally of the right to be paid a specified amount from a non-bypassable
tariff levied on residential and small commercial customers. Notwithstanding the
legal sale of the transition property by SCE to the SPE, the amounts reflected
as assets on SCE's balance sheet have not been reduced by the amount of the
transition property sold to the SPE, and the liabilities of the SPE for the rate
reduction notes are for accounting purposes reflected as long-term liabilities
on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of
the transition property to retire debt and equity securities. The rate reduction
notes are secured solely by the transition property and certain other assets of
the SPE, and there is no recourse to SCE or Edison International.
Although the SPE is consolidated with SCE in the financial statements, as
required by generally accepted accounting principles, the SPE is legally
separate from SCE, the assets of the SPE are not available to creditors of SCE
or Edison International, and the transition property is legally not an asset of
SCE or Edison International.
Long-term debt consisted of:
In millions December 31, 1998 1997
- --------------------------------------------------------------------------------
First and refunding mortgage bonds:
1999 - 2026 (5.625% to 7.5%) $1,550 $1,825
Rate reduction notes:
1999 - 2007 (6.14% to 6.42%) 2,217 2,463
Pollution-control bonds:
1999 - 2027 (5.4% to 7.2% and variable) 1,201 1,202
Funds held by trustees (2) (2)
Debentures and notes:
1999 - 2006 (5.6% to 8.25%) 700 1,195
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 108 92
Long-term debt due within one year (401) (693)
Unamortized debt discount-- net (26) (37)
- --------------------------------------------------------------------------------
Total $5,447 $6,145
- --------------------------------------------------------------------------------
24
- --------------------------------------------------------------------------------
Southern California Edison Company
Short-Term Debt
SCE has lines of credit it can use at negotiated or bank index rates. At
December 31, 1998, these lines totaled $1.3 billion, with $800 million available
for short-term debt and $500 million available for the long-term refinancing of
certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel inventories
and general cash requirements. Commercial paper outstanding at December 31,
1998, and December 31, 1997, was $581 million and $415 million, respectively.
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. Weighted-average interest rates were 5.3% and 6.0% at December
31, 1998, and December 31, 1997, respectively.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. At December 31, 1998, SCE had the capacity to pay $794
million in additional dividends and continue to maintain its authorized capital
structure.
In 1998, SCE implemented a recently issued accounting standard that requires
companies to report comprehensive income. Implementation of the new standard had
no effect on SCE's results of operations or financial position.
Changes in SCE's common shareholder's equity were as follows:
Accumulated Total
Additional Other Common
Common Paid-in Comprehensive Retained Shareholder's
In millions Stock Capital Income Earnings Equity
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1995 $ 2,168 $ 178 $ 18 $ 2,780 $5,144
Net income 655 655
Unrealized gain on securities 25 25
Tax effect (10) (10)
Dividends declared on common stock (735) (735)
Dividends declared on preferred stock (34) (34)
- -----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 2,168 178 33 2,666 5,045
- -----------------------------------------------------------------------------------------------------------------
Net income 606 606
Unrealized gain on securities 24 24
Tax effect (9) (9)
Dividends declared on common stock (1,829) (1,829)
Dividends declared on preferred stock (30) (30)
Reacquired capital stock expense (5) (5)
Additional investment from
parent company 156 156
- ----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 2,168 334 48 1,408 3,958
- ----------------------------------------------------------------------------------------------------------------
Net income 515 515
Unrealized gain on securities 14 14
Tax effect (5) (5)
Reclassified adjustment for gain
Included in net income (30) (30)
Tax efffect 12 12
Dividends declared on common stock (1,101) (1,101)
Dividends declared on preferred stock (24) (24)
Stock option appreciation (4) (4)
- -----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ 2,168 $ 334 $ 39 $ 794 $3,335
- -----------------------------------------------------------------------------------------------------------------
25
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Authorized common stock is 560 million shares with no par value. Authorized
shares of preferred and preference stock 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: 1999
through 2001-- zero; 2002--$105 million; and 2003-- $9 million.
Cumulative preferred stock consisted of:
Dollars in millions, except per share amounts December 31, 1998 1997
- -------------------------------------------------------------------------------------------------------------------
December 31, 1998
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
5.80 -- -- -- 55
- -------------------------------------------------------------------------------------------------------------------
Total $129 $184
- -------------------------------------------------------------------------------------------------------------------
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 81 100
- -------------------------------------------------------------------------------------------------------------------
Total $256 $275
- -------------------------------------------------------------------------------------------------------------------
In 1998, 193,000 shares of Series 7.23% and 2.2 million shares of Series 5.8%
preferred stock were redeemed. In 1997, 4 million shares of Series 7.36%
preferred stock were redeemed. There were no preferred stock issuances for the
years presented.
Note 5. Income Taxes
SCE and its subsidiaries will be included in Edison International's consolidated
federal income tax and combined state franchise tax returns. Under income tax
allocation agreements, each subsidiary calculates its own tax liability.
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.
26
- --------------------------------------------------------------------------------
Southern California Edison Company
The components of the net accumulated deferred income tax liability were:
In millions December 31, 1998 1997
- --------------------------------------------------------------------------------
Deferred tax assets:
Property-related $ 197 $ 227
Unrealized gains or losses 387 273
Investment tax credits 152 192
Regulatory balancing accounts 96 180
Decommissioning-related 126 114
Fixed costs 188 109
Other 285 226
- --------------------------------------------------------------------------------
Total $1,431 $1,321
- --------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $3,005 $3,272
Capitalized software costs 196 127
Regulatory balancing accounts 162 202
Other 786 536
- --------------------------------------------------------------------------------
Total $4,149 $4,137
- --------------------------------------------------------------------------------
Accumulated deferred income taxes-- net $2,718 $2,816
- --------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $2,993 $2,939
Included in current assets 275 123
The current and deferred components of income tax expense were:
In millions Year ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------
Current:
Federal $450 $375 $386
State 101 100 129
- ----------------------------------------------------------------------------------------------------------
551 475 515
- ----------------------------------------------------------------------------------------------------------
Deferred--federal and state:
Accrued charges (43) (33) (14)
Property related (106) (47) (14)
Investment and energy tax credits-- net (74) (20) (24)
Pension reserve (3) (5) 45
Rate phase-in plan -- (19) (32)
Regulatory balancing accounts 177 141 34
Unbilled revenue (67) 6 --
Other 7 22 1
- ----------------------------------------------------------------------------------------------------------
(109) 45 (4)
- ----------------------------------------------------------------------------------------------------------
Total income tax expense $442 $520 $511
- ----------------------------------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income $446 $582 $578
Included in other income (4) (62) (67)
The composite federal and state statutory income tax rate was 40.551% for 1998
and 1997, and 41.045% for 1996.
27
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
The federal statutory income tax rate is reconciled to the effective tax rate
below:
Year ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software (0.7) (0.9) (0.8)
Property related and other 11.4 6.9 4.5
Investment and energy tax credits (6.8) (1.8) (2.0)
State tax-- net of federal deduction 6.9 7.0 7.1
- ----------------------------------------------------------------------------------------------------------------
Effective tax rate 45.8% 46.2% 43.8%
- ----------------------------------------------------------------------------------------------------------------
Note 6. Employee Compensation and Benefit Plans
Stock Option Plans
In April 1998, Edison International shareholders approved the Edison
International Equity Compensation Plan. The plan replaces the Long-Term
Incentive Compensation Program, consisting of officer, director, and management
plans, which was adopted by Edison International shareholders in 1992. No new
awards will be made under the prior program; however, it will remain in effect
as long as any awards remain outstanding under the prior program.
The prior program participated in the use of 8.2 million shares of parent
company common stock reserved for potential issuance under various stock
compensation programs to directors, officers and senior managers of Edison
International and its affiliates. Under these programs, options on 3.0 million
shares of Edison International common stock are currently outstanding to
officers and senior managers of SCE.
The new plan authorizes the annual issuance of shares equal to one percent of
the issued and outstanding shares of Edison International common stock as of
December 31 of the prior year. This authorization is cumulative so that to the
extent shares are not needed to meet new plan requirements in any year, the
excess authorized shares will carry over to subsequent years until plan
termination. One percent of the issued and outstanding Edison International
common stock on December 31, 1997, was 3.8 million shares. Under the new plan,
options on 1.4 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. Edison International stock options
include a dividend equivalent feature. Generally, for options issued before
1994, amounts equal to dividends accrue on the options at the same time and at
the same rate as would be payable on the number of shares of Edison
International common stock covered by the options. The amounts accumulate
without interest. For Edison International stock options issued after 1993,
dividend equivalents are subject to reduction unless certain shareholder return
performance criteria are met.
The new plan's stock options have a 10-year term with one-fourth of the total
award vesting after each of the first four years of the award term. The prior
program's stock options have a 10-year term with one-third of the total award
vesting after each of the first three years of the award term. If an optionee
retires, dies or is permanently and totally disabled during the vesting period,
the unvested options will vest and be exercisable to the extent of 1/36 (prior
program) or 1/48 (the new plan) of the grant for each full month of service
during the vesting period.
Unvested options of any person who has served in the past on the Edison
International or SCE Management Committee (which was dissolved in 1993) will
vest and be exercisable upon the member's retirement, death or permanent and
total disability. Upon retirement, death or permanent and total disability, the
vested options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by retirement,
death or permanent and total disability, 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.
28
- --------------------------------------------------------------------------------
Southern California Edison Company
SCE measures compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the
stock-compensation program was $8 million, $5 million and $8 million for the
years 1998, 1997 and 1996, respectively.
Stock-based compensation expense under the fair-value method of accounting would
have resulted in pro forma earnings of $516 million, $602 million and $653
million for the years 1998, 1997 and 1996, respectively.
The weighted-average fair value of options granted during 1998 and 1997 was
$6.44 per share option and $7.62 per share option, respectively. The
weighted-average remaining life of options outstanding as of December 31, 1998,
and December 31, 1997, was 7 years.
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:
1998 1997
- --------------------------------------------------------------------------------
Expected life 7 years 7 years
Risk-free interest rate 4.7% - 5.6% 6.3% - 6.8%
Expected volatility 17% 17%
- --------------------------------------------------------------------------------
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.
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 1996, SCE recorded
pension gains from a special voluntary early retirement program. In 1998, SCE
adopted a new accounting standard that revises the disclosure requirements for
pension plans. Prior periods have been restated.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $2,094 $2,002
Service cost 59 44
Interest cost 141 138
Actuarial loss 90 192
Benefits paid (133) (282)
- ---------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $2,251 $2,094
- ---------------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $2,298 $2,158
Actual return on plan assets 334 369
Employer contributions 53 53
Benefits paid (133) (282)
- ---------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $2,552 $2,298
- ---------------------------------------------------------------------------------------------------------------
Funded status $ 301 $ 204
Unrecognized net gain (372) (304)
Unrecognized net obligation (17-year amortization) 33 38
Unrecognized prior service cost 168 184
- ---------------------------------------------------------------------------------------------------------------
Pension asset (liability) $ 130 $ 122
- ---------------------------------------------------------------------------------------------------------------
Discount rate 6.75% 7.0%
Rate of compensation increase 5.0% 5.0%
Expected return on plan assets 7.5% 8.0%
29
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
The components of pension expense were:
In millions Year ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------
Service cost $ 59 $ 44 $ 49
Interest cost 141 138 178
Expected return on plan assets (170) (160) (203)
Net amortization and deferral 14 13 5
- ----------------------------------------------------------------------------------------------------------------
Pension expense under
accounting standards 44 35 29
Regulatory adjustment-- deferred 11 17 22
- ----------------------------------------------------------------------------------------------------------------
Net pension expense recognized 55 52 51
Settlement gain -- -- (121)
- ----------------------------------------------------------------------------------------------------------------
Total expense (gain) $ 55 $ 52 $ (70)
- ----------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service (or
those eligible under a 1996 special voluntary early retirement program), are
eligible for postretirement health and dental care, life insurance and other
benefits. In 1996, SCE recorded special termination expenses from a special
voluntary early retirement program. In 1998, SCE adopted a new accounting
standard that revises the disclosure requirements for postretirement benefit
plans. Prior periods have been restated.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 1998 1997
- --------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $1,533 $1,349
Service cost 41 30
Interest cost 99 99
Actuarial loss (gain) (74) 114
Benefits paid (54) (59)
- --------------------------------------------------------------------------------------------------
Benefit obligation at end of year $1,545 $1,533
- --------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 815 $ 617
Actual return on plan assets 147 147
Employer contributions 121 110
Benefits paid (54) (59)
- --------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $1,029 $ 815
- --------------------------------------------------------------------------------------------------
Funded status $ (516) $ (718)
Unrecognized net loss 84 244
Unrecognized transition obligation (20-year
amortization) 376 403
- --------------------------------------------------------------------------------------------------
Recorded asset (liability) $ (56) $ (71)
- --------------------------------------------------------------------------------------------------
Discount rate 6.75% 7.0%
Expected return on plan assets 7.5% 8.0%
30
- --------------------------------------------------------------------------------
Southern California Edison Company
The components of postretirement benefits other than pension expense were:
In millions Year ended December 31, 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------------
Service cost $ 41 $ 30 $ 31
Interest cost 99 99 90
Expected return on plan assets (62) (50) (43)
Amortization of loss 1 4 6
Amortization of transition obligation 27 27 27
- ------------------------------------------------------------------------------------------------------------------
Net expense 106 110 111
Special termination expense -- -- 72
- ------------------------------------------------------------------------------------------------------------------
Total expense $ 106 $ 110 $ 183
- ------------------------------------------------------------------------------------------------------------------
The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1999, gradually decreasing to 5.0% for 2009 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 1998, by $264 million and
annual aggregate service and interest costs by $31 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of December 31, 1998, by $211 million and annual
aggregate service and interest costs by $24 million.
Employee Savings Plan
SCE has a 401(k) defined contribution savings plan designed to supplement
employees' retirement income. The plan received employer contributions of $17
million in 1998, $15 million in 1997 and $24 in 1996.
Note 7. 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 included in the consolidated balance sheet as
of December 31, 1998, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 31 $ 6 $ 2 60%
Pacific Intertie 239 78 5 50
Generating stations:
Four Corners Units 4 and 5 (coal) 459 288 2 48
Mohave (coal) 315 183 6 56
Palo Verde (nuclear)(1) 1,605 908 12 16
San Onofre (nuclear)(1) 4,217 2,762 63 75
- -------------------------------------------------------------------------------------------------------------------
Total $ 6,866 $ 4,225 $90
- -------------------------------------------------------------------------------------------------------------------
(1) Reported as "Regulatory asset -- unamortized nuclear investment -- net."
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.
31
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Estimated remaining commitments for noncancellable leases at December 31, 1998,
were:
Year ended December 31, In millions
- --------------------------------------------------------------------------------
1999 $ 13
2000 11
2001 8
2002 5
2003 3
Thereafter 5
- --------------------------------------------------------------------------------
Total $45
- --------------------------------------------------------------------------------
Note 9. Commitments
Nuclear Decommissioning
Decommissioning is estimated to cost $1.9 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 plans to decommission its nuclear
generating facilities by a prompt removal method authorized by the Nuclear
Regulatory Commission. Decommissioning is scheduled to begin in 2013 for San
Onofre Units 2 and 3, and 2025 at Palo Verde. In December 1998, SCE requested
the CPUC's approval to access its nuclear decommissioning trust funds to
commence decommissioning of San Onofre Unit 1 in 2000.
Decommissioning costs, which are accrued and recovered through non-bypassable
customer rates over the term of each nuclear facility's operating license, are
recorded as a component of depreciation expense.
Decommissioning expense was $164 million in 1998, $154 million in 1997 and $148
million in 1996. The accumulated provision for decommissioning, excluding San
Onofre Unit 1, was $1.2 billion at December 31, 1998, and $1.1 billion at
December 31, 1997. The estimated costs to decommission San Onofre Unit 1 ($368
million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Trust investments include:
Maturity December 31,
In millions Dates 1998 1997
- -------------------------------------------------------------------------------------------------------------------
Municipal bonds 2000--2029 $ 547 $ 459
Stocks -- 550 392
U.S. government issues 1999--2029 355 357
Short-term and other 1999--2028 82 163
- -------------------------------------------------------------------------------------------------------------------
Trust fund balance (at cost) $ 1,534 $1,371
- -------------------------------------------------------------------------------------------------------------------
Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $63
million in 1998, $54 million in 1997 and $49 million in 1996. Proceeds from
sales of securities (which are reinvested) were $1.2 billion in 1998, $595
million in 1997 and $1.0 billion in 1996. Approximately 89% of the trust fund
contributions were tax-deductible.
32
- --------------------------------------------------------------------------------
Southern California Edison Company
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase.
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.
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. The
purchased-power contract is not expected to provide more than 5% of current or
estimated future operating capacity. SCE's minimum commitment under both
contracts is approximately $172 million through 2017.
Certain commitments for the years 1999 through 2003 are estimated below:
In millions 1999 2000 2001 2002 2003
- -------------------------------------------------------------------------------------------------------------------
Projected construction expenditures $922 $831 $726 $699 $689
Fuel supply contracts 167 136 123 139 117
Purchased-power capacity payments 744 786 797 704 689
Unconditional purchase obligations 9 10 10 9 10
- -------------------------------------------------------------------------------------------------------------------
Note 10. 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.
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 49 identified sites
is $171 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 $247 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE
33
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Notes to Consolidated Financial Statements
among a range of reasonably possible outcomes. SCE has sold all of its gas- and
oil-fueled generation plants and has retained some liability associated with the
divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $88 million of its recorded liability, through an incentive
mechanism (SCE may request 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 $141 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 costs in each of the next several years are expected to range from
$4 million to $10 million. Recorded costs for 1998 were $7 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 $9.6
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 primarily by mutual insurance companies
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 $22 million per year. Insurance premiums are charged to operating expense.
34
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Southern California Edison Company
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the
selection and development of repositories for, and the disposal of, spent
nuclear fuel and high-level radioactive waste. The Act requires that the DOE
provide for the disposal of spent nuclear fuel and high-level radioactive waste
from nuclear generation stations beginning January 31, 1998. However, the DOE
did not meet its obligations. It is not certain when the DOE will begin
accepting spent nuclear fuel from San Onofre or from other nuclear power plants.
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.
SCE 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. Meeting spent fuel storage requirements beyond that
period could require new and separate interim storage facilities, the costs for
which have not been determined. Extended delays by the DOE can lead to
consideration of costly alternatives involving siting and environmental issues.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2002
for Units 1 and 2, and until 2003 for Unit 3. Arizona Public Services, operating
agent for Palo Verde, has commenced construction of an interim fuel storage
facility and projects completion in 2002.
SCE and other owners of nuclear power plants may be able to recover interim
storage costs arising from DOE delays in the acceptance of utility spent nuclear
fuel by pursuing relief under the terms of the contracts, as directed by the
courts, through other court actions.
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Quarterly Financial Data
1998 1997
------------------------------------------ -----------------------------------------
In millions Total Fourth Third Second First Total Fourth Third Second First
- -------------------------------------------------------------------------------------------------------------------
Operating revenue(1) $8,847 $2,245 $3,057 $1,922 $1,623 $7,953 $1,980 $2,434 $1,844 $1,695
Operating income 918 241 237 212 228 1,060 248 349 229 234
Net income 515 121 169 120 105 606 123 233 129 121
Earnings available for
common stock 490 115 163 114 98 576 116 226 122 112
Common dividends declared 1,101 141 422 442 96 1,829 1,266 217 171 175
- --------------------------------------------------------------------------------------------------------------------
(1) Effective second quarter 1998, operating revenue includes sales to the PX.
35
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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 generally accepted accounting
principles applied on a consistent basis 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 generally accepted auditing
standards 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.
Richard K. Bushey John E. Bryson
----------------- --------------
Richard K. Bushey John E. Bryson
Vice President Chairman of the Board
and Controller and Chief Executive Officer
February 4, 1999
36
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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, 1998, and 1997, and the related consolidated statements of
income, comprehensive income and cash flows for each of the three years in the
period ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1998, and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
February 4, 1999
37
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Selected Financial and Operating Data:
1994-1998 Southern California Edison Company
Dollars in millions 1998 1997 1996 1995 1994
- ------------------------------------------------------------------------------------------------------------------
Income statement data:
Operating revenue(1) $ 8,847 $ 7,953 $ 7,583 $ 7,873 $ 7,799
Operating expenses(2) 7,929 6,893 6,450 6,724 6,705
Fuel and purchased power expenses(2) 4,934 3,735 3,336 3,197 3,403
Income tax from operations 446 582 578 560 508
Allowance for funds used during construction 20 17 25 34 29
Interest expense-- net 485 444 453 464 443
Net income 515 606 655 680 639
Earnings available for common stock 490 576 621 643 599
Ratio of earnings to fixed charges 2.95 3.49 3.54 3.52 3.43
- ------------------------------------------------------------------------------------------------------------------
Balance sheet data:
Assets $ 16,947 $ 18,059 $ 17,737 $ 18,155 $ 18,076
Gross utility plant 14,150 21,483 21,134 20,717 20,127
Accumulated provision for depreciation and
decommissioning 6,896 10,544 9,431 8,569 7,710
Common shareholder's equity 3,335 3,958 5,045 5,144 5,039
Preferred stock:
Not subject to mandatory redemption 129 184 284 284 359
Subject to mandatory redemption 256 275 275 275 275
Long-term debt 5,447 6,145 4,779 5,215 4,988
Capital structure:
Common shareholder's equity 36.4% 37.5% 48.6% 47.1% 47.3%
Preferred stock:
Not subject to mandatory redemption 1.4% 1.7% 2.7% 2.6% 3.3%
Subject to mandatory redemption 2.8% 2.6% 2.7% 2.5% 2.6%
Long-term debt 59.4% 58.2% 46.0% 47.8% 46.8%
- -----------------------------------------------------------------------------------------------------------------
Operating data:
Peak demand in megawatts (MW) 19,935 19,118 18,207 17,548 18,044
Generation capacity at peak (MW) 10,546 21,511 21,602 21,603 20,615
Kilowatt-hour sales (kWh) (in millions) 76,595 77,234 75,572 74,296 77,986
Total energy requirement (kWh) (in millions)(3) 80,289 86,849 84,236 81,924 85,011
Energy mix:
Thermal 38.8% 44.6% 47.6% 51.6% 59.5%
Hydro 7.4% 6.5% 6.9% 7.7% 3.9%
Purchased power and other sources 53.8% 48.9% 45.5% 40.7% 36.6%
Customers (in millions) 4.27 4.25 4.22 4.18 4.15
Full-time employees 13,177 12,642 12,057 14,886 16,351
- -----------------------------------------------------------------------------------------------------------------
(1) 1998 includes $1.3 billion from sales to the power exchange (PX).
(2) 1998 includes $2.0 billion for purchases from the PX.
(3) 1998 excludes direct access and resale customer requirements.
38
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Board of Directors Southern California Edison Company
- --------------------------------------------------------------------------------
John E. Bryson Charles D. Miller Thomas C. Sutton
Chairman of the Board and CEO, Chairman of the Board, Chairman of the Board and CEO,
Edison International and SCE Avery Dennison Corporation, Pacific Life Insurance Company,
Pasadena, California Newport Beach, California
Winston H. Chen Luis G. Nogales Daniel M. Tellep
Chairman of the Paramitas Foundation President, Retired Chairman of the Board,
and Chairman of Paramitas Nogales Partners, Lockheed Martin Corporation,
Investment Corporation, Los Angeles, California Bethesda, Maryland
Santa Clara, California
Warren Christopher Ronald L. Olson James D. Watkins*
Senior Partner, Senior Partner, Admiral USN, Retired,
O'Melveny & Myers, Munger, Tolles and Olson, President, Joint Oceanographic
Los Angeles, California Los Angeles, California Institutions, Inc., and
President, Consortium for
Stephen E. Frank James M. Rosser Oceanographic Research and Education,
President and Chief Operating President, Washington, D.C.
Officer, SCE California State University, Los Angeles
Los Angeles, California
Edward Zapanta, M.D.
Joan C. Hanley E. L. Shannon, Jr.* Physician and Neurosurgeon,
Former General Partner, Retired Chairman of the Board, Torrance, California
Miramonte Vineyards, Santa Fe International Corporation,
Rancho Palos Verdes, California Alhambra, California
Carl F. Huntsinger Robert H. Smith
General Partner, Managing Director,
DAE Limited Partnership Ltd., Smith and Crowley Incorporated,
Ojai, California Pasadena, California
* Retiring on April 15, 1999
- ----------------------------------------------------------------------------------------------------------------------
Management Team
- ----------------------------------------------------------------------------------------------------------------------
John E. Bryson Robert G. Foster R. W. Krieger
Chairman of the Board and CEO Senior Vice President, Vice President, Nuclear Generation
Public Affairs
Stephen E. Frank J. Michael Mendez
President and Chief Operating Officer Lillian R. Gorman Vice President, Labor Relations
Senior Vice President, Human
Resources
Bryant C. Danner Thomas M. Noonan***
Executive Vice President and Richard M. Rosenblum Vice President and Controller
General Counsel Senior Vice President,
T&D Business Unit Dwight E. Nunn
Alan J. Fohrer Vice President, Nuclear Engineering
Executive Vice President and Emiko Banfield and Technical Services
Chief Financial Officer Vice President, Shared Services
Frank J. Quevedo
Harold B. Ray Vice President, Equal Opportunity
Executive Vice President, Richard K. Bushey**
Generation Business Unit Vice President and Controller Anthony L. Smith***
Vice President, Tax
Pamela A. Bass Bruce C. Foster
Senior Vice President, Vice President, Mahvash Yazdi
Customer Service Business Unit San Francisco Regulatory Affairs Vice President and Chief
Information Officer
Theodore F. Craver, Jr. Lawrence D. Hamlin
Senior Vice President and Treasurer Vice President, Power Production Beverly P. Ryder
Corporate Secretary
John R. Fielder Thomas J. Higgins
Senior Vice President, Vice President,
Regulatory Policy and Affairs Corporate Communications
** Resigned March 1, 1999
*** Effective March 1, 1999
39
Shareholder Information
- --------------------------------------------------------------------------------
Annual Meeting of Shareholders
Thursday, April 15, 1999 10:00 a.m.
The Industry Hills Sheraton Resort and Conference Center
One Industry Hills Parkway
City of Industry, California
- --------------------------------------------------------------------------------
Stock Listing and Trading Information
SCE Preferred Stock
The American and Pacific stock exchanges use the ticker symbol SCE. Previous
day's closing prices, when traded, are listed in the daily newspapers in the
American Stock Exchange table under the symbol SoCalEd. 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
Southern California Edison Company maintains shareholder records and is transfer
agent and registrar for SCE preferred stock. Shareholders may call Shareholder
Services, (800) 347-8625, between 8:00 a.m. and 4:00 p.m. (Pacific time) every
business day, 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;
o dividend checks;
o requests to eliminate multiple annual report mailings; and
o request access to online account information via Edison
International's Internet Home Page, www.edisoninvestor.com
The address of Shareholder Services is:
P.O. Box 400, Rosemead, California 91770-0400
FAX: (626) 302-4815
Southern California Edison
2244 Walnut Grove Avenue
Rosemead, California 91770
(626) 302-1212