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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, 1993
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COMMISSION FILE NUMBER 1-9936
SCECORP
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
CALIFORNIA 95-4137452
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
2244 WALNUT GROVE AVENUE (818) 302-2222
ROSEMEAD, CALIFORNIA 91770 (REGISTRANT'S TELEPHONE
(ADDRESS OF PRINCIPAL (ZIP CODE) NUMBER, INCLUDING AREA CODE)
EXECUTIVE OFFICES)
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
- ------------------- ---------------------
Common Stock New York and Pacific
(also listed on London
Exchange)
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. [ ]
The aggregate market value of registrant's voting stock held by
non-affiliates was approximately $8,118,598,988 on or about March 1, 1994,
based upon prices reported on the New York Stock Exchange. As of March 1,
1994, there were 447,799,172 shares of Common Stock outstanding.
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, 1993 . . . . . . . . . . . . . . . . . . . . Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement relating
to registrant's 1994 Annual Meeting of Shareholders . . . . . . . . . . . . Part III
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TABLE OF CONTENTS
ITEM PAGE
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PART I
1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Business of SCEcorp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Regulation of SCEcorp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Business of Southern California Edison Company . . . . . . . . . . . . . . . . . . . . . 4
Regulation of Edison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Business of The Mission Group and its Subsidiaries . . . . . . . . . . . . . . . . . . . 13
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Existing Utility Generating Facilities . . . . . . . . . . . . . . . . . . . . . . 14
El Paso Electric Company ("El Paso") Bankruptcy . . . . . . . . . . . . . . . . . . 16
Construction Program and Capital Expenditures . . . . . . . . . . . . . . . . . . . 16
Nuclear Power Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Nuclear Waste Policy Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Competitive Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Antitrust Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Environmental Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
San Onofre Personal Injury Litigation . . . . . . . . . . . . . . . . . . . . . . . 23
4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . 23
Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . 24
PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . . . . . . . . . . . 30
8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 30
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . 30
PART III
10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . 31
11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 31
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
Report of Independent Public Accountants on Supplemental
Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
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PART I
ITEM 1. BUSINESS
BUSINESS OF SCECORP
SCEcorp was incorporated on April 20, 1987, under the laws of the
State of California for the purpose of becoming the parent holding company of
Southern California Edison Company ("Edison"), a California public utility
corporation. SCEcorp owns all of the issued and outstanding common stock of
Edison and, in addition, owns all of the issued and outstanding capital stock
of The Mission Group ("Mission Group"), which in turn owns the stock of
subsidiaries engaged in nonutility businesses. These subsidiaries are
currently engaged in developing cogeneration and other energy projects
("Mission Energy"), making financial investments in electric generating
facilities and other assets ("Mission First Financial") and developing,
managing, and selling existing real estate projects ("Mission Land").
SCEcorp is engaged solely in the business of holding for investment
the stock of its subsidiaries and is not presently conducting any independent
business activities. For the year ended December 31, 1993, Edison and Mission
Group accounted for 99.3% and 0.7%, respectively, of the net income of SCEcorp.
At December 31, 1993, Edison had 16,487 full-time employees and Mission Group
and its subsidiaries had 706 full-time employees. Currently, SCEcorp has no
employees of its own.
The principal executive offices of SCEcorp are located at 2244 Walnut
Grove Avenue, Rosemead, California 91770, and its telephone number is (818)
302-2222.
REGULATION OF SCECORP
SCEcorp and its subsidiaries are exempt from all provisions, except
Section 9(a)(2), of the Public Utility Holding Company Act of 1935 ("Holding
Company Act") on the basis that SCEcorp and Edison are incorporated in the same
state and their business is predominately intrastate in character and carried
on substantially in the state of incorporation. It is necessary for SCEcorp to
file an annual exemption statement with the Securities and Exchange Commission
("SEC"), and the exemption may be revoked by the SEC upon a finding that the
exemption may be detrimental to the public interest or the interest of
investors or consumers. SCEcorp has no intention of becoming a registered
holding company under the Holding Company Act.
SCEcorp is not a public utility under the laws of the State of
California and is not subject to regulation as such by the California Public
Utilities Commission ("CPUC"). See "Business of Southern California Edison
Company--Regulation of Edison" below for a description of the regulation of
Edison by the CPUC. However, the CPUC decision authorizing Edison to
reorganize into a holding company structure contains certain conditions, which,
among other things, ensure the CPUC access to books and records of SCEcorp and
its affiliates which relate to transactions with Edison; require SCEcorp and
its subsidiaries to employ accounting and other procedures and controls to
ensure full review by the CPUC and to protect against subsidization of
nonutility activities by Edison's customers; require that all transfers of
market, technological or similar data from Edison to SCEcorp or its affiliates
be made at market value; preclude Edison from guaranteeing any obligations of
SCEcorp without prior written consent from the CPUC; provide for royalty
payments to be paid by SCEcorp or its subsidiaries in connection with the
transfer of product rights, patents, copyrights or similar legal rights
from
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Edison; and prevent SCEcorp and its subsidiaries from providing certain
facilities and equipment to Edison except through competitive bidding. In
addition, the decision provides that Edison shall maintain a balanced capital
structure in accordance with prior CPUC decisions, that Edison's dividend
policy shall continue to be established by Edison's Board of Directors as
though Edison were a comparable stand-alone utility company, and that the
capital requirements of Edison, as determined to be necessary to meet Edison's
service obligations, shall be given first priority by the Boards of Directors
of SCEcorp and Edison.
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 SCEcorp's subsidiaries with respect to the operation of
existing facilities, on the timing, cost, location, design, construction and
operation of new facilities required to meet future load requirements, 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 existing facilities and operating procedures. SCEcorp is
unable to predict the extent to which additional regulations may affect the
operations and capital expenditure requirements of its subsidiaries.
The Clean Air Act provides the statutory framework to implement a
program for achieving national ambient air quality standards and provides for
maintenance of air quality in areas exceeding such standards. The Clean Air
Act was amended in 1990, giving the South Coast Air Quality Management District
("SCAQMD") 20 years to achieve all the federal air quality standards. The
SCAQMD's Air Quality Management Plan ("AQMP"), adopted in 1991, demonstrates a
commitment to attain federal air quality standards within 20 years. Consistent
with the requirements of the AQMP and the Clean Air Act Amendments of 1990
("CAAA"), the SCAQMD adopted rules to reduce emissions of oxides of nitrogen
("NOx") from combustion turbines, internal combustion engines, industrial
coolers and utility boilers. On October 15, 1993, the SCAQMD adopted the
Regional Clean Air Incentives Market ("RECLAIM") which replaces most of the
previous rule requirements with a market mechanism for NOx emission trading
(trading credits). RECLAIM will, however, still require Edison to reduce NOx
emissions through retrofit or purchase of trading credits on all basin
generation by over 86% by 2003. In Ventura County, a NOx rule was adopted
requiring more than an 88% NOx reduction by June 1996 at all utility boilers.
Edison's expected total cost to meet these requirements is approximately
$330,000,000 of capital expenditures.
The CAAA do not require any significant additional emissions control
expenditures that are identifiable at this time. The amendments call for a
five-year study of the sources and causes of regional haze in the southwestern
U.S. The extent to which this study may require sulfur dioxide emissions
reductions at Edison's Mohave Generating Station ("Mohave") is not known. The
acid rain provisions of the amended Clean Air Act also put an annual limit on
sulfur dioxide emissions allowed from power plants. Edison will receive more
sulfur dioxide allowances than it requires for its projected operations. The
CAAA also require the Environmental Protection Agency ("EPA") to carry out a
three-year study of risk to public health from emissions of toxic air
contaminants from power plants, and to regulate such emissions only if
required. As a result of a petition by Mohave County in the State of Arizona,
the Nevada Department of Environmental Protection ("NDEP") studied the impact
of the plume from Edison's Mohave plant on the Mohave area air quality. The
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regulatory outcome requires Edison to meet a new lower opacity limit in early
1994. The NDEP will review the opacity limit again in 1995 in conjunction with
an ongoing tracer study being conducted by the EPA and evaluate potential
impacts on visibility in the Grand Canyon from sulfur dioxide emissions. Until
more definitive information on tracer study results are available, Edison
expects to meet all the present regulations through improved operations at the
plant.
Regulations under the Clean Water Act require permits for the
discharge of certain pollutants into waters of the United States. 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 even more stringent limitations. In order to
comply with guidelines and standards applicable to steam electric power plants,
Edison incurs additional expenses and capital expenditures. Edison 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 by Edison.
The State of California has adopted a policy discouraging the use of
fresh water for plant cooling purposes at inland locations. Such a policy,
when taken in conjunction with existing federal and state water quality
regulations and coastal zone land use restrictions, could substantially
increase the difficulty of siting new generating plants anywhere in California.
SCEcorp has identified 46 sites for which any of its subsidiaries, are
or may be, responsible for remediation under environmental laws. SCEcorp's
subsidiaries are participating in investigations and cleanups at a number of
these sites and SCEcorp has recorded a $60,000,000 liability for the estimated
minimum costs to clean up several sites. Additional costs may be incurred as
progress is made in determining the magnitude of required remedial actions, as
the share of these costs attributable to SCEcorp's subsidiaries in proportion
to other responsible parties is determined and as additional investigations and
cleanups are performed.
The CPUC currently allows Edison rate recovery of environmental-
cleanup costs, subject to reasonableness reviews. Edison filed
for a reasonableness review of costs incurred through 1991 at two hazardous
substance sites. Hearings have been delayed due to a 1992 CPUC decision
involving another California utility, which concluded that the current
procedure may not be appropriate for these costs and requested interested
parties to recommend alternatives. In November 1993, the major California
utilities, the DRA and others filed a collaborative report recommending an
incentive mechanism, which would require shareholders to fund 10% of cleanup
costs. Shareholders would have the opportunity to recover these costs through
insurance. Accordingly, Edison has recorded a regulatory asset which
represents 90% of the estimated cleanup costs for sites covered by this
proposed mechanism. The remaining sites' cleanup costs are expected to be
immaterial and would be recovered through base rates. If approved by the CPUC,
Edison would be allowed to recover 90% of cleanup costs incurred to date under
the reasonableness review procedure ($11,000,000). A March 10, 1994 proposed
decision issued by a CPUC ALJ accepted the collaborative report's
recommendation. A final CPUC decision is expected in early 1994.
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Twenty of the 46 sites identified are Edison's former manufactured gas
plant sites. Edison's cleanup responsibility for these sites is based on
Edison's, or a predecessor company's, ownership or operation of the plants.
These gas plants were operated for the production of gas prior to the
widespread availability of natural gas. The EPA and the California Department
of Toxic Substances Control have determined that specified constituents of the
gas plant by-products are hazardous substances or hazardous wastes, and may
require removal or other remedial action.
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.
There is an unresolved issue regarding the degree to which coal wastes should
be regulated under RCRA. Increased regulation may result in an increase in
expenses related to the operation of Mohave.
The Toxic Substance 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 ("PCB waste"). Current costs for deposal of PCB waste are
immaterial.
Edison's capitalized expenditures for environmental protection for the
years 1969 through 1993 and its currently estimated capital expenditures for
such purpose for the years 1994 through 1998 are as follows:
(IN THOUSANDS)
AIR WATER SOLID ADDITIONAL
POLLUTION POLLUTION WASTE NOISE PLANT
YEARS TOTAL CONTROL CONTROL DISPOSAL ABATEMENT AESTHETICS CAPACITY MISCELLANEOUS
----- ----- ------- ------- -------- --------- ---------- -------- --------
1969-1993 $3,823,749 $770,911 $285,648 $60,320 $15,323 $2,454,146 $16,531 $220,870
1994 . . . 277,198 68,104 17,531 11,108 260 176,339 -- 3,856
1995 . . . 285,484 42,649 26,979 25,376 231 186,306 -- 3,943
1996 . . . 286,080 41,698 26,912 14,435 148 202,273 -- 614
1997 . . . 254,861 11,534 14,389 11,900 199 216,583 -- 256
1998 . . . 227,631 11,374 9,471 3,577 1,103 201,217 -- 889
These estimates include budgeted and forecasted plant expenditures
responsive to currently effective legislation. Projected capital expenditures
for environmental protection are subject to continuous review and periodic
revisions because of escalation in engineering and construction costs,
additions and deletions of planned facilities, changes in technology, evolving
environmental regulatory requirements and other factors beyond Edison's
control. Edison believes that costs incurred for these environmental purposes
will be recognized by the CPUC and the FERC as reasonable and necessary costs
of service for rate recovery purposes.
BUSINESS OF SOUTHERN CALIFORNIA EDISON COMPANY
Edison was incorporated under California law in 1909. Edison 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 some 800
cities and communities and a population of nearly 11 million people. As of
December 31, 1993, Edison had 16,487 full-time employees. During 1993, 37% of
Edison's total operating revenue was derived from commercial customers, 36%
from residential customers, 13% from industrial customers, 8% from public
authorities, 4% from agricultural and other customers and 2% from resale
customers. Edison comprises the major portion of the assets and revenues of
SCEcorp, its parent holding company.
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REGULATION OF EDISON
Edison'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 and depreciation practices. Edison's
resale operations are subject to regulation by the Federal Energy Regulatory
Commission ("FERC"). The FERC has the authority to regulate resale rates as
well as other matters, including transmission service pricing, accounting and
depreciation practices and licensing of hydroelectric projects.
Edison 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 Edison's power plants within
California are subject to the jurisdiction of the California Energy Commission
and the CPUC. Edison is subject to rules and regulations promulgated by the
California Air Resources Board and local air pollution control districts with
respect to the emission of pollutants into the atmosphere, the regulatory
requirements of the California State Water Resources Control Board and regional
boards with respect to the discharge of pollutants into waters of the state and
the requirements of the California Department of Toxic Substances Control with
respect to handling and disposal of hazardous materials and wastes. Edison 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 impact Edison. (See previous discussion of Environmental Matters
under the Business of SCEcorp, above.)
The California Coastal Commission has continuing jurisdiction over
the coastal permit for San Onofre Nuclear Generating Station ("San Onofre")
Units 2 and 3. Although the units are operating, the permit remains open.
This jurisdiction may continue for several years because it involves oversight
on mitigation measures arising from the permit.
The Department of Energy ("DOE") has regulatory authority over
certain aspects of Edison's operations and business relating to energy
conservation, solar energy development, power plant fuel use and disposal, coal
conversion, public utility regulatory policy and natural gas pricing.
RATE MATTERS
CPUC Retail Ratemaking
The rates for electricity provided by Edison to its retail customers
comprise several major components established by the CPUC to compensate Edison
for basic business and operational costs, fuel and purchased power costs, and
the costs of adding major new facilities.
Basic business and operational costs are recovered through base
rates, which are determined in general rate case proceedings held before the
CPUC every three years. During a general rate case, the CPUC critically
reviews Edison's operations and general costs to provide service (excluding
energy costs and, in certain instances, major plant additions). The CPUC then
determines the revenue requirement to cover those costs, including items such
as depreciation, taxes, cost of capital, operation, maintenance, and
administrative and general expenses. The revenue
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requirement is forecasted on the basis of a specified test year. Following the
revenue requirement phase of a general rate case, Edison and the CPUC proceed
to a rate design phase which allocates revenue requirements and establishes
rate levels for customers.
Base rates may be adjusted in the years between general rate case
years through an attrition year allowance. The attrition year allowance is
intended to allow Edison to recover, without lengthy hearings, specific
uncontrollable cost changes in its base rate revenue requirement and thereby
preserve Edison's opportunity to earn its authorized rate of return in the
years that are not general rate case test years.
In December 1993, Edison filed an application with the CPUC in which
it proposed a performance-based ratemaking procedure for recovery of operation
and maintenance ("O&M") expenses and capital-related costs. Such costs have
traditionally been recovered through general rate cases, attrition proceedings,
and cost of capital proceedings.
Edison proposed that the CPUC authorize a base rate revenue indexing
formula which would combine O&M and capital-related cost recovery. In
addition, Edison proposed that the period between general rate cases be
lengthened from three to six years. Cost of capital proceedings would occur
only after significant changes in utility capital markets.
Edison's fuel, purchased power and energy-related costs of providing
electrical service are recovered through a balancing account mechanism called
the Energy Cost Adjustment Clause ("ECAC"). Under the ECAC balancing account
procedure, fuel, purchased power and energy-related revenues and costs are
compared and the difference is recorded as either an undercollection or
overcollection. The amount recorded in the balancing account is periodically
amortized through rate changes which return overcollections to customers by
reducing rates or collect undercollections from customers by increasing rates.
The costs recorded in the ECAC balancing account are subject to review by the
CPUC and allowed for rate recovery only to the extent they are found to be
reasonable. Certain incentive provisions are included in the ECAC that can
affect the amount of fuel and energy-related costs actually recovered. Edison
is required to make an ECAC filing for each calendar year, and must also make a
second filing for a mid-year adjustment if such filing would result in an ECAC
rate change exceeding 5% of total annual revenue.
For Edison's interest in the three units of the Palo Verde Nuclear
Generating Station ("Palo Verde"), the CPUC authorized a 10-year rate phase-in
plan which deferred $200,000,000 of investment-related revenue during the first
four years of operations for each of the three units, commencing on their
respective commercial operation dates. Revenue deferred for each unit under
the plan for years one through four was $80,000,000, $60,000,000, $40,000,000
and $20,000,000, respectively. The deferrals and related interest are being
recovered over the final six years of each unit's phase-in plan.
The CPUC has also adopted a nuclear unit incentive procedure which
provides for a sharing of additional energy costs or savings between Edison and
its ratepayers when operation of any of the units of San Onofre or Palo Verde
is outside a specified target capacity factor ("TCF") range. For San Onofre
Units 2 and 3, and Palo Verde Units 1, 2 and 3 the TCF range is 55% to 80% of
their rated capacity.
The Electric Revenue Adjustment Mechanism ("ERAM") reflects the
difference between the recorded level of base rate revenue and the authorized
level of base rate revenue. This mechanism has been adopted by the CPUC
primarily to minimize the effect on earnings of fluctuations in retail
kilowatt-hour sales.
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General Rate Case ("GRC")
In December 1991, the CPUC issued a decision on the revenue
requirement phase of Edison's 1992 test year GRC application. The CPUC
authorized a $72,000,000 or 1% increase in Edison's base rate revenues,
effective January 20, 1992. The decision did not adopt Edison's request to
capitalize, rather than expense, computer software development and research,
development and demonstration ("RD&D") expenditures, but did allow Edison to
file additional information regarding such capitalization.
In April 1992, Edison filed supplemental testimony supporting its
request to capitalize application software development costs, and proposed to
decrease its authorized level of base rate revenues ("ALBRR") by $53,000,000 in
1993 and 1994. Edison and the CPUC's Division of Ratepayer Advocates ("DRA")
entered into a settlement agreement to allow rate recovery of capitalized
software expenditures in which Edison agreed to an additional $32,000,000 base
rate revenue decrease. The CPUC approved the settlement agreement in November
1992, and authorized a $48,900,000 decrease to Edison's ALBRR effective January
1, 1993. The related base rate revenue decrease was included in Edison's
January 15, 1993, consolidated revenue change. The CPUC also authorized a
$12,900,000 increase to Edison's ALBRR effective January 1, 1994. The related
base rate revenue increase was included in Edison's January 24, 1994,
consolidated revenue change.
In September 1992, Edison filed supplemental testimony supporting its
request to capitalize RD&D expenditures. In the additional filing, Edison
proposed to capitalize approximately $9,000,000 in RD&D project expenditures.
The DRA's supplemental testimony alleged that Edison did not comply with a CPUC
order regarding joint remote meter reading and recommended a $10,000,000
penalty for non-compliance. Additionally, the DRA proposed to disallow
approximately $4,500,000 of capital costs associated with Edison's research on
off-grid generation technology. The CPUC's decision is expected by the end of
1994.
In December 1992, the CPUC approved an ALBRR increase of
$110,000,000, effective January 1, 1993, for the 1993 attrition year allowance.
The related base rate revenue increase was included in Edison's January 15,
1993 consolidated revenue change. In April 1993, the CPUC modified its
decision (pursuant to a petition by Edison), and approved an ALBRR increase of
$10,400,000 effective April 28, 1993. The related base rate revenue increase
was included in Edison's January 24, 1994, consolidated revenue change.
In December 1993, the CPUC approved an ALBRR increase of $97,200,000
effective January 1, 1994, for: (1) the 1994 attrition year allowance; (2)
increased federal income taxes pursuant to the Revenue Reconciliation Act of
1993; and, (3) reduction in Edison's California property tax liability
resulting from a settlement agreement with the California State Board of
Equalization.
Each year, the CPUC reviews the components of the cost of capital for
all the California energy utilities in a generic cost of capital proceeding.
On December 3, 1993, the CPUC issued a final decision resulting in a
$108,000,000 reduction to Edison's ALBRR effective January 1, 1994. The
decision also resulted in a reduction of Edison's overall rate of return from
9.94% to 9.17%, a reduction in return on common equity from 11.80% to 11.00%,
and an increase to Edison's common equity capital ratio from 46.00% to 47.25%
effective January 1, 1994. The related base rate revenue decrease was included
in Edison's January 24, 1994, consolidated revenue change.
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In December 1993, Edison filed with the CPUC its 1995 GRC
application. In its application, Edison requested an increase to the ALBRR of
$117,000,000 above the expected year-end 1994 ALBRR level to become effective
January 1, 1995. On March 14, 1994, the DRA issued a report which, based on
Edison's preliminary review, recommended a $269,000,000 reduction to Edison's
expected year-end 1994 authorized level of base rate revenue. Evidentiary
hearings are expected to commence in April 1994, with a final CPUC decision
anticipated in December 1994.
In January 1994, the CPUC approved an ALBRR increase of $8,800,000
effective January 24, 1994, for base rate recovery of the permanent component
of Edison's fuel oil inventory. The related base rate revenue increase was
included in Edison's January 24, 1994, consolidated revenue change.
In November 1993, the CPUC approved an ALBRR increase of: (1)
$64,400,000 effective December 31, 1993; and (2) $63,100,000 effective January
1, 1994, to reflect cost recovery of employee post-retirement benefits other
than pensions ("PBOP"). In addition, the CPUC approved an ALBRR reduction of
$39,500,000 effective December 30, 1993, to reflect the removal of costs
associated with Edison's 1992 PBOP contributions. The related base rate
revenue reduction associated with the PBOP ALBRR changes was included in
Edison's January 24, 1994, consolidated revenue change, less $16,000,000 of
rate recovery deferred until 1995.
Energy Cost Adjustment Clause
In January 1992, the DRA issued a report on the reasonableness of
Edison's non-standard, non-affiliate qualifying facilities ("QF") power
purchase contracts included in Edison's 1989 and 1990 annual ECAC applications.
With respect to both ECAC periods, the DRA asserted that Edison had incorrectly
calculated firm capacity payments and bonus capacity payments to QFs by
including certain energy deliveries which the DRA contended should be excluded
or "truncated" from the calculation. The DRA recommended disallowances of
$2,500,000 for the 1989 record period and $4,800,000 for the 1990 record
period. On April 26, 1993, the DRA withdrew its January 1992 testimony
pursuant to an Edison-DRA agreement to jointly petition the CPUC for
clarification of the CPUC's intent regarding truncation and two other QF
contract administration issues. Edison and the DRA filed their joint petition
on April 23, 1993. On November 2, 1993, the CPUC voted to dismiss the joint
petition on the basis that the issues presented were complex and could be
developed more appropriately in an ECAC proceeding or through direct
negotiations among the affected parties. Pursuant to the Edison-DRA agreement,
a dismissal on this basis permits the DRA to renew its challenge to Edison's
truncation practice beginning with the 1991 ECAC record period and thereafter
in each subsequent ECAC record period. To date, the DRA has not recommended
further disallowances attributable to the truncation issue.
In March 1992, Edison and the DRA settled disputes relating to
Edison's power purchases from the 13 non-utility generation facilities
partially owned by Mission Energy. Pursuant to the settlements, Edison agreed
not to enter into new power purchase-contracts with Mission Energy and to a
one-time disallowance. On March 10, 1993, the CPUC issued a decision approving
the settlement and authorizing a ratepayer refund of $250,000,000 over a
two-year period beginning January 1, 1994. The decision also ordered an
immediate adjustment to Edison's ECAC balancing account with interest accruing
until the rate reduction takes effect. The
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$250,000,000 disallowance is fully reflected in Edison's financial statements.
In October 1993, the DRA issued its report on QF reasonableness
issues for the ECAC record period April 1990 through March 1991. In its
report, the DRA recommended that the CPUC disallow $1,574,000 in power purchase
expenses incurred as a result of purchases during the record period under a QF
contract with Mojave Cogeneration Company, a nonutility generator. In its
report, the DRA also alleged that in 1990 and 1991 Edison imprudently
renegotiated Mojave Cogeneration Company's contract with Edison, resulting in
higher ratepayer costs. The DRA further alleged that ratepayers may be harmed
in the amount of $31,600,000 (present value) over the contract's twenty-year
life. The DRA found the execution of five other QF contracts to be reasonable.
Hearings will likely be held no earlier than the second half of 1994.
The DRA issued four reports addressing Edison's non-QF reasonableness
showing for the April 1, 1991 through March 31, 1992 period. The DRA
recommended: 1) a disallowance of $2,205,000 of replacement power costs
associated with extended outage duration or reduced power production at
Edison's nuclear units, which was allegedly caused by human error; and 2) a
reduction of $1,203,000 to Edison's proposed TCF reward for San Onofre Unit 3,
based on excluding generation above the unit capacity rating. A January 25,
1994 ALJ proposed decision found three nuclear plant outages unreasonable,
resulting in a potential $1,600,000 disallowance, but rejected the DRA's
recommendations for reducing Edison's TCF reward. Edison filed comments on the
proposed decision on February 14, 1994. The final CPUC decision is expected in
March 1994.
On May 28, 1993, Edison requested a $152,000,000 annual rate increase
for service beginning January 1, 1994, for changes to the Energy Cost
Adjustment Billing Factor, Electric Revenue Adjustment Balancing Accounts
("ERABF"), Low Income Surcharge and base rate levels. Edison also made a rate
stabilization proposal which defers recovery of approximately $200,000,000 of
1994 fuel and purchased-power expenses until 1995. In July 1993, Edison
updated its ECAC request to a $181,000,000 increase. The DRA proposed a
$105,000,000 increase. In October 1993, Edison and the DRA stipulated to a
proposed $164,688,000 ECAC revenue increase subject to adjustment for
incorporating Edison's forecast December 31, 1993 balance in the ECAC, Low
Income Ratepayer Assistance, and ERABF to reflect more recent recorded data.
On January 19, 1994, the CPUC issued its decision which adopted a revenue
increase of $274,600,000. When this revenue change is combined with other
revenue changes which occurred on or before January 1, 1994, the total combined
revenue change is $232,101,000.
On May 28, 1993, Edison filed the non-QF portion of its
Reasonableness of Operations Report, which included power purchases and
exchanges and the operation of its hydro, coal, gas and nuclear resources for
the period April 1, 1992 through March 31, 1993. In February 1994, the DRA
recommended: (1) a $7,200,000 disallowance relating to fuel oil inventory
management; and (2) a $5,000,000 disallowance for transmission loss revenues.
Hearings on this matter are scheduled for October 1994.
Edison filed its QF Reasonableness of Operations Report on September
1, 1993. It is presently unknown when the DRA will file testimony in the QF
reasonableness phase.
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Palo Verde Outage Review
In March 1989, Palo Verde Units 1 and 3 experienced automatic
shutdowns. Since the resultant outages overlapped previously scheduled
refueling outages, normal refueling, maintenance, inspection, surveillance,
modification and testing activities were conducted at the units, as well as
modifications to the plants required by the NRC. Unit 3 was restored to
service on December 30, 1989, and Unit 1 was restored to service on July 5,
1990.
In December 1989, the CPUC instituted an investigation into the
outages pursuant to the California Public Utilities Code ("Code"). The Code
requires the CPUC to institute an investigation when any portion of a
utility's generating facilities has been out of service for nine consecutive
months. The CPUC order required that the subsequent collection of rates
associated with Palo Verde Units 1 and 3 be subject to refund pending review of
the outages. In November 1991, the DRA issued a report recommending
disallowances totaling more than $160,000,000 including a $63,000,000
disallowance for revenue collected during the outages (including interest).
In September 1993, Edison and the DRA agreed to settle these disputes
for $38,000,000 (including $29,000,000 for replacement power costs, $2,000,000
for capital projects and approximately $7,000,000 for interest), subject to
CPUC approval. The settlement resolves all issues related to the 1989-1990
outages at Palo Verde. The effect of the settlement has been fully reflected
in the financial statements. Edison expects a CPUC decision regarding the
settlement in mid 1994.
Mohave Order Instituting Investigation ("OII")
In April 1986, the CPUC began investigating the 1985 rupture of a
high pressure steam pipe at Mohave. Edison is the plant operator and 56%
owner. The CPUC's OII reviewed Edison's share of repair costs and replacement
fuel and energy related costs associated with the outage. Edison incurred
costs of approximately $90,000,000 (including interest) to repair damage from
the accident and provide replacement power during the six-month outage. This
total is net of Edison's recovery of expenses from the settlement of lawsuits
with contractors and insurance.
In May 1991, the DRA and its consultant issued reports alleging that
Edison imprudently operated the Mohave plant and therefore contributed to the
accident. As a result, the DRA recommended that all expenses incurred because
of the accident be disallowed in rates. The DRA did not quantify its proposed
disallowance. Edison believes that metallurgical and physical characteristics
of a weld reduced the otherwise expected pipe life to the point of failure
after 15 years of service. Edison filed testimony contesting the allegations
in May 1992, in December 1992, and on March 1, 1993. In March 1994, the CPUC
issued a decision finding that Edison acted unreasonably in failing to
implement an inspection program. The CPUC decision ordered a second phase of
this proceeding to quantify the disallowance.
High Voltage Direct Current Expansion Project ("HVDCEP")
The HVDCEP began operation in 1989. In October 1989, Edison filed a
report with the CPUC requesting recovery of $72,600,000 in project costs.
Subsequently, Edison and the DRA agreed on an accounting adjustment of
$150,000, and a settlement agreement was filed. A February 3, 1993 CPUC
decision upheld the settlement agreement allowing Edison recovery in rates of
approximately $72,450,000. In its 1995 GRC, Edison is requesting rate recovery
of an additional $7,000,000 associated with completion items and
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other HVDCEP-related expenditures. The total amount of rate recovery for the
HVDCEP that Edison will be allowed remains subject to further adjustment
pending a final determination of the cost-effectiveness of the project in
comparison with the power exchange agreement between Edison and the Los Angeles
Department of Water and Power.
FERC Resale Ratemaking
Edison sells electricity to public power utilities (the cities of
Anaheim, Azusa, Banning, Colton, Riverside and Vernon), Southern California
Water Company and Arizona Public Service Company ("APS") under rates subject to
FERC jurisdiction. In accordance with FERC procedures resale rates are subject
to refund with interest if subsequently disallowed. Edison believes any
refunds from pending rate proceedings, would not materially affect its results
of operations or financial position.
FUEL SUPPLY
Fuel and purchased-power costs amounted to approximately $3.29
billion in 1993, a 7% increase over 1992. Sources of energy and unit costs of
fuel for 1989 through 1993 were as follows:
AVERAGE COST PER MILLION
SOURCES OF ENERGY BTU'S(1)
----------------------------------- ---------------------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
----------------------------------- ---------------------------------------
1989 1990 1991 1992 1993 1989 1990 1991 1992 1993
---- ---- ---- ---- ---- ----- ----- ----- ----- -----
Oil . . . . . . . . . . . 4% 2% * * * $3.03 $4.39 $4.07 $5.75 $6.08
Natural Gas . . . . . . . 24 17 18% 24% 23% 3.24 3.02 2.81 2.78 2.89
Nuclear . . . . . . . . . 17 20 21 22 18 1.04 0.94 0.87 0.66 0.51
Coal . . . . . . . . . . . 13 13 14 14 13 1.14 1.21 1.15 1.15 1.19
--- --- --- --- ---
All Fuels . . . . . . . . 58 52 53 60 54 2.15 1.90 1.64 1.65 1.77
Hydroelectric(2) . . . . . 4 3 4 3 7
Purchased Power(2):
Firm . . . . . . . . . 6 3 3 3 2
Economy . . . . . . . . 7 13 8 2 3
Other power producers:
Biomass . . . . . . . 1 2 2 2 3
Cogeneration . . . . 17 19 20 20 20
Geothermal . . . . . 5 6 7 7 8
Solar . . . . . . . . 1 1 1 1 1
Wind . . . . . . . . 1 1 2 2 2
--- --- --- --- ---
Total 100% 100% 100% 100% 100%
=== === === === ===
_______________
(1) British Thermal Unit ("BTU") is the standard unit of measure for the
heat content of fuels. One BTU is the amount of heat required to
raise the temperature of one pound of water, at 39.1 degrees
Fahrenheit, by one degree Fahrenheit.
(2) There are no fuel costs associated with these categories.
* Indicates a source of less than 1%.
Average fuel costs, expressed in cents per kilowatt-hour, for the year
ended December 31, 1993, were: oil, 7.996c.; natural gas, 2.930c.; nuclear,
0.537c.; and coal, 1.226c..
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Natural Gas Supply
Twelve of Edison's major steam electric generating units are designed
to burn oil or natural gas as a primary boiler fuel. In 1990, Edison adopted
an all-gas strategy to comply with air quality goals by eliminating burning oil
in all but very extreme conditions. In August 1991, the CPUC adopted
regulations which made Edison fully responsible for all gas procurement
activities previously performed by local distribution companies for natural
gas.
To implement its all-gas strategy, Edison acquired a balanced
portfolio of gas supply and transportation arrangements. Traditionally,
natural gas needs in southern California were met from gas production in the
southwest region of the country. To diversify its gas supply, Edison entered
into four 15-year natural gas supply agreements with major producers in western
Canada. These contracts, totaling 200,000,000 cubic feet per day, have
market-sensitive pricing arrangements. This represents about 40% of Edison's
current average annual supply needs. The rest of Edison's gas supply is
acquired under short-term contracts from West Texas, New Mexico, and the Rocky
Mountain region.
Firm transportation arrangements provide the necessary long-term
reliability for supply deliverability. To transport Canadian supplies, Edison
contracted for 200,000,000 cubic feet per day of firm transportation
arrangements on the Pacific Gas Transmission and Pacific Gas & Electric
Expansion Project connecting southern California to the low-cost gas producing
regions of western Canada. Edison has a 30-year commitment to this project,
construction of which was completed in late 1993. In addition, Edison has a
15-year commitment to 200,000,000 cubic feet per day of firm transportation
rights on El Paso Natural Gas' pipeline to transport Southwest U.S. gas
supplies.
Nuclear Fuel Supply
Edison has contractual arrangements covering 100% of the projected
nuclear fuel cycle requirements for San Onofre through the years indicated
below:
UNITS
2 & 3
-----
Uranium concentrates(1) . . . . . . . . . . . . . . . 1995
Conversion . . . . . . . . . . . . . . . . . . . . . . 1995
Enrichment . . . . . . . . . . . . . . . . . . . . . . 1998
Fabrication . . . . . . . . . . . . . . . . . . . . . 2000
Spent fuel storage(2) . . . . . . . . . . . . . . . . 2005/2004
_______________
(1) Assumes the San Onofre participants meet their supply obligations in a
timely manner.
(2) Assumes full utilization of expanded on-site storage capacity and
normal operation of the units, including interpool transfers and
maintaining full-core reserve. To supplement existing spent fuel
storage, a contingency plan is being developed to construct additional
on-site storage capacity with initial operation scheduled for no later
than 2002. The Nuclear Waste Policy Act of 1982 requires that the DOE
provide for the disposal of utility spent nuclear fuel beginning in
1998. The DOE has stated that it is unlikely that it will be able to
start accepting spent nuclear fuel at its permanent repository before
2010.
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Participants in Palo Verde have purchased uranium concentrates
sufficient to meet projected requirements through 1997. Independent of
arrangements made by other participants, Edison will furnish its share of
uranium concentrates requirements through at least 1995 from existing
contracts. Contracts to provide conversion services cover requirements through
1994. Enrichment and fabrication contracts will meet Palo Verde requirements
through 1995 and 1997, respectively.
Palo Verde on-site expanded spent fuel storage capacity will
accommodate needs through 2005 for Units 1 and 2 and 2006 for Unit 3, while
maintaining full-core reserve.
BUSINESS OF THE MISSION GROUP AND ITS SUBSIDIARIES
Mission Group was incorporated in 1987 to own the stock and coordinate
the activities of several companies engaged in nonutility businesses. The
principal subsidiaries of Mission Group are Mission Energy, Mission First
Financial and Mission Land. A fourth subsidiary, Mission Power Engineering
Company, discontinued operations in 1990. The businesses of these companies
are described below. For SCEcorp's business segment information for each of
the three years ended December 31, 1993, 1992 and 1991, see Note 12 of "Notes
to Consolidated Financial Statements" contained in the 1993 Annual Report to
Shareholders incorporated by reference in this report.
On December 31, 1993, Mission Group had consolidated assets of $3.3
billion and, for the year then ended, had consolidated operating revenue of
$424,500,000 and consolidated net income of $3,000,000.
Mission Group's principal executive offices are located at 18101 Von
Karman Avenue, #1700, Irvine, California 92715.
Mission Energy. Mission Energy, primarily through its subsidiary
corporations, is engaged in the business of developing, owning, and operating
cogeneration, small power, geothermal, and other principally energy-related
projects. At December 31, 1993, Mission Energy subsidiaries held interests in
33 operating power production facilities with an aggregate power production
capability of 4,105 MW, of which 1,862 MW are attributable to Mission Energy's
interests. These operating facilities are located in California, Nevada, New
Jersey, Pennsylvania, Virginia, Washington, Australia, Spain, and the United
Kingdom. In addition, facilities aggregating more than 1,746 MW, of which one
500 MW facility is located in Australia, are in construction or advanced
permitting stages. Mission Energy owns interests in oil and gas producing
operations and related facilities in Canada and U.S. locations in Texas,
Alabama, New Mexico, California and offshore Louisiana. In February 1994,
Mission Energy -- as lead developer -- and its partners, General Electric
Capital Corporation, Mitsui & Co., Ltd. and P.T. Batu Hitam Perkasa, signed a
30-year power-purchase agreement with the Indonesian government for the
1,230-MW Paiton project.
At December 31, 1993, Mission Energy had total consolidated assets of
$1.8 billion and for the year then ended, had consolidated operating revenue of
$272,800,000 and consolidated net income of $2,300,000.
Currently, most of Mission Energy's operating power production
facilities have QF status under the Public Utility Regulatory Policies Act of
1978 ("PURPA") and the regulations promulgated thereunder. QF status exempts
the projects from the application of the Holding Company Act, many provisions
of the Federal Power Act, and state laws and regulations respecting rates and
financial or organizational regulation of electric
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utilities. Mission Energy, through wholly-owned subsidiaries, also has
ownership interests in two operating power projects that have received exempt
wholesale generator status as defined in the Holding Company Act. In addition,
some Mission Energy subsidiaries have made fuel-related investments and a
limited number of non-energy related investments.
While QF status entitles projects to the benefits of PURPA, each
project must still comply with other federal, state and local laws, including
those regarding siting, construction, operation, licensing and pollution
abatement.
Mission First Financial. Mission First Financial participates in
investment opportunities involving leveraged leasing, project financing,
affordable housing and cash management. Its investments include interests in
nuclear power, cogeneration, waste-to-energy, hydroelectric, electric
transportation and affordable housing facilities. Since its inception in 1987,
Mission First Financial has invested in 71 projects. In 1993, Mission First
Financial invested $20,000,000 in a sale/leaseback of electric locomotive
equipment with the Dutch rail authority. In addition, Mission First Financial
invested $62,000,000 in 23 completed affordable housing projects and signed
commitments to invest in 19 additional projects.
At December 31, 1993, Mission First Financial had total consolidated
assets of $972,000,000 and, for the year then ended, had consolidated operating
revenue of $31,500,000 (including interest income) and consolidated net income
of $29,200,000.
Mission Land. Mission Land is engaged, directly and through its
subsidiaries, in the business of developing, owning and managing industrial
parks and other real property investments. Mission Land owns and manages
commercial and industrial buildings in industrial parks located in Brea, Chino,
Garden Grove, Ontario, Oceanside and Rancho Cucamonga, California. Mission
Land and its subsidiaries also have interests in industrial, residential and
commercial real estate in California; Tolleson, Arizona; Munster, Indiana;
Chicago, Illinois and in other locations. SCEcorp has decided no longer to
pursue real estate development as one of its core businesses and plans to exit
this business in an orderly fashion over time.
At December 31, 1993, Mission Land had total consolidated assets of
$516,300,000 and for the year then ended, had consolidated operating revenue of
$112,500,000 and a consolidated net loss of $15,300,000. Mission Land has
reduced assets by one-third since 1991 primarily through asset sales, reduced
debt significantly, improved operating income through higher occupancy rates,
and has increased reserves. As a result, Mission Land believes it has improved
its ability to systematically exit the real estate business in a
self-sustaining way. However, Mission Land may experience additional losses if
the real estate market remains weak.
ITEM 2. PROPERTIES
EXISTING UTILITY GENERATING FACILITIES
Edison owns and operates 12 oil- and gas-fueled electric generating
plants, one diesel-fueled generating plant, 38 hydroelectric plants and an
undivided 75.05% interest (1,614 MW net) in Units 2 and 3 at San Onofre. These
plants are located in central and southern California. Palo Verde (15.8%
Edison-owned, 579 MW net) is located near Phoenix, Arizona. Palo Verde Units
1, 2 and 3 started commercial operation on February 1, 1986, September 19,
1986, and January 20, 1988, respectively. Edison owns a 48% undivided interest
(754 MW) in Units 4 and 5 at the Four
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Corners Generating Station ("Four Corners Project"), a coal-fueled steam
electric generating plant in New Mexico. Palo Verde and the Four Corners
Project are operated by other utilities. Edison operates and owns a 56%
undivided interest (885 MW) in Mohave, which consists of two coal-fueled steam
electric generating units in Clark County, Nevada. Edison receives an
entitlement of 277 MW from the DOE's Hoover Dam Hydroelectric Project. At
year-end 1993, the existing Edison-owned generating capacity (summer effective
rating) was comprised of approximately 67% gas, 14% nuclear, 11% coal and 8%
hydroelectric.
San Onofre, the Four Corners Project, certain of Edison's substations
and portions of its transmission, distribution and communication systems are
located on lands of the United States 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 Edison, 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.
With certain exceptions, major and certain minor hydroelectric
projects with related reservoirs, currently having an effective operating
capacity of 1,154 MW and located in whole or in part on lands of the United
States, are owned and operated by Edison under governmental licenses which
expire at various times between 1994 and 2022. Such licenses impose numerous
restrictions and obligations on Edison, including the right of the United
States to acquire the project 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 Edison's and then
only upon payment of specified compensation to Edison. Any new licenses issued
to Edison are expected to be issued under terms and conditions less favorable
than those of the expired licenses. Edison's applications for the relicensing
of certain hydroelectric projects referred to above with an aggregate effective
operating capacity of 89.0 MW are pending. Annual licenses issued for all
Edison projects, whose licenses have expired and are undergoing relicensing,
will be renewed until the new licenses are issued.
In 1993, Edison's peak demand was 16,475 MW, set on September 9, 1993.
The 1993 peak was 1,938 MW less than Edison's record peak demand of 18,413 MW
that occurred on August 17, 1992. Total area system operating capacity of
20,606 MW was available to Edison at the time of the 1993 record peak.
Substantially all of Edison's properties are subject to the lien of a
trust indenture securing First and Refunding Mortgage Bonds ("Trust
Indenture"), of which approximately $3.5 billion principal amount was
outstanding at December 31, 1993. Such lien and Edison'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 Edison's title to its properties are subject to certain other
liens, prior rights and other encumbrances, none of which, with minor or
unsubstantial exceptions, affects Edison's right to use such properties in its
business, unless the matters with respect to Edison's interest in the Four
Corners Project and the related easement and lease referred to below may be so
considered.
Edison's rights in the Four Corners Project, which is located on land
of The Navajo Tribe of Indians under an easement from the United States and a
lease from The Navajo Tribe, may be subject to possible defects. These defects
include possible conflicting grants or encumbrances not
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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 Tribe, the possible inability of Edison to resort to legal process to
enforce its rights against The Navajo Tribe without Congressional consent,
possible impairment or termination under certain circumstances of the easement
and lease by The Navajo Tribe, Congress or the Secretary of the Interior and
the possible invalidity of the Trust Indenture lien against Edison's interest
in the easement, lease and improvements on the Four Corners Project.
EL PASO ELECTRIC COMPANY ("EL PASO") BANKRUPTCY
El Paso owns and leases a combined 15.8% interest in Palo Verde and
owns a 7% interest in Units 4 and 5 of the Four Corners Project. In January
1992, El Paso filed a voluntary petition to reorganize under Chapter 11 of the
Bankruptcy Code in the United States Bankruptcy Court for the Western District
of Texas. Pursuant to an agreement among the Palo Verde participants and an
agreement among the participants in Four Corners Units 4 and 5, each
participant is required to fund its proportionate share of operation and
maintenance, capital and fuel costs of Palo Verde and Four Corners Units 4 and
5, respectively. The participation agreements provide that if a participant
fails to meet its payment obligation, each non-defaulting participant must pay
its proportionate share of the payments owed by the defaulting participant. In
February 1992, the bankruptcy court approved a stipulation between El Paso and
APS, as the operating agent of Palo Verde, pursuant to which El Paso agreed to
pay its proportionate share of all Palo Verde invoices delivered to El Paso
after February 6, 1992. El Paso agreed to make these payments until such time,
if ever, the bankruptcy court orders El Paso's rejection of the participation
agreement governing the relations among the Palo Verde participants. The
stipulation also specifies that approximately $9,200,000 of El Paso's Palo
Verde payment obligations invoiced prior to February 7, 1992, are to be
considered "pre-petition" general unsecured claims of the other Palo Verde
participants.
On August 27, 1993, El Paso filed with the bankruptcy court an Amended
Plan of Reorganization and Disclosure Statement ("Amended Plan"). The Amended
Plan, which is subject to numerous conditions, proposes a reorganization
pursuant to which El Paso will become a wholly- owned subsidiary of Central and
South West Corporation. The Amended Plan also proposes, among other things,
(i) rejection of the El Paso leases and reacquisition by El Paso of the Palo
Verde interests represented by the leases, and (ii) El Paso's assumption of the
Four Corners Operating Agreement and the Arizona Nuclear Power Project
Participation Agreement. On November 19, 1993, the bankruptcy court approved a
Cure and Assumption Agreement among El Paso and the Palo Verde Participants, in
which El Paso shall (i) assume the Participation Agreement on the date the
Amended Plan becomes effective, and (ii) cure its pre-petition default on the
date the court approves the Order Confirming El Paso's Amended Plan. On
December 8, 1993, the bankruptcy court confirmed El Paso's Amended Plan.
Effectiveness of the Amended Plan is still subject to approval by numerous
state and federal agencies. El Paso estimates that it will take about 18
months to obtain all necessary regulatory approvals.
CONSTRUCTION PROGRAM AND CAPITAL EXPENDITURES
In April 1992, the CPUC decided how Edison and other California
utilities will meet their resource needs through 2002. The CPUC ruled that
Edison must obtain 624 MW of new generation through competitive bidding. The
decision required that 175 MW be reserved for renewables, such as wind, hydro
and geothermal. The competitive bid solicitation was issued in August 1993
and suspended in December 1993 due to the discovery
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of a bidding anomaly that raised prices above those allowed by the rules of the
solicitation. After the suspension, Edison requested the solicitation be
cancelled because current forecasts show that Edison has no need for additional
generating capacity until at least 2005.
From the solicitation results, Edison has estimated that the cost of
these resources would be approximately $530,000,000 (present value in 1997
dollars). However, two events have occurred that should reduce Edison's cost
exposure resulting from power purchases under this CPUC mandated process.
First, on March 15, 1994, Edison and Kenetech Corporation, a potential winning
bidder in Edison's solicitation, signed a memorandum of understanding for a
wind resource power purchase. Contingent upon CPUC approval, Kenetech, under
this proposed agreement, will provide lower cost resources than those
potentially awarded through Edison's solicitation. Second, on March 16, 1994,
the CPUC issued an interim decision that reduces Edison's solicitation by 25%
and gives Edison authority to eliminate the added costs from the bidding
anomaly. Although Edison will likely continue to request cancellation of the
competitive solicitation, these two events reduce Edison's exposure. The
exact amount of this reduction cannot be estimated until the methodology the
CPUC intends for implementation of these changes is known.
Cash required by SCEcorp for its capital expenditures totaled $1.26
billion in 1993, $1.24 billion in 1992, and $1.03 billion in 1991.
Construction expenditures for the 1994-1998 period are estimated as follows:
(IN MILLIONS)
1994 1995 1996 1997 1998 TOTAL
------ ------ ------ ------ ------ ------
Electric generating plant . . . . . . . . . . . . . . $ 378 $ 353 $ 283 $ 264 $ 491 $1,769
Electric transmission lines
and substations . . . . . . . . . . . . . . . . . 131 121 153 173 252 830
Electric distribution lines
and substations . . . . . . . . . . . . . . . . . 486 559 529 560 556 2,690
Other expenditures . . . . . . . . . . . . . . . . . 184 194 145 139 92 754
Nonutility expenditures . . . . . . . . . . . . . . . 164 147 88 1 1 401
------ ------ ------ ------ ------ ------
Total . . . . . . . . . . . . . . . . . . . . . 1,343 1,374 1,198 1,137 1,392 6,444
Less: allowance for funds used
during construction . . . . . . . . . . . . . . . 38 44 43 43 43 211
------ ------ ------ ------ ---- ------
Cash required for construction expenditures . . . . . $1,305 $1,330 $1,155 $1,094 $1,349 $6,233
====== ====== ====== ====== ====== ======
Edison's construction program and related expenditures are
continuously reviewed and periodically revised because of changes in estimated
system load growth, rates of inflation, receipt of adequate and timely rate
relief, the availability and timing of environmental, siting and other
regulatory approvals, the scope of modifications required by regulatory
agencies, the availability and costs of external sources of capital, the
development of new technology and other factors beyond Edison's control.
Since the completion of San Onofre Units 2 and 3 and Palo Verde Units
1, 2 and 3, construction work in progress has been significantly reduced. The
reduction in construction work in progress caused allowance for funds used
during construction ("AFUDC"), which does not represent current cash income, to
decline accordingly. Pre-tax AFUDC represented 5.7% of earnings for 1993.
In addition to cash required for construction expenditures for the
next five years as discussed above, $1.3 billion is needed to meet requirements
for long-term debt maturities, and sinking fund redemption
17
20
requirements. The majority of these capital requirements are expected to be
met by internally generated sources.
Edison's estimates of cash available for operations for the five years
through 1998 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. Edison'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 Edison's Articles of Incorporation and Trust Indenture.
NUCLEAR POWER MATTERS
Although higher energy costs will be incurred for replacement
generation during any periods the San Onofre and Palo Verde Units are not in
operation, substantially all such costs will be included in future ECAC
filings. Edison cannot predict what other effects, if any, legislative or
regulatory actions may have upon it or upon the future operation of the San
Onofre or Palo Verde Units or the extent of any additional costs it may incur
as a result thereof, except for those that follow.
San Onofre Unit 1
On November 30, 1992, Edison discontinued operation of San Onofre Unit
1. The CPUC approved an agreement between Edison and the DRA which allows
Edison recovery of its investment of approximately $350,000,000 (after deferred
taxes), including an 8.98% rate of return, by August 1996.
The agreement does not affect Unit 1's decommissioning, scheduled to
start in 2013. The estimated current-dollar decommissioning costs for Unit 1
have been recorded as a liability.
San Onofre Units 2 and 3
In 1974, the California Coastal Commission, as a condition of the San
Onofre Units 2 and 3 coastal permit, established a three-member Marine Review
Committee ("MRC") to assess the marine environmental effects caused by the
Units. In August 1989, the MRC issued its final report which alleged, in part,
that San Onofre Units 2 and 3 caused adverse effects to several species of
marine life and to the environment.
Based on the MRC findings, the Coastal Commission in 1991 revised the
coastal permit for Units 2 and 3 and required Edison to restore 150 acres of
degraded wetlands, construct a 300-acre artificial kelp reef, and install fish
behavioral barriers inside the Units' cooling water intake structure. Edison
is currently in the process of planning and designing these projects, all of
which must receive the approval of the Coastal Commission and state and federal
resource and regulatory agencies. Current estimates place Edison's share of
these capital costs at about $83,000,000 which is expected to be spent over the
next 10 to 12 years.
Palo Verde Nuclear Generating Station
On March 14, 1993, APS, as operating agent, manually shut down Palo
Verde Unit 2 as a result of a steam generator tube leak. Unit 2 remained shut
down and began its scheduled refueling outage on March 19, 1993.
An extensive inspection of the Palo Verde Unit 2 steam generators was
performed prior to the unit's return to service on September 1, 1993. APS
18
21
determined that intergranular attack/intergranular stress corrosion cracking
was a major contributor to the tube leak. APS is continuing its evaluation of
the effects of possible steam generator tube degradation in all three units
(six steam generators) and has instituted several avenues of study and
corrective action.
Palo Verde Units 1, 2, and 3 will be operated at reduced power (85%)
until the investigation and other associated activities are completed. APS
expects to be able to return the units to full power after implementing
corrective action.
Nuclear Facility Decommissioning
Edison's share of costs to decommission nuclear generation facilities
is estimated to be $225,500,000 for San Onofre Unit 1; $280,900,000 for San
Onofre Unit 2; $365,400,000 for San Onofre Unit 3; $50,200,000 for Palo Verde
Unit 1; $49,800,000 for Palo Verde Unit 2; and $55,400,000 for Palo Verde Unit
3. These costs are all in 1993 dollars.
Edison is currently collecting $104,255,000 annually in rates for its
share of decommissioning costs for San Onofre Units 1, 2 and 3 and Palo Verde
Units 1, 2 and 3. As of December 31, 1993, Edison's decommissioning trust
funds totaled approximately $853,000,000 (market value).
In accordance with the Energy Policy Act of 1992, Edison's recorded
liability at December 31, 1993, of $72,300,000 represents its share of the
estimated costs to decommission three federal nuclear enrichment facilities.
This cost is based on San Onofre's and Palo Verde's past purchases of
enrichment services and will be paid over 15 years. These costs are expected
to be recovered through the ECAC procedure and from participants.
Nuclear Facility Depreciation
To reduce Edison nuclear facilities' capital cost effect on future
customer rates, Edison has filed for a $75,000,000 per year accelerated
recovery of its nuclear investments. To offset the increased cost recovery,
Edison proposes to lengthen its recovery period for transmission and
distribution assets. This proposal would have no significant effect on
customer rates. The CPUC held hearings in October 1993 and Edison expects a
decision in mid-1994.
Nuclear Insurance
Edison carries the maximum insurance coverage reasonably available to
protect against losses from damage to its nuclear units and to provide some of
its replacement energy costs in the unlikely event of an accident at any of its
nuclear units. A description of this insurance is included in Note 10 of
"Notes to Consolidated Financial Statements" incorporated herein. Although
Edison believes an accident at its nuclear units is extremely unlikely, in the
event of an accident, regardless of fault, Edison's insurance coverage might be
inadequate to cover the losses to Edison. In addition, such an accident could
result in NRC action to suspend operation of the damaged unit. Further, the
NRC could suspend operation at Edison's undamaged nuclear units and the CPUC
and FERC could deny rate recovery of related costs. Such an accident,
therefore, could materially and adversely affect the operations and earnings of
Edison.
NUCLEAR WASTE POLICY ACT
Under the Nuclear Waste Policy Act of 1982, Edison, acting as agent
for the San Onofre participants, has entered into a contract with the DOE for
disposal of spent nuclear fuel for San Onofre Units 1, 2 and 3. Under
19
22
the terms of the contract, Edison is required to pay a quarterly fee of one
mill per kilowatt hour to the DOE for net nuclear power generated and sold on
and after April 7, 1983. During 1992, DOE implemented a refund process for
overpayments to the Nuclear Waste Fund through credits against future quarterly
payments.
For generation prior to April 7, 1983, the contract required payment
of a one-time fee equivalent to one mill per kilowatt hour, plus accrued
interest. The obligation for this one-time fee was being discharged by equal
quarterly payments. In October 1992 and 1993, DOE credits arising from
overpayments to the Nuclear Waste Fund were also applied to this obligation.
In October 1993, this obligation was paid in full. Expenses associated with
the disposal of spent nuclear fuel are recovered through the ECAC procedure and
from participants.
COMPETITIVE ENVIRONMENT
Under various acts of Congress, federal power projects have been
constructed in California and neighboring states. Municipally owned utilities,
cooperative utilities and other public bodies have certain preferences over
investor-owned utilities in the purchase of electric power provided by
federally funded power projects and, in addition, have certain preferences over
investor-owned utilities in connection with the acquisition of licenses to
build and/or operate hydroelectric power plants. Any energy which is or may
be generated at these projects and transmitted for the account of such other
utilities and public bodies over present or future government or utility-owned
lines into the territory or markets served by Edison would result in a loss of
sales by Edison.
Under the laws of California, utility districts may include
incorporated as well as unincorporated territory. Such districts, as well as
municipalities, have the right to construct, purchase or condemn and operate
electric facilities. In addition, when a city owning an electric system
annexes adjacent unincorporated territory which Edison has previously served,
Edison may experience a loss of customers.
Edison's construction permits for San Onofre Units 2 and 3 contain
certain conditions which require Edison (i) on timely notice, to permit
privately or publicly owned utilities, including Edison's resale customers
within or adjacent to Edison's service area, to participate on mutually
agreeable terms in future nuclear units initiated by Edison, and (ii) to
interconnect and coordinate reserves with, furnish emergency service to, sell
bulk power to and purchase bulk power from, and provide certain transmission
services for such utilities. Edison has also entered into agreements with
certain of its resale customers which contemplate their possible participation
in jointly owned generating projects initiated by Edison, and the integration
of power sources acquired by each such customer, including the dispatching,
reserve sharing, partial power-supply requirements and transmission service
required in connection with such integrated operations. Pursuant to these
agreements, two resale customers exercised an option to participate in Edison's
ownership entitlement in San Onofre Units 2 and 3. Effective November 1977,
Edison sold an undivided 3.45% interest in San Onofre Units 2 and 3 to these
two resale customers for approximately $90,000,000. Effective September 1981,
a further 1.5% interest in Units 2 and 3 was sold to one of these resale
customers for approximately $50,000,000. In addition, since 1986, six of
Edison's resale customers have acquired ownership interests in other generating
sources and made purchases from other utilities in such amounts as to decrease
Edison's revenues from resale cities from 4.4% to 1.6% of sales. This revenue
loss has not had a substantial effect on Edison's business and opportunities.
20
23
PURPA has fostered the entry of nonutility companies into the electric
generation business. Under PURPA, nonutility power producers are allowed to
construct QFs for the production of electricity from certain alternative or
renewable energy resources, and utilities are required to purchase the
electrical output of these QFs at prices set pursuant to state regulations and,
in the future, pursuant to a CPUC- approved competitive bidding process.
Edison is required by contracts and state regulation to continue to
buy power generated by QFs, under long-term contracts negotiated earlier at
prices that are most often higher than the power Edison can produce or purchase
from other sources. Edison is presently managing contracts with QF developers
to reduce ratepayer impacts and to more closely match Edison's needs with
proposed development. Further, certain operators of QFs sell power they
produce to large industrial and commercial customers of Edison from projects
located on-site. Further loss of sales from such customers may be aggravated
in the future as a result of attempts by these producers to gain access to a
utility's transmission lines to sell power directly to retail customers now
being served by that utility--an activity called "retail wheeling." Edison
opposes any attempt to impose mandatory wheeling to Edison's retail customers.
In late 1992, Congress passed the Energy Policy Act of 1992. This Act
creates a new class of Exempt Wholesale Generators ("EWGs") who are exempt from
the restrictions otherwise imposed on utilities under the Public Utility
Holding Company Act. The effect of this exemption is to facilitate the
development of more independent third-party generators potentially available to
satisfy utilities' needs for increased power supplies. However, unlike
purchases from QFs, utilities have no statutory obligation to purchase power
from EWGs. Furthermore, EWGs are precluded from making direct sales to retail
electricity customers.
The Energy Policy Act also broadens the authority of the FERC to
require a utility to transmit power produced by a wholesale producer to another
utility. Municipal utilities are eligible applicants for such transmission
service. However, the FERC is precluded from ordering a utility to transmit
power from another entity directly to a retail customer. The authority of
states to order such retail wheeling is unclear; but, to the extent such
authority exists, it is explicitly preserved by the Energy Policy Act.
ITEM 3. LEGAL PROCEEDINGS
ANTITRUST MATTERS
In 1983, a public power utility, the City of Vernon, filed a complaint
against Edison in the United States District Court for the Central District of
California, alleging violation of certain antitrust laws. The complaint
alleged that Edison engaged in anticompetitive behavior by restricting access
to Edison transmission facilities and foreclosing Vernon from purchasing bulk
power supplies from other sources. Vernon also alleged that Edison unlawfully
designed its resale rates and claimed damages of approximately $60,000,000
before trebling. Edison filed three motions for Summary Judgment and the
District Court entered final judgment in favor of Edison in August 1990. In
October 1990, Vernon appealed the District Court decision to the Ninth Circuit
Court of Appeals. In February 1992, the Court of Appeals affirmed the District
Court's rulings on all issues but one, involving injunctive relief only, and
remanded that issue back to the District Court for consideration. In July
1992, Vernon filed a writ of certiorari to the U.S. Supreme Court which was
denied. On July 13, 1993, Edison and Vernon settled the remaining issue
regarding injunctive relief. The settlement is part of a broader settlement of
regulatory issues that was approved by the FERC on October 27, 1993.
21
24
On January 31, 1991, California Energy Company ("CEC") filed a lawsuit
in United States District Court for the Northern District of California
against SCEcorp, Edison, several nonutility subsidiaries, selected individuals,
and Kidder, Peabody & Co. CEC alleged antitrust violations of the Sherman Act,
conspiracy to interfere with contractual relations and common law unfair
competition. CEC asked for treble damages (as proved at trial) for antitrust
violations and compensatory and punitive damages for the pendent claims.
Furthermore, CEC requested that SCEcorp divest itself of Mission Energy. On
April 30, 1993, Edison and CEC reached a settlement. In June 1993, a
nonutility affiliate and CEC settled a related lawsuit concerning construction
of CEC's power plants. Pursuant to the settlements, the case was dismissed.
Further terms of the CEC settlement relate to litigation involving
Mission Power Engineering Company in connection with a construction contract.
In June 1990, Mission Power filed suit to foreclose on mechanics liens against
CEC, Coso Finance Partners, Coso Energy Developers, Coso Power Developers
("Coso Entities") and Credit Suisse in California Superior Court in Inyo
County. Mission Power claimed damages in excess of $79,000,000 and alleged
breach of contract, fraud and negligent misrepresentation. In December 1990,
the Coso Entities filed a cross- complaint against Mission Power and The
Mission Group alleging $97,000,000 plus punitive damages for breach of
contract, negligence, and misrepresentations. On June 10, 1993, the parties
announced they had reached a settlement of all outstanding disputes regarding
construction of the Coso Geothermal Project. Under the settlement, Coso
Partnerships made a net payment of $20,000,000 to Mission Power. This was less
than the amount of revenue Mission Power had previously recorded, resulting in
a one-time charge of $11,000,000 after tax for the second quarter.
Transphase Systems, Inc. filed a lawsuit on May 3, 1993, in the United
States District Court for the Central District of California against Edison and
San Diego Gas & Electric Company ("SDG&E"). The complaint alleged that
Transphase was competitively disadvantaged because it could not directly access
the demand side management funds Edison collects from its ratepayers to fund
conservation and demand side management activities and that the utilities
willfully acquired and maintain monopoly power in the energy conservation
industry. The complaint sought $50,000,000 in damages before trebling. Edison
filed a motion to dismiss the complaint on the grounds that it was without
merit. The court granted Edison's motion on October 7, 1993, and denied
plaintiffs the opportunity to replead the case. Plaintiffs have appealed to
the Ninth Circuit Court of Appeals.
ENVIRONMENTAL LITIGATION
On November 8, 1990, an environmental organization and two individuals
filed a lawsuit against Edison in United States Federal District Court for the
Southern District of California. The lawsuit alleges Edison's operation of San
Onofre Units 2 and 3 is in violation of its National Pollutant Discharge
Elimination System permits. The basis for the allegations was a report
prepared for the California Coastal Commission on the marine environmental
effects of the generating station. The plaintiffs requested that the Court
enjoin operation of Units 2 and 3, impose civil penalties, and order Edison to
repair the alleged damage to the marine environment. After mediation by the
court, the parties agreed on a settlement that includes: (i) $2,000,000 in
wetlands research which will be undertaken by the Pacific Estuarine Research
Laboratory at San Diego State University; (ii) $7,500,000 in additional wetland
restoration within the San Dieguito River Valley; (iii) a $5,500,000, 10 year,
Marine Education Program which will be based at Edison's Redondo Generating
Station; and (iv) $1,400,000 in attorney's fees. The court approved the
settlement on June 15, 1993.
22
25
On September 23, 1993, the California Department of Toxic Substances
Control ("DTSC") issued a Report of Violation to Edison, alleging various
hazardous waste violations of the California Health & Safety Code at several
Edison facilities. Edison is currently in settlement negotiations with DTSC
regarding these alleged violations and tentatively has reached an agreement in
principle for settlement in the amount of $1,900,000.
SAN ONOFRE PERSONAL INJURY LITIGATION
In 1993, a former NRC inspector who was assigned to San Onofre in 1985
and 1986 filed a lawsuit against Edison, SDG&E and a fuel rod manufacturer in
Los Angeles County Superior Court, Central District. The case was subsequently
transferred to the Federal District Court for the Southern District of
California. The inspector claimed that exposure to radioactive materials at
the plant caused her leukemia. Plant records showed that the inspector's
exposure to radiation was well below NRC regulatory levels. Plaintiff
nevertheless alleged that she was exposed to radioactive fuel particles, that
this caused a radiation exposure above the NRC levels and that this exposure
was a legal cause for her illness. Plaintiff sought compensatory and punitive
damages. The defendants denied having liability for plaintiff's illness.
A jury trial began on January 4, 1994. In closing arguments at the
end of the trial, plaintiff's counsel requested damages between $4,000,000 and
$4,500,000 for medical costs and economic losses and asked for three to five
times that amount for pain and suffering compensatory damages. After
deliberations, the jury reported that it was "hung" and could not reach a
unanimous verdict on the threshold question of whether plaintiff was exposed to
radiation levels above the NRC-defined levels. (A 7-2 majority of the jury had
concluded that plaintiffs exposure did exceed these levels). Finding itself
hung on the exposure question, the jury did not decide the other questions
regarding causation, the amount of compensatory damages and whether Edison's
conduct warranted punitive damages. If the jury had found that punitive
damages should be assessed, the trial would have resumed to decide the amount
of such damages.
On February 8, 1994, the trial judge declared a mistrial because of
the hung jury. The second trial was scheduled to begin on March 15, 1994. On
March 14, 1994, the case was settled. The amount of the settlement payment
will not have a material adverse effect on Edison's net income.
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:
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26
EXECUTIVE OFFICERS OF THE REGISTRANT (1)(2)
SCECORP
AGE AT
DECEMBER EFFECTIVE
EXECUTIVE OFFICER 31, 1993 COMPANY POSITION DATE
- ----------------- -------- ----------------- ---------------
John E. Bryson 50 Chairman of the Board, Chief Executive October 1, 1990
Officer and Director
Bryant C. Danner 56 Senior Vice President and General July 1, 1992
Counsel
Alan J. Fohrer 43 Senior Vice President, Treasurer and January 21, 1993
Chief Financial Officer
Richard K. Bushey 53 Vice President and Controller July 21, 1988
Kenneth S. Stewart 42 Assistant General Counsel November 19, 1992
and Corporate Secretary
- ---------------------
(1) The Executive Officers of SCEcorp include the Chairman of the Board
and Chief Executive Officer, the elected Vice Presidents and the
Secretary of SCEcorp and Edison as well as the Chief Executive
Officers and Presidents, Executive Vice Presidents and Senior Vice
Presidents of Mission Energy, Mission Financial, and Mission Land
(collectively "The Mission Companies") all of whom may be deemed
policy makers of SCEcorp.
(2) Effective March 1, 1993, Michael R. Peevey retired from his position
as President of SCEcorp.
None of SCEcorp's elected executive officers are related to each other
by blood or marriage. As set forth in Article IV of SCEcorp's Bylaws, the
elected officers of SCEcorp are chosen annually by and serve at the pleasure of
SCEcorp's Board of Directors and hold their respective offices until their
resignation, removal, other disqualification from service, or until their
respective successors are elected. Each of the elected executive officers of
SCEcorp holds an identical position with Edison except for Alan J. Fohrer, who
does not hold the Treasurer position at Edison and has been actively engaged in
the business of Edison for more than five years except for Bryant C. Danner.
Those officers who have not held their present position with SCEcorp and/or
Edison for the past five years had the following business experience during
that period:
John E. Bryson Executive Vice President and Chief May 1988 to
Financial Officer of SCEcorp September 1990
Executive Vice President and January 1985 to
Chief Financial Officer of Edison September 1990
Bryant C. Danner Partner with law firm of Latham & Watkins(1)(2) January 1970 to
June 1992
Alan J. Fohrer Vice President, Treasurer and Chief April 1991 to
Financial Officer of SCEcorp and Edison January 1993
Assistant Treasurer of SCEcorp July 1988 to
March 1991
Assistant Treasurer and Manager of Cost September 1987
Control of Edison to March 1991
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27
Kenneth S. Stewart Assistant General Counsel of Edison March 1992 to
and SCEcorp October 1992
Senior Counsel of Edison March 1989 to
February 1992
Attorney of Edison June 1987 to
February 1989
- ----------------
(1) Prior to leaving the law firm of Latham & Watkins, Bryant C. Danner
was in the firm's environmental department.
(2) This entity is not a parent, subsidiary or other affiliate of Edison.
EDISON
AGE AT
DECEMBER EFFECTIVE
EXECUTIVE OFFICER 31, 1993 COMPANY POSITION(1)(2) DATE
- ----------------- --------- ----------------------- ---------------
John E. Bryson 50 Chairman of the Board, Chief October 1, 1990
Executive Officer and Director
Bryant C. Danner 56 Senior Vice President and July 1, 1992
General Counsel
Alan J. Fohrer 43 Senior Vice President and June 17, 1993
Chief Financial Officer
Charles B. McCarthy, Jr. 53 Senior Vice President June 1, 1990
Harold B. Ray 53 Senior Vice President (Power Systems) June 1, 1990
R. H. Bridenbecker 50 Vice President (Customer Solutions) June 1, 1990
Vikram S. Budhraja 46 Vice President (Planning February 1, 1992
and Technology)
Richard K. Bushey 53 Vice President and Controller January 1, 1984
Ronald Daniels 54 Vice President (Regulatory Projects) August 10, 1992
John R. Fielder 48 Vice President (Regulatory Policy and February 1, 1992
Affairs)
Robert G. Foster 46 Vice President (Public Affairs) November 18, 1993
L. D. Hamlin 49 Vice President (Power Production) February 1, 1992
Margaret H. Jordan 50 Vice President (Health Care and December 7, 1992
and Employee Services)
Russell W. Krieger 45 Vice President (Nuclear Generation) June 17, 1993
J. Michael Mendez 52 Vice President (Regional Leadership) February 8, 1993
Georgia R. Nelson 43 Vice President (Performance Support) March 18, 1993
Lewis M. Phelps 50 Vice President (Corporate Communications) May 1, 1989
Richard M. Rosenblum 43 Vice President (Engineering and June 17, 1993
Technical Services)
C. Alex Miller 36 Treasurer June 17, 1993
Kenneth S. Stewart 42 Assistant General Counsel November 19, 1992
and Corporate Secretary
- ---------------
(1) Effective March 1, 1993, Michael R. Peevey retired from his position
as President of Edison, and Harry E. Morgan, Jr. retired from his
position as Vice President of Edison and Site Manager of San Onofre.
At December 31, 1993, Charles B. McCarthy, Jr. was Senior Vice
President of Edison; however, effective January 1, 1994, Mr. McCarthy
retired from this position.
(2) John E. Bryson, Bryant C. Danner, Richard K. Bushey and Kenneth S.
Stewart also hold the same positions with SCEcorp. Alan J. Fohrer
holds the office of Senior Vice President, Treasurer and Chief
Financial Officer of SCEcorp. SCEcorp is the parent holding company
of Edison.
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None of Edison's executive officers are related to each other by blood
or marriage. As set forth in Article IV of Edison's Bylaws, the officers of
Edison are chosen annually by and serve at the pleasure of Edison'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 Edison for more than five years except for Bryant C. Danner and
Margaret H. Jordan. Those officers who have not held their present position
for the past five years had the following business experience during that
period:
John E. Bryson Executive Vice President January 1985 to
and Chief Financial Officer September 1990
Bryant C. Danner Partner with Law Firm of January 1970 to
Latham & Watkins(1)(3) June 1992
Harold B. Ray Vice President -- Nuclear Engineering August 1989
Safety and Licensing to May 1990
Vice President -- Fuel Supply, January 1988
Procurement and Material Management to July 1989
R. H. Bridenbecker Vice President and Site Manager -- September 1989 to
San Onofre Nuclear Generating Station May 1990
Vice President (Customer Service) January 1988 to
August 1989
Vikram S. Budhraja Vice President -- System Planning April 1991 to
and Fuel Supply January 1992
Manager -- Electric System Planning September 1986 to
March 1991
Ronald Daniels Vice President -- Revenue Requirements August 1989 to
July 1992
Manager -- Revenue Requirements September 1975 to
July 1989
John R. Fielder Vice President -- Information Services January 1989 to
January 1992
Alan J. Fohrer Vice President, Treasurer and April 1991 to
Chief Financial Officer January 1993
Assistant Treasurer and Manager -- Cost Control September 1987 to
March 1991
L. D. Hamlin Manager -- Steam Generation April 1990 to
January 1992
Manager -- Research, System Planning September 1986
and Research Department to April 1990
Robert G. Foster Regional Vice President (Sacramento Office) January 1988 to
October 1993
Margaret H. Jordan Vice President -- Kaiser Foundation March 1986 to
Health Plan of Texas(2)(3) December 1992
Russell W. Krieger Station Manager (San Onofre) August 1990 to
May 1993
Station Operation Manager (San Onofre) August 1985 to
July 1990
26
29
J. Michael Mendez Vice President -- Human Resources August 1991 to
February 1993
Division Vice President -- Customer Service January 1991
to July 1991
Division Manager -- Customer Service September 1989
to January 1991
Manager -- Personnel and Employee September 1985 to
Relations September 1989
Georgia R. Nelson Special Assistant to the Chairman February 1992 to
March 1993
Manager -- Procurement and September 1989 to
Material Management January 1992
Manager -- Telecommunications November 1987 to
August 1989
Lewis M. Phelps Manager -- Corporate Communications July 1985 to
April 1989
Richard M. Rosenblum Manager of Nuclear Regulatory Affairs June 1989 to
May 1993
Manager of Nuclear Oversight September 1986 to
May 1989
C. Alex Miller Assistant Treasurer April 1991 to
May 1993
Manager of Financial Planning and September 1987 to
Regulatory Finance March 1991
Kenneth S. Stewart Assistant General Counsel March 1992 to
November 1992
Senior Counsel March 1989 to
February 1992
Attorney June 1987 to
February 1989
- ----------------
(1) Prior to leaving the law firm of Latham & Watkins, Bryant C. Danner
was in the firm's environmental department.
(2) As Vice President of the Kaiser Foundation Health Plan of Texas,
Margaret H. Jordan was responsible for serving over 124,000 members in
10 multispecialty medical offices in the Dallas/Fort Worth area.
(3) This entity is not a parent, subsidiary or other affiliate of Edison.
THE MISSION COMPANIES
AGE AT
DECEMBER EFFECTIVE
EXECUTIVE OFFICER 31, 1993 COMPANY POSITION(1) DATE
- ----------------- --------- -------------------- ---------------
Edward R. Muller 41 President and Chief Executive August 23, 1993
Officer -- Mission Energy
Robert M. Edgell 46 Executive Vice President -- Mission Energy April 1, 1988
Robert Dietch 55 Senior Vice President, Project February 1, 1992
Management/Operations -- Mission Energy
Alan M. Fenning 43 Senior Vice President and General April 1, 1988
Counsel -- Mission Energy
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30
James V. Iaco, Jr. 49 Senior Vice President and Chief January 24, 1994
Financial Officer -- Mission Energy
S. Daniel Melita 42 Senior Vice President -- Mission Energy November 1, 1993
Thomas R. McDaniel 44 President and Chief Executive January 1, 1988
Officer -- Mission First Financial
and Mission Land
Lawrence W. Yu 40 Executive Vice President October 15, 1993
-- Mission First Financial
Michael L. Noel 52 Executive Vice President -- Mission Land January 17, 1994
Charles W. Johnson 47 Executive Vice President -- Mission Land August 7, 1992
____________
(1) Effective August 1, 1993, James S. Pignatelli resigned from his
position as President and Chief Executive Officer of Mission Energy.
Alan J. Fohrer served as interim Vice Chairman and interim Chief
Executive Officer of Mission Energy prior to Edward R. Muller's
appointment as President and Chief Executive Officer. John A.
Moriarty served as Senior Vice President of Mission Land until April
15, 1993; Mr. Moriarty currently serves as Vice President of Mission
Land.
None of The Mission Companies' executive officers are related to each
other by blood or marriage. As set forth in Article IV of their respective
Bylaws, the officers of The Mission Companies are chosen annually by and serve
at the pleasure of the respective Boards 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 the respective Mission
Companies and/or SCEcorp and Edison for more than five years except for Edward
R. Muller, James V. Iaco, Jr., S. Daniel Melita and Charles W. Johnson. Those
officers who have not held their present position for the past five years had
the following business experience during that period:
Edward R. Muller Vice President, Chief Financial Officer, October 1992 to
General Counsel and Secretary, July 1993
Whittaker Corporation(1)(13)
Vice President, Chief Administrative March 1988 to
Officer, General Counsel and September 1992
Secretary, Whittaker Corporation(2)(13)
James V. Iaco, Jr. President, James V. Iaco & Associates(3)(4)(13) October 1993 to
January 1994
Independent Business Consultant(5)(13) October 1992 to
September 1993
Independent Business Consultant(6)(13) November 1991 to
September 1992
Senior Vice President, Chief Financial January 1990 to
Officer, Intermark, Inc.(7)(13) October 1991
Senior Vice President, Chief Financial September 1981 to
Officer and Treasurer, MAXXAM Inc.(8)(13) October 1990
Robert Dietch Vice President, Engineering, Planning January 1987 to
and Research of Edison January 1992
28
31
S. Daniel Melita Vice President, Mission Energy(9)(13) September 1992 to
October 1993
Vice President, International October 1989 to
Operations of EBASCO Constructors, August 1992
Inc., EBASCO Overseas Corporation(10)(13)
Michael L. Noel Senior Vice President and Chief February 1992 to
Financial Officer of Mission Energy December 1993
Senior Vice President of Edison April 1991 to
January 1992
Vice President, Treasurer and Chief October 1990 to
Financial Officer of SCEcorp and Edison March 1991
Vice President and Treasurer of SCEcorp July 1988 to
September 1990
Vice President and Treasurer of Edison July 1980 to
September 1990
Lawrence W. Yu Senior Vice President of Mission First Financial July 1991 to
September 1993
Vice President of Mission First Financial September 1987
to June 1991
Charles W. Johnson President, Glenfed Development Corp.(11)(13) September 1990 to
June 1992
Executive Vice President/Deputy August 1987 to
Subsidiary Group Administrator, Glenfed August 1990
Service Corporation(12)(13)
____________
(1) Edward R. Muller served as Chief Financial Officer and General Counsel
(the second most senior officer) of Whittaker Corporation, a company
during the period from 1992 to 1993 engaged in various aerospace
businesses.
(2) Edward R. Muller served as Chief Administrative Officer and General
Counsel (the third most senior officer) of Whittaker Corporation, a
company during the period from 1988 to 1992 engaged in various
aerospace, chemical and biotechnology businesses and which underwent
significant restructurings, including a leveraged recapitalization and
a tax-free spin off.
(3) James V. Iaco, Jr. was elected Senior Vice President and Chief
Financial Officer of Mission Energy Company effective January 24,
1994.
(4) As President of James V. Iaco & Associates, James V. Iaco, Jr.
provided consultant services specializing in mergers and acquisitions,
restructurings, financing crisis management and other management
services.
(5) As an independent business consultant, James V. Iaco, Jr. completed
the disposition of subsidiaries of Phoenix Distributors, Inc.
("Phoenix"). Phoenix was one of the largest independent industrial
gas and welding supply distributor in the United States. Mr. Iaco
acted as the Company's chief financial officer, completing the
refinancing and restructuring of the remaining operation of the
Company.
(6) James V. Iaco, Jr. served as an independent business consultant
primarily engaged as the chief operating officer of a major developer
of time-share resort properties at the request of the shareholders.
(7) As Senior Vice President, Chief Financial Officer, James V. Iaco, Jr.
developed debt reduction and restructuring plans.
29
32
(8) James V. Iaco, Jr. served as Senior Vice President, Chief Financial
Officer and Treasurer at MAXXAM, Inc., a Fortune 200 company engaged
in aluminum production, forest products operations and real estate
development.
(9) As Director International Business Development, S. Daniel Melita
planned and implemented international marketing and sales strategies
for all business units and was responsible for selecting team partners
and establishing joint venture companies.
(10) As Vice President, International Operations of EBASCO Constructors,
Inc./EBASCO Overseas Corporation, S. Daniel Melita was responsible for
all overseas activities including operations and business development,
consulting construction management and lump sum turn key construction.
(11) As President, Charles W. Johnson directed all real estate operations
and business combinations which included direct development, joint
ventures and syndications.
(12) As Executive Vice President, Charles W. Johnson directed all real
estate operations where Glenfed had made a direct equity investment.
This included August Financial Corporation, Glenfed Development
Corporation and Glenfed Properties.
(13) This entity is not a parent, subsidiary or other affiliate of SCEcorp.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Information responding to Item 5 is included in SCEcorp's Annual
Report to Shareholders for the year ended December 31, 1993, ("Annual Report")
under "Quarterly Financial Data" on page 38 and under "Shareholder Information"
on page 41, and is incorporated by reference pursuant to General Instruction
G(2). The number of Common Stock shareholders of record was 140,600 on March
4, 1994. Additional information concerning the market for SCEcorp's Common
Stock is set forth on the cover page hereof.
ITEM 6. SELECTED FINANCIAL DATA
Information responding to Item 6 is included in the Annual Report
under "Selected Financial and Operating Data: 1989-1993" on page 40, 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" on pages 21 through 29 and is
incorporated herein by reference pursuant 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 23 through 40 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.
30
33
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning executive officers of SCEcorp 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 SCEcorp's Annual Meeting to be held on April 21,
1994, under the heading, "Election of Directors of SCEcorp and Edison," and is
incorporated herein by reference pursuant to General Instruction G(3).
ITEM 11. EXECUTIVE COMPENSATION
Information responding to Item 11 is included in the Proxy Statement
under the heading "Election of Directors of SCEcorp and Edison," 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 "Election of Directors of SCEcorp and Edison," and "Stock
Ownership of Certain Shareholders" and is incorporated herein by reference
pursuant to General Instruction G(3).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information responding to Item 13 is included in the Proxy Statement
under the heading "Election of Directors of SCEcorp and Edison," 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 1993 Annual Report to
Shareholders are incorporated by reference in this report.
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Responsibility for Financial Reporting
Report of Independent Public Accountants
Consolidated Statements of Income -- Years Ended December 31,
1993, 1992 and 1991
Consolidated Balance Sheets -- December 31, 1993, and 1992
Consolidated Statements of Cash Flows -- Years Ended December
31, 1993, 1992 and 1991
Consolidated Statements of Retained Earnings -- Years Ended
December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
31
34
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Schedule III--Condensed Financial Information of Parent . . . . . . . . . . . . . . . . . . . . 34
Schedule V--Property, Plant and Equipment for the Years Ended
December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Schedule VI--Accumulated Depreciation and Amortization of
Property, Plant, and Equipment for the Years Ended
December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Schedule VII--Guarantees of Securities of Other Issuers for
the Year Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Schedule VIII--Valuation and Qualifying Accounts for the
Years Ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . 43
Schedule IX--Short-Term Borrowings For Each of the Three
Years in the Period Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . . 46
Schedule X--Supplementary Income Statement Information For
for Each of the Three Years in the Period
Ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Schedule XIII--Other Investments, December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . 48
Schedules I through XIII, inclusive, except those referred to above, are
omitted as not required or not applicable.
(3) EXHIBITS
See Exhibit Index on page 50 of this report.
(B) REPORTS ON FORM 8-K
October 12, 1993
Item 5: Other Events: Termination of Mission Energy Company
Project in Mexico
October 27, 1993
Item 5: Other Events: Earnings Report
Item 7: Financial Statements: Pro Forma Financial Information
and Exhibits
32
35
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To SCEcorp:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in the 1993 Annual
Report to Shareholders of SCEcorp, incorporated by reference in this Form 10-K,
and have issued our report thereon dated February 4, 1994. 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 SCEcorp'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 & CO.
ARTHUR ANDERSEN & CO.
Los Angeles, California
February 4, 1994
33
36
SCECORP
SCHEDULE III -- CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
December 31,
---------------------------
1993 1992
---------- ----------
(IN THOUSANDS)
ASSETS:
Cash and equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,004 $ 11,353
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . 143,607 158,640
---------- ----------
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . 149,611 169,993
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . 5,927,922 5,943,771
Accumulated deferred income taxes -- net . . . . . . . . . . . . . . . . . 46,768 1,030
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258 552
---------- ----------
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,124,559 $6,115,346
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,630 $ 3,353
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . 162,348 158,256
---------- ----------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . 166,978 161,609
Common shareholders' equity . . . . . . . . . . . . . . . . . . . . . . . 5,957,581 5,953,737
---------- ----------
Total liabilities and shareholders' equity . . . . . . . . . . . . . . $6,124,559 $6,115,346
========== ==========
CONDENSED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
1993 1992 1991
---------- -------- --------
(IN THOUSANDS, EXCEPT PER-SHARE AMOUNTS)
Operating revenue and interest income . . . . . . . . . . . . . . $ 18,914 $13,974 $ 8,662
Operating expenses and income taxes . . . . . . . . . . . . . . . 20,231 14,611 9,454
---------- -------- --------
Loss before equity in earnings of subsidiaries . . . . . . . . (1,317) (637) (792)
Equity in earnings of subsidiaries . . . . . . . . . . . . . . . 640,364 739,357 703,397
---------- -------- --------
Net income . . . . . . . . . . . . . . . . . . . . . . . . $ 639,047 $738,720 $702,605
========== ======== ========
Weighted-average shares of common stock outstanding . . . . . . . 447,754 445,489 437,321
Earnings per share . . . . . . . . . . . . . . . . . . . . . . . $ 1.43 $ 1.66 $ 1.61
========== ======== ========
Note: Per-share figures reflect the two-for-one split of
SCEcorp common stock effective June 1, 1993.
34
37
SCECORP
SCHEDULE III--CONDENSED FINANCIAL INFORMATION OF PARENT (CONTINUED)
CONDENSED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
1993 1992 1991
-------- -------- --------
(IN THOUSANDS)
Cash Flows From Operating Activities . . . . . . . . . . . . . . $(46,143) $ 1,404 $ (71)
-------- -------- --------
Cash Flows From Financing Activities:
Capital contributions . . . . . . . . . . . . . . . . . . . . 41,250 (64,020) 69,505
-------- -------- --------
Cash Flows From Investing Activities . . . . . . . . . . . . . . (456) 3,380 --
-------- -------- --------
Increase (Decrease) in cash and equivalents . . . . . . . . . . . (5,349) (59,236) 69,434
Cash and equivalents at beginning of period . . . . . . . . . . . 11,353 70,589 1,155
-------- -------- --------
Cash and Equivalents at the End of Period . . . . . . . . . . $ 6,004 $ 11,353 $ 70,589
======== ======== ========
Cash dividends received from Southern California
Edison Company . . . . . . . . . . . . . . . . . . . . . . . . $631,325 $613,816 $588,513
======== ======== ========
35
38
SCECORP
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
ADD (DEDUCT)
BALANCE AT --------------------------------------- BALANCE
BEGINNING OF ADDITIONS OTHER AT END OF
DESCRIPTION PERIOD AT COST RETIREMENTS CHANGES PERIOD
----------- ------------ --------- ----------- ------- -----------
(IN THOUSANDS)
Steam production . . . . . . . $2,151,082 $130,586 $ (33,221) $ 4,687 $ 2,253,134
Nuclear production . . . . . . 5,380,457 61,597 (2,958) -- 5,439,096
Hydro production . . . . . . . 571,859 11,864 (453) -- 583,270
Other production . . . . . . . 396,095 19,391 (11,432) 391 404,445
Transmission . . . . . . . . . 2,568,391 86,972 (12,499) 467 2,643,331
Distribution . . . . . . . . . 5,608,233 342,022 (51,641) 11,980 5,910,594
General . . . . . . . . . . . . 1,072,671 121,986 (14,960) 177 1,179,874
Plant held for future use . . . 16,043 (14,393) (9) -- 1,641
Experimental electric plant
unclassified . . . . . . . . 31,381 4,818 (6,221) (17,946) 12,032
Other utility plant . . . . . . 8,419 343 (45) -- 8,717
----------- -------- ---------- -------- -----------
Subtotal--utility plant . . 17,804,631 765,186 (133,439) (244) 18,436,134
Construction work in
progress . . . . . . . . . . 723,765 124,321(a) 9,139 -- 857,225
Nuclear fuel . . . . . . . . . 776,262 86,225 (129,442) 26(b) 733,071
----------- -------- ---------- -------- -----------
Gross utility plant . . . . $19,304,658 $975,732 $ (253,742) $ (218) $20,026,430
=========== ======== ========== ======== ===========
Nonutility property . . . . . . $ 1,074,009 $320,326 $ (176,586) $131,891 $ 1,349,640
=========== ======== =========== ======== ===========
_______________
(a) Reflects transfers to plant in service, which are net of additions to
construction work in progress.
(b) Reflects prior-year adjustments.
36
39
SCECORP
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
ADD (DEDUCT)
BALANCE AT ------------------------------------ BALANCE
BEGINNING OF ADDITIONS OTHER AT END OF
DESCRIPTION PERIOD AT COST RETIREMENTS CHANGES PERIOD
----------- ------------ --------- ----------- ------- ---------
(IN THOUSANDS)
Steam production . . . . . . . . $ 2,054,404 $ 96,120 $ (15,578) $ 16,136 $ 2,151,082
Nuclear production . . . . . . . 5,915,872 70,661 (606,076)(b) -- 5,380,457
Hydro production . . . . . . . . 569,322 3,519 (982) -- 571,859
Other production . . . . . . . . 394,635 5,595 (4,135) -- 396,095
Transmission . . . . . . . . . . 2,468,478 106,779 (7,491) 625 2,568,391
Distribution . . . . . . . . . . 5,291,905 376,130 (59,909) 107 5,608,233
General . . . . . . . . . . . . . 993,991 125,687 (48,290) 1,283 1,072,671
Plant held for future use . . . . 17,629 132 (61) (1,657) 16,043
Experimental electric plant
unclassified . . . . . . . . . 58,145 263 (5,839) (21,188) 31,381
Other utility plant . . . . . . . 7,692 713 (150) 164 8,419
----------- -------- --------- -------- -----------
Subtotal--utility plant . . . 17,772,073 785,599 (748,511) (4,530) 17,804,631
Construction work in
progress . . . . . . . . . . . 794,303 (60,531)(a) 9,054 (19,061) 723,765
Nuclear fuel . . . . . . . . . . 973,554 20,356 (182,978) (34,670)(b) 776,262
----------- -------- --------- -------- -----------
Gross utility plant . . . . . $19,539,930 $745,424 $(922,435) $(58,261) $19,304,658
=========== ======== ========= ======== ===========
Nonutility property . . . . . . . $ 446,723 $ 22,689 $ (10,327) $614,924 $ 1,074,009
=========== ======== ========= ======== ===========
_______________
(a) Reflects transfers to plant in service, which are net of additions to
construction work in progress.
(b) Reflects removal from service of nuclear generating plant under an
agreement reached with the California Public Utilities Commission.
37
40
SCECORP
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
ADD (DEDUCT)
BALANCE AT ------------------------------------ BALANCE
BEGINNING OF ADDITIONS OTHER AT END OF
DESCRIPTION PERIOD AT COST RETIREMENTS CHANGES PERIOD
----------- ------------ --------- ----------- ------- ---------
(IN THOUSANDS)
Steam production . . . . . . . . $ 1,960,914 $ 98,818 $ (5,328) $ -- $ 2,054,404
Nuclear production . . . . . . . 5,789,475 129,931 (3,534) -- 5,915,872
Hydro production . . . . . . . . 556,197 13,555 (373) (57) 569,322
Other production . . . . . . . . 395,963 5,039 (6,367) -- 394,635
Transmission . . . . . . . . . . 2,405,526 74,072 (11,120) -- 2,468,478
Distribution . . . . . . . . . . 4,961,068 393,032 (61,807) (388) 5,291,905
General . . . . . . . . . . . . . 920,813 97,158 (21,714) (2,266) 993,991
Plant held for future use . . . . 17,110 152 (21) 388 17,629
Experimental electric plant
unclassified . . . . . . . . . 30,314 27,831 -- -- 58,145
Other utility plant . . . . . . . 7,224 506 (38) -- 7,692
----------- -------- --------- ------- -----------
Subtotal--utility plant . . . 17,044,604 840,094 (110,302) (2,323) 17,772,073
Construction work in
progress . . . . . . . . . . . 741,040 39,471(a) 13,792 -- 794,303
Nuclear fuel . . . . . . . . . . 1,020,897 83,674 (131,017) -- 973,554
----------- -------- --------- ------- -----------
Gross utility plant . . . . . $18,806,541 $963,239 $(227,527) $(2,323) $19,539,930
=========== ======== ========= ======= ===========
Nonutility property . . . . . . . $ 418,658 $ 66,535 $ (51,136) $12,666 $ 446,723
=========== ======== ========= ======= ===========
____________
(a) Reflects transfers to plant in service, which are net of additions to
construction work in progress.
(b) Restated to include consolidated statements from affiliates.
38
41
SCECORP
SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1993
ADDITIONS
CHARGED ADD (DEDUCT)
BALANCE AT TO COSTS ------------------------------------- BALANCE
BEGINNING OF AND OTHER AT END OF
DESCRIPTION PERIOD EXPENSES RETIREMENTS CHARGES(A) SALVAGE PERIOD
----------- ------------ -------- ----------- ---------- ------- ---------
(IN THOUSANDS)
Steam production . . . . $1,376,609 $109,929 $(21,637) $ (15,890) $3,279 $1,452,290
Nuclear production . . . 1,835,951 315,683 (2,757) (60,047) 108 2,088,938
Hydro production . . . . 153,594 11,297 (445) (302) - 164,144
Other production . . . . 229,998 12,737 (6,080) (3,288) 319 233,686
Transmission . . . . . . 843,228 60,655 (11,483) (3,262) 2,631 891,769
Distribution . . . . . . 1,833,654 213,309 (51,555) (27,201) 6,095 1,974,302
General . . . . . . . . . 268,189 59,402 (14,542) 2,145 192 315,386
Experimental electric
plant unclassified . . 19,590 7,600 (3,165) (6,935) -- 17,090
Retirement work in
progress . . . . . . . (22,514) -- 7,538 5,058 956 (8,962)
Other utility plant
reserves . . . . . . . 5,387 4,274 (14) (1) -- 9,646
---------- -------- -------- --------- ------ ----------
Subtotal . . . . . . . 6,543,686 794,886 (104,140) (109,723) 13,580 7,138,289
Nuclear fuel
amortization . . . . . 652,653 61,848 (129,442) -- -- 585,059
---------- -------- -------- --------- ------ ----------
Total utility plant
reserves . . . . . $7,196,339 $856,734 $(233,582) $(109,723) $13,580 $7,723,348
========== ======== ======== ========= ======= ==========
Nonutility property
reserves . . . . . . . $ 50,478 $ 28,993 $ (9,252) $ 2,950 $ -- $ 73,169
========== ======== ======== ========= ======= ==========
____________
(a) Includes removal costs related to facilities retired, damage claims
and relocation costs collected from others, and various other
adjustments of depreciation and amortization.
39
42
SCECORP
SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1992
ADDITIONS
CHARGED ADD (DEDUCT
BALANCE AT TO COSTS ------------------------------------ BALANCE
BEGINNING OF AND OTHER AT END OF
DESCRIPTION PERIOD EXPENSES RETIREMENTS CHARGES(A) SALVAGE PERIOD
----------- ------------ --------- ----------- ---------- ------- ----------
(In thousands)
Steam production . . . . $1,301,013 $ 99,652 $ (15,798) $ (8,588) $ 330 $1,376,609
Nuclear production . . . 1,926,088 319,875 (777,264)(b) 367,166 86 1,835,951
Hydro production . . . . 143,797 11,223 (982) (444) -- 153,594
Other production . . . . 228,740 11,116 (4,090) (6,068) 300 229,998
Transmission . . . . . . 790,677 58,443 (7,017) (476) 1,601 843,228
Distribution . . . . . . 1,712,575 201,666 (59,792) (28,757) 7,962 1,833,654
General . . . . . . . . . 254,535 56,665 (48,309) 4,981 317 268,189
Experimental electric
plant unclassified . . 19,275 6,212 (5,839) (58) -- 19,590
Retirement work in . . .
progress . . . . . . . (40,590) -- 4,785 9,462 3,829 (22,514)
Other utility plant
reserves . . . . . . . 3,038 2,425 (76) -- -- 5,387
---------- --------- --------- -------- ------- ----------
Subtotal . . . . . . . 6,339,148 767,277 (914,382) 337,218 14,425 6,543,686
Nuclear fuel
amortization . . . . . 726,327 109,266 (182,978) 38 -- 652,653
---------- --------- --------- -------- ------- ----------
Total utility plant
reserves . . . . . $7,065,475 $876,543 $(1,097,360) $337,256 $14,425 $7,196,339
========== ========= ========= ======== ======= ==========
Nonutility property
reserves . . . . . . . $ 43,994 $ 11,402 $ (1,947) $ (2,971) $ -- $ 50,478
========== ========= ========= ======== ======= ==========
____________
(a) Includes removal costs related to facilities retired, damage claims
and relocation costs collected from others, and various other
adjustments of depreciation and amortization.
(b) Reflects removal from service of nuclear generating plant under an
agreement reached with the California Public Utilities Commission.
40
43
SCECORP
SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
FOR THE YEAR ENDED DECEMBER 31, 1991
ADDITIONS
CHARGED ADD (DEDUCT)
BALANCE AT TO COSTS ----------------------------------- BALANCE
BEGINNING OF AND OTHER AT END OF
DESCRIPTION PERIOD EXPENSES RETIREMENTS CHARGES(A) SALVAGE PERIOD
----------- ------------ -------- ----------- ---------- ------- ----------
(IN THOUSANDS)
Steam production . . . . $1,217,709 $ 88,644 $(5,112) $ (778) $ 550 $1,301,013
Nuclear production . . . 1,607,984 324,610 (3,508) (3,050) 52 1,926,088
Hydro production . . . . 135,630 8,754 (387) (240) 40 143,797
Other production . . . . 222,660 12,554 (6,365) (109) -- 228,740
Transmission . . . . . . 724,070 76,608 (10,686) (2,606) 3,291 790,677
Distribution . . . . . . 1,601,611 190,922 (61,709) (27,789) 9,540 1,712,575
General . . . . . . . . . 219,110 51,831 (21,809) 4,981 422 254,535
Experimental electric
plant unclassified . . 11,003 8,272 -- -- -- 19,275
Retirement work in . . .
progress . . . . . . . (46,557) -- 14,426 (8,239) (220) (40,590)
Other utility plant
reserves . . . . . . . 2,863 213 (39) 1 -- 3,038
---------- -------- ------- ------- ------- ----------
Subtotal . . . . . . . 5,696,083 762,408 (95,189) (37,829) 13,675 6,339,148
Nuclear fuel
amortization . . . . . 725,989 131,355 (131,017) -- -- 726,327
---------- -------- ------- ------- ------- ----------
Total utility plant
reserves . . . . . $6,422,072 $893,763 $(226,206) $(37,829) $13,675 $7,065,475
========== ======== ======= ======= ======= ==========
Nonutility property
reserves(b) . . . . . $ 39,992 $ 8,493 $ (2,653) $ (1,838) $ -- $ 43,994
========== ======== ======= ======= ======= ==========
____________
(a) Includes removal costs related to facilities retired, damage claims
and relocation costs collected from others, and various other
adjustments of depreciation and amortization.
(b) Restated to include consolidated statements from affiliates.
41
44
SCECORP
SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS
FOR THE YEAR ENDED DECEMBER 31, 1993
(IN THOUSANDS)
Amount in Nature of any default
Name of Issuer Title of issue Amount treasury of guaranteed in principal
of securities of each class Total amount owned issuer of interest, sinking fund
guarantee by of securities guaranteed and by the securities Nature of redemption provisions,
SCEcorp guaranteed outstanding Company guaranteed guarantee or payment of dividneds
- ------------- -------------- -------------- ------- ----------- ---------- -----------------------
Ontario Lakeshore Construction Principal
Partners Loan $15,000 --- --- and Interest None
Centrelake Construction Principal
Partners Loan $5,000 --- --- and Interest None
Carol Stream Acquisition
Developers and Development Principal
Loan $7,935 --- --- and Interest None
42
45
SCECORP
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1993
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 . . . . . . . . . . . $ 8,970 $ 38,314 $ 481 $ 31,374 $ 16,391
All other . . . . . . . . . . . 32,572 12,772 (481) 3,321 41,542
-------- -------- ------- -------- --------
Total . . . . . . . . . . . $ 41,542 $ 51,086 $ -- $ 34,695(a) $ 57,933
======== ======== ======= ======== ========
Group B:
Regulatory settlement . . . . . . $113,380 $ 10,620 $ -- $124,000(b) $ --
DOE Decontamination
and Decommissioning . . . . . . 53,136 -- 19,156(c) 5,164(d) 67,128
Pension and benefits . . . . . . . 111,139 48,692 22,064(e) 50,131(f) 131,764
Insurance, casualty and
other . . . . . . . . . . . . . 64,019 51,843 -- 48,159(g) 67,703
-------- -------- ------- -------- --------
Total . . . . . . . . . . . $341,674 $111,155 $41,220 $227,454 $266,595
======== ======== ======= ======== ========
________________
(a) Accounts written off, net.
(b) Represents final settlement with the California Public Utilities
Commission's Division of Ratepayer Advocates regarding affiliated
company power purchases.
(c) Represents new estimate based on actual billings.
(d) Represents amounts paid.
(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.
43
46
SCECORP
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1992
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 . . . . . . . . . . $ 10,028 $ 23,041 $ --- $ 24,099 $ 8,970
All other . . . . . . . . . . 11,934 25,846 --- 5,208 32,572(a)
--------- ---------- -------- --------- ----------
Total . . . . . . . . . . . $ 21,962 $ 48,887 $ --- $ 29,307(b) $ 41,542
========= ========== ======== ========= ==========
Group B:
Regulatory settlement . . . . . $ 124,000 $ --- 9,320(c) 19,940(d) $ 113,380
DOE decontamination
and decommissioning . . . . . --- --- 53,136(e) --- 53,136
Environmental cleanup . . . . . 40,000 --- 5,000(e) 45,000(f) ---
Pension and benefits . . . . . . 112,007 30,905 20,562(g) 52,335(h) 111,139
Insurance, casualty and
other . . . . . . . . . . . . 70,513 71,040 --- 77,534(i) 64,019
--------- ---------- -------- --------- ----------
Total . . . . . . . . . . . $ 346,520 $ 101,945 $ 88,018 $ 194,809 $ 341,674
========= ========== ======== ========= ==========
____________
(a) Includes reserve for net realizable value write-down.
(b) Accounts written off, net.
(c) Represents reserve addition for the settlement with the California
Public Utilities Commission's Division of Ratepayer Advocates
regarding affiliated company power purchases.
(d) Represents the amortization of the difference between the nominal
value and the present value.
(e) Represents the estimated long-term costs to be incurred and recovered
through rates over 15 years; reclassified from account 253.
(f) Represents an additional estimated liability established for
environmental cleanup costs expected to be incurred and recovered
through rates in future years.
(g) Amount reclassified to Account 253, other deferred credits.
(h) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(i) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(j) Amounts charged to operations that were not covered by insurance.
44
47
SCECORP
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEAR ENDED DECEMBER 31, 1991
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 . . . . . . . . . . $ 10,423 $ 22,533 $ --- $ 22,928 $ 10,028
All other . . . . . . . . . . 7,814 9,358 --- 5,238 11,934(a)
--------- --------- -------- -------- ---------
Total . . . . . . . . . . . $ 18,237 $ 31,891 $ --- $ 28,166(b) $ 21,962
========= ========= ======== ======== =========
Group B:
Regulatory settlement . . . . . $ --- 124,000(c) $ --- $ --- $ 124,000
Environmental cleanup . . . . . --- --- 40,000(d) --- 40,000
Pension and benefits . . . . . . 98,886 29,267 18,749(e) 34,895(f) 112,007
Insurance, casualty and
other . . . . . . . . . . . . 61,620 63,901 --- 55,008(g) 70,513
--------- --------- -------- -------- ---------
Total . . . . . . . . . . . $ 160,506 $ 217,168 $ 58,749 $ 89,903 $ 346,520
========= ========= ======== ======== =========
____________
(a) Includes reserve for net realizable value write-down.
(b) Accounts written off, net.
(c) Represents reserve addition for a proposed settlement with the
California Public Utilities Commission's Division of Ratepayer
Advocates regarding affiliated company power purchases.
(d) Represents an estimated minimum liability established for
environmental cleanup costs expected to be incurred and recovered
through rates in future years.
(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.
45
48
SCECORP
SCHEDULE IX -- SHORT-TERM BORROWINGS
FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 1993
WEIGHTED
MAXIMUM AVERAGE AVERAGE
WEIGHTED AMOUNT AMOUNT INTEREST
BALANCE AVERAGE OUTSTANDING OUTSTANDING RATE
AT END INTEREST DURING DURING DURING
DESCRIPTION OF PERIOD RATE THE PERIOD THE PERIOD THE PERIOD
----------- --------- -------- ----------- ----------- ----------
(A) (B)
(DOLLARS IN THOUSANDS)
C>
DECEMBER 31, 1993:
Payable to holders of commercial
paper--general purpose . . . . . $ 252,000 3.47% $ 420,800 $201,800 3.36%
Payable to holders of commercial
paper--balancing accounts . . . . 163,500 3.47 246,900 119,823 3.36
Payable to holders of commercial
paper--fuel . . . . . . . . . . . 269,600(c) 3.47 269,600 225,037 3.36
Payable to holders of commercial
paper--leveraged leases . . . . . 181,600(c) 3.40 181,600 181,600 6.92
Payable to bank--general
purpose . . . . . . . . . . . . . 22,250 10.37 209,781 120,321 7.91
Payable to unconsolidated
subsidiary--fuel . . . . . . . . --- --- 31,000 28,367 3.90
DECEMBER 31, 1992:
Payable to holders of commercial
paper--general purpose . . . . . $ 197,700 3.65% $ 350,400 $ 87,000 4.03%
Payable to holders of commercial
paper--balancing accounts . . . . 246,900 3.65 455,700 361,000 4.03
Payable to holders of commercial
paper--fuel . . . . . . . . . . . 228,300(c) 3.65 400,100 318,000 4.03
Payable to bank--leveraged leases . 181,600(c) 3.77 181,600 162,840 7.09
Payable to bank--general
purpose . . . . . . . . . . . . . 119,460 7.34 534,714 182,337 7.06
Payable to unconsolidated
subsidiary--fuel . . . . . . . . 31,000 3.97 31,000 24,757 4.43
DECEMBER 31, 1991:
Payable to holders of commercial
paper--general purpose . . . . . --- --- $ 461,900 $149,633 6.39%
Payable to holders of commercial
paper--balancing accounts . . . . $ 419,600 5.14% 506,700 476,000 6.36
Payable to holders of commercial
paper--fuel . . . . . . . . . . . 372,200(c) 5.14 436,100 397,000 6.36
Payable to holders of commercial
paper--leveraged leases . . . . . 181,600(c) 4.95 186,600 94,133 7.78
Payable to bank--general
purpose . . . . . . . . . . . . . 142,310 5.58 214,785 85,614 7.28
Payable to others--fuel . . . . . . 16,000 5.57 16,000 3,995 6.10
_____________
(a) Average amount outstanding during the period is computed by dividing
the total of daily outstanding principal balances by 365.
(b) Weighted-average interest rate during the period is computed by
dividing the total interest expense by the average amount outstanding.
(c) Under credit agreements with commercial banks which allow SCEcorp to
refinance short-term borrowings on a long-term basis, borrowings of
$252,000,000 as of December 31, 1993, $245,000,000 as of December 31,
1992, and $333,000,000 as of December 31, 1991, have been reclassified
as long-term debt on the Consolidated Balance Sheet in the 1993 Annual
Report.
46
49
SCECORP
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR EACH OF THE THREE YEARS IN THE PERIOD ENDED DECEMBER 31, 1993
CHARGED
TO
EXPENSE
-------
(IN THOUSANDS)
Year ended December 31, 1993:
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $159,661
Year ended December 31, 1992:
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155,792
Year ended December 31, 1991:
Property taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151,869
____________
Note: Depreciation and maintenance expenses appear on the Consolidated
Statements of Income. Royalties paid and advertising costs included
in Other Operating Expenses are less than 1% of total operating
revenue.
47
50
SCECORP
SCHEDULE XIII -- OTHER INVESTMENTS
DECEMBER 31, 1993
(IN THOUSANDS)
NUMBER OF SHARES AMOUNT AT WHICH
OR PRINCIPAL MARKET CARRIED IN BALANCE
DESCRIPTION AMOUNT COST VALUE SHEET
----------- ---------------- ---- ------- ------------------
INVESTMENTS IN NUCLEAR
DECOMMISSIONING TRUSTS:
Qualified trust . . . . . . . . . -- $ 681,687 $ 732,314 $ 681,687
Non-qualified trust . . . . . . . -- 106,888 121,028 106,888
---------- ---------- ----------
$ 788,575 $ 853,342 $ 788,575
========== ========== ==========
INVESTMENTS IN PARTNERSHIPS AND
UNCONSOLIDATED SUBSIDIARIES:
Energy partnerships . . . . . . . -- $ 687,504 $ 669,346 $ 664,407
Real estate partnerships . . . . . -- 260,073 260,073 218,543
Unconsolidated subsidiary . . . . -- 328,747 279,508 279,502
---------- ---------- ----------
$1,276,324 $1,208,927 $1,162,452
========== ========== ==========
INVESTMENTS IN LEVERAGED LEASES(A) . . . -- $ 354,449 $ 354,449 $ 497,469
========== ========== ==========
OTHER INVESTMENTS . . . . . . . . . . . . -- $ 20,577 $ 20,577 $ 20,577
========== ========== ==========
____________
(a) Market value is assumed to equal current unrecovered investment less
deferred taxes.
48
51
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.
SCEcorp
By W. J. Scilacci
--------------------------------
(W. J. Scilacci,
Assistant Treasurer)
Date: March 17, 1994
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 17, 1994
Chief Executive Officer
and Director
Principal Financial Officer:
Alan J. Fohrer* Senior Vice President,
Treasurer and Chief March 17, 1994
Financial Officer
Controller or Principal
Accounting Officer:
Richard K. Bushey* Vice President and March 17, 1994
Controller
Majority of Board of Directors:
Howard P. Allen* Director March 17, 1994
Norman Barker, Jr.* Director March 17, 1994
Walter B. Gerken* Director March 17, 1994
Joan C. Hanley* Director March 17, 1994
Carl F. Huntsinger* Director March 17, 1994
Luis G. Nogales* Director March 17, 1994
J. J. Pinola* Director March 17, 1994
Henry T. Segerstrom* Director March 17, 1994
E. L. Shannon, Jr.* Director March 17, 1994
Daniel M. Tellep* Director March 17, 1994
James D. Watkins* Director March 17, 1994
Edward Zapanta* Director March 17, 1994
By W. J. Scilacci
---------------------------------------
(W. J. Scilacci, Attorney-in-Fact)
49
52
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 Restated Articles of Incorporation as amended through
April 25, 1988 (Registration No. 33-19541)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.2 Certificate of Amendment of Restated Articles of Incorporation of
SCEcorp (Registration No 33-37381)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.3 Bylaws as adopted by the Board of Directors on November 18, 1993 . . . . . . . . . . . . . . . . . . . . .
4.1 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 Second Supplemental Indenture, dated as of April 25, 1935 (Registration No. 2-1472)* . . . . . . . . . . .
4.4 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)* . . . . . . . . . . . .
4.5 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No. 2-4522)* . . . . . . . . .
4.6 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No. 2-4522)* . . . . . . . . . . .
4.7 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No. 2-4522)* . . . . . . . . . .
4.8 Seventh Supplemental Indenture, dated as of January 15, 1948 (Registration No. 2-7369)* . . . . . . . . .
4.9 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No. 2-7610)* . . . . . . . . . .
4.10 Ninth Supplemental Indenture, dated as of February 15, 1951 (Registration No. 2-8781)* . . . . . . . . . .
4.11 Tenth Supplemental Indenture, dated as of August 15, 1951 (Registration No. 2-7968)* . . . . . . . . . . .
4.12 Eleventh Supplemental Indenture, dated as of August 15, 1953 (Registration No. 2-10396)* . . . . . . . . .
4.13 Twelfth Supplemental Indenture, dated as of August 15, 1954 (Registration No. 2-11049)* . . . . . . . . .
4.14 Thirteenth Supplemental Indenture, dated as of April 15, 1956 (Registration No. 2-12341)*. . . . . . . . .
4.15 Fourteenth Supplemental Indenture, dated as of February 15, 1957 (Registration No. 2-13030)* . . . . . . .
4.16 Fifteenth Supplemental Indenture, dated as of July 1, 1957 (Registration No. 2-13418)* . . . . . . . . . .
4.17 Sixteenth Supplemental Indenture, dated as of August 15, 1957 (Registration No. 2-13516)* . . . . . . . .
4.18 Seventeenth Supplemental Indenture, dated as of August 15, 1958 (Registration No. 2-14285)* . . . . . . .
4.19 Eighteenth Supplemental Indenture, dated as of January 15, 1960 (Registration No. 2-15906)* . . . . . . .
4.20 Nineteenth Supplemental Indenture, dated as of August 15, 1960 (Registration No. 2-16820)* . . . . . . . .
4.21 Twentieth Supplemental Indenture, dated as of April 1, 1961 (Registration No. 2-17668)* . . . . . . . . .
4.22 Twenty-First Supplemental Indenture, dated as of May 1, 1962 (Registration No. 2-20221)* . . . . . . . . .
4.23 Twenty-Second Supplemental Indenture, dated as of October 15, 1962 (Registration No. 2-20791)* . . . . . .
4.24 Twenty-Third Supplemental Indenture, dated as of May 15, 1963 (Registration No. 2-21346)* . . . . . . . .
50
53
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
4.25 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)* . . . . . .
4.26 Twenty-Fifth Supplemental Indenture, dated as of February 1, 1965 (Registration No. 2-23082)* . . . . . . .
4.27 Twenty-Sixth Supplemental Indenture, dated as of May 1, 1966 (Registration No. 2-24835)* . . . . . . . . .
4.28 Twenty-Seventh Supplemental Indenture, dated as of August 15, 1966 (Registration No. 2-25314)*. . . . . . .
4.29 Twenty-Eighth Supplemental Indenture, dated as of May 1, 1967 (Registration No. 2-26323)* . . . . . . . . .
4.30 Twenty-Ninth Supplemental Indenture, dated as of February 1, 1968 (Registration No. 2-28000)* . . . . . . .
4.31 Thirtieth Supplemental Indenture, dated as of January 15, 1969 (Registration No. 2-31044)* . . . . . . . .
4.32 Thirty-First Supplemental Indenture, dated as of October 1, 1969 (Registration No. 2-34839)* . . . . . . .
4.33 Thirty-Second Supplemental Indenture, dated as of December 1, 1970 (Registration No. 2-38713)* . . . . . .
4.34 Thirty-Third Supplemental Indenture, dated as of September 15, 1971 (Registration No. 2-41527)* . . . . . .
4.35 Thirty-Fourth Supplemental Indenture, dated as of August 15, 1972 (Registration No. 2-45046)* . . . . . . .
4.36 Thirty-Fifth Supplemental Indenture, dated as of February 1, 1974 (Registration No. 2-50039)* . . . . . . .
4.37 Thirty-Sixth Supplemental Indenture, dated as of July 1, 1974 (Registration No. 2-59199)* . . . . . . . . .
4.38 Thirty-Seventh Supplemental Indenture, dated as of November 1, 1974 (Registration No. 2-52160)* . . . . . .
4.39 Thirty-Eighth Supplemental Indenture, dated as of March 1, 1975 (Registration No. 2-52776)* . . . . . . . .
4.40 Thirty-Ninth Supplemental Indenture, dated as of March 15, 1976 (Registration No. 2-55463)* . . . . . . . .
4.41 Fortieth Supplemental Indenture, dated as of July 1, 1977 (Registration No. 2-59199)* . . . . . . . . . . .
4.42 Forty-First Supplemental Indenture, dated as of November 1, 1978 (Registration No. 2-62609)* . . . . . . .
4.43 Forty-Second Supplemental Indenture, dated as of June 15, 1979 (File No.1-2313)* . . . . . . . . . . . . .
4.44 Forty-Third Supplemental Indenture, dated as of September 15, 1979 (File No. 1-2313)* . . . . . . . . . . .
4.45 Forty-Fourth Supplemental Indenture, dated as of October 1, 1979 (Registration No. 2-65493)* . . . . . . .
4.46 Forty-Fifth Supplemental Indenture, dated as of April 1, 1980 (Registration No. 2-66896)* . . . . . . . . .
4.47 Forty-Sixth Supplemental Indenture, dated as of November 15, 1980 (Registration No. 2-69609)* . . . . . . .
4.48 Forty-Seventh Supplemental Indenture, dated as of May 15, 1981 (Registration No. 2-71948)* . . . . . . . .
4.49 Forty-Eighth Supplemental Indenture, dated as of August 1, 1981 (File No. 1-2313)* . . . . . . . . . . . .
51
54
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
4.50 Forty-Ninth Supplemental Indenture, dated as of December 1, 1981
(Registration No. 2-74339)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.51 Fiftieth Supplemental Indenture, dated as of January 16, 1982
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.52 Fifty-First Supplemental Indenture, dated as of April 15, 1982
(Registration No. 2-76626)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.53 Fifty-Second Supplemental Indenture, dated as of November 1, 1982
(Registration No. 2-79672)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.54 Fifty-Third Supplemental Indenture, dated as of November 1, 1982
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.55 Fifty-Fourth Supplemental Indenture, dated as of January 1, 1983
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.56 Fifty-Fifth Supplemental Indenture, dated as of May 1, 1983
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.57 Fifty-Sixth Supplemental Indenture, dated as of December 1, 1984
(Registration No. 2-94512)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.58 Fifty-Seventh Supplemental Indenture, dated as of March 15, 1985
(Registration No. 2-96181)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.59 Fifty-Eighth Supplemental Indenture, dated as of October 1, 1985
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.60 Fifty-Ninth Supplemental Indenture, dated as of October 15, 1985
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.61 Sixtieth Supplemental Indenture, dated as of March 1, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.62 Sixty-First Supplemental Indenture, dated as of March 15, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.63 Sixty-Second Supplemental Indenture, dated as of April 15, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.64 Sixty-Third Supplemental Indenture, dated as of April 15, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.65 Sixty-Fourth Supplemental Indenture, dated as of July 1, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.66 Sixty-Fifth Supplemental Indenture, dated as of September 1, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.67 Sixty-Sixth Supplemental Indenture, dated as of September 1, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.68 Sixty-Seventh Supplemental Indenture, dated as of December 1, 1986
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.69 Sixty-Eighth Supplemental Indenture, dated as of July 1, 1987
(Registration No. 33-19541)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.70 Sixty-Ninth Supplemental Indenture, dated as of October 15, 1987
(Registration No. 33-19541)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.71 Seventieth Supplemental Indenture, dated as of November 1, 1987
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.72 Seventy-First Supplemental Indenture, dated as of February 15, 1988
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.73 Seventy-Second Supplemental Indenture, dated as of April 15, 1988
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.74 Seventy-Third Supplemental Indenture, dated as of July 1, 1988
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
52
55
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
4.75 Seventy-Fourth Supplemental Indenture, dated as of August 15, 1988
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.76 Seventy-Fifth Supplemental Indenture, dated as of September 15, 1988
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.77 Seventy-Sixth Supplemental Indenture, dated as of January 15, 1989
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.78 Seventy-Seventh Supplemental Indenture, dated as of May 1, 1990
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.79 Seventy-Eighth Supplemental Indenture, dated as of June 15, 1990
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.80 Seventy-Ninth Supplemental Indenture, dated as of August 15, 1990
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.81 Eightieth Supplemental Indenture, dated as of December 1, 1990
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.82 Eighty-First Supplemental Indenture, dated as of April 1, 1991
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.83 Eighty-Second Supplemental Indenture, dated as of May 1, 1991
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.84 Eighty-Third Supplemental Indenture, dated as of June 1, 1991
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.85 Eighty-Fourth Supplemental Indenture, dated as of December 1, 1991
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.86 Eighty-Fifth Supplemental Indenture, dated as of February 1, 1992
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.87 Eighty-Sixth Supplemental Indenture, dated as of April 1, 1992
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.88 Eighty-Seventh Supplemental Indenture, dated as of July 1, 1992
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.89 Eighty-Eight Supplemental Indenture, dated as of July 15, 1992
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.90 Eighty-Ninth Supplemental Indenture, dated as of December 1, 1992
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.91 Ninetieth Supplemental Indenture, dated as of January 15, 1993
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.92 Ninety-First Supplemental Indenture, dated as of March 1, 1993
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.93 Ninety-Second Supplemental Indenture, dated as of June 1, 1993 . . . . . . . . . .
4.94 Ninety-Third Supplemental Indenture, dated as of June 15, 1993
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.95 Ninety-Fourth Supplemental Indenture, dated as of July 15, 1993 . . . . . . . . .
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.96 Ninety-Fifth Supplemental Indenture, dated as of September 1, 1993
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.97 Ninety-Sixth Supplemental Indenture, dated as of October 1, 1993
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.1 Executive Supplemental Benefit Program
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.2 1981 Deferred Compensation Agreement
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.3 1985 Deferred Compensation Agreement for Executives
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.4 1985 Deferred Compensation Agreement for Directors
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.5 1987 Deferred Compensation Plan for Executives
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
53
56
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
10.6 1987 Deferred Compensation Plan for Directors
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.7 1988 Deferred Compensation Plan for Executives
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.8 1988 Deferred Compensation Plan for Directors
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.9 1989 Deferred Compensation Plan for Executives
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.10 1989 Deferred Compensation Plan for Directors
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.11 1990 Deferred Compensation Plan for Executives
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.12 1990 Deferred Compensation Plan for Directors
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.13 Annual Deferred Compensation Plan for Executives
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.14 Annual Deferred Compensation Plan for Directors
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.15 Executive Retirement Plan (File No. 1-2313)* . . . . . . . . . . . . . . . . . . .
10.16 Employment Agreement with Jack K. Horton (File No. 1-2313)* . . . . . . . . . . .
10.17 Employment Agreement with Howard P. Allen
(File No. 1-2313)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.18 1991 Executive Incentive Compensation Plan (File No. 1-9936)* . . . . . . . . . .
10.19 1992 Executive Incentive Compensation Plan (File No. 1-9936)*
10.20 1993 Executive Incentive Compensation Plan . . . . . . . . . . . . . . . . . . . .
10.21 Retirement Plan for Directors (File No. 1-2313)* . . . . . . . . . . . . . . . . .
10.22 Long-Term Incentive Plan for Executive Officers
(Registration No. 33-19541)* . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.23 Estate and Financial Planning Program for Executive
Officers (File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.24 Consulting Agreement with Jack K. Horton (File No. 1-9936)* . . . . . . . . . . .
10.25 Consulting Agreement with Howard P. Allen (File No. 1-9936)* . . . . . . . . . . .
10.26 Consulting Agreement with Michael R. Peevey
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.27 Resignation and General Release Agreement with Michael R.
Peevey (File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.28 Employment Agreement with Bryant C. Danner
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.29 Employment Agreement with Charles W. Johnson
(File No. 1-9936)* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.30 Resignation Agreement with Charles B. McCarthy, Jr. . . . . . . . . . . . . . . .
11. Computation of Primary and Fully Diluted Earnings Per Share . . . . . . . . . . .
12. Computation of Ratios of Earnings to Fixed Charges . . . . . . . . . . . . . . . .
13. Selected portions of the Annual Report to Shareholders
for year ended December 31, 1993 . . . . . . . . . . . . . . . . . . . . . . . . .
21. Subsidiaries of the Registrant . . . . . . . . . . . . . . . . . . . . . . . . . .
23. Consent of Independent Public Accountants - Arthur Andersen
& Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24.1 Power of Attorney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24.2 Certified copy of Resolution of Board of Directors
Authorizing Signature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
- ------------
* Incorporated by reference pursuant to Rule 12b-32.
54