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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
COMMISSION FILE NUMBER 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
CALIFORNIA 95-1240335
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
2244 WALNUT GROVE AVENUE (818) 302-1212
ROSEMEAD, CALIFORNIA 91770 (REGISTRANT'S TELEPHONE NUMBER,
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE) INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -------------------------
CAPITAL STOCK
CUMULATIVE PREFERRED $100 CUMULATIVE PREFERRED AMERICAN AND PACIFIC
4.08% SERIES 4.78% SERIES 7.58% SERIES
4.24% SERIES 5.80% SERIES
4.32% SERIES 7.36% SERIES
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL
REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE
REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH
FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES X NO
INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO
ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED,
TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION
STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY
AMENDMENT TO THIS FORM 10-K. [ X ]
AS OF MARCH 1, 1994, THERE WERE 434,888,104 SHARES OF COMMON STOCK OUTSTANDING,
ALL OF WHICH ARE HELD BY THE REGISTRANT'S PARENT HOLDING COMPANY. THE
AGGREGATE MARKET VALUE OF REGISTRANT'S VOTING STOCK HELD BY NON-AFFILIATES WAS
APPROXIMATELY $554,822,588 ON OR ABOUT MARCH 1, 1994, BASED UPON PRICES
REPORTED BY THE AMERICAN STOCK EXCHANGE. THE MARKET VALUES OF THE VARIOUS
CLASSES OF VOTING STOCK HELD BY NON-AFFILIATES WERE AS FOLLOWS: CUMULATIVE
PREFERRED STOCK $225,765,088; $100 CUMULATIVE PREFERRED STOCK $329,057,500.
THE MARKET VALUES OF CERTAIN UNLISTED SERIES OF $100 CUMULATIVE PREFERRED
STOCK, FOR WHICH MARKET PRICES ARE NOT AVAILABLE, WERE DERIVED BY DIVIDING THE
ANNUAL DIVIDEND RATE OF EACH SUCH SERIES OF STOCK BY THE AVERAGE YIELD OF ALL
OF THE COMPANY'S CUMULATIVE PREFERRED AND $100 CUMULATIVE PREFERRED STOCK
OUTSTANDING FOR WHICH MARKET PRICES WERE AVAILABLE.
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
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Existing Generating Facilities . . . . . . . . . . . . . . . . . . . . . . . . . 12
El Paso Electric Company ("El Paso") Bankruptcy . . . . . . . . . . . . . . . . . 13
Construction Program and Capital Expenditures . . . . . . . . . . . . . . . . . . 14
Nuclear Power Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Nuclear Waste Policy Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Competitive Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Antitrust Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Environmental Litigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
San Onofre Personal Injury Litigation . . . . . . . . . . . . . . . . . . . . . . 20
4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . 21
Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . 21
PART II
5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . . . . . . . . . 23
8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 23
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . 24
PART III
10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . 24
11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . 24
PART IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Report of Independent Public Accountants on
Supplemental Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
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PART I
ITEM 1. BUSINESS
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.
REGULATION
Edison's retail operations are subject to regulation
by the California Public Utilities Commission ("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 U.S.
Environmental Protection Agency ("EPA"), which administers certain federal
statutes relating to environmental matters. Other federal, state and local
laws and regulations relating to environmental protection, land use and water
rights also impact Edison.
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.
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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 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 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
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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.
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
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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.
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
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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 $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
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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.
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 the Mohave Generating Station
("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
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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 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:
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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
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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, 7.996 cents;
natural gas, 2.930 cents; nuclear, 0.537 cents; and coal, 1.226 cents.
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.
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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.
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.
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 Edison's operation of existing
facilities, on the timing, cost, location, design, construction and operation
by Edison of new facilities required to meet its future load requirements, and
on the cost of mitigating the effect of past operations on the environment.
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These activities substantially affect future planning and will continue to
require modifications of Edison's existing facilities and operating procedures.
Edison is unable to predict the extent to which additional regulations may
affect its operations and capital expenditure requirements.
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 the Mohave plant 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 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 the Mohave plant on the Mohave
area air quality. The 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
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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.
Edison has identified 42 sites for which it is, or
may be, responsible for remediation under environmental laws. Edison is
participating in investigations and cleanups at a number of these sites and has
recorded a $60,000,000 liability for its 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 Edison's share of
these costs in proportion to other responsible parties is determined and as
additional investigations and cleanups are performed.
The CPUC currently allows 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 11, 1994 proposed
decision issued by a CPUC ALJ accepted the collaborative report's
recommendation. A final CPUC decision is expected in early 1994.
Twenty of the 42 sites identified are 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 disposal of PCB waste
are immaterial.
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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.
ITEM 2. PROPERTIES
EXISTING 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
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
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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
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.
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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 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.
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Cash required by Edison for its capital expenditures
totaled $1,040,000,000 in 1993, $787,000,000 in 1992 and $964,000,000 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
------ ------ ------ ------ ----- ------
Total . . . . . . . . . . . . . . . . . . . . 1,179 1,227 1,110 1,136 1,391 6,043
Less: allowance for funds used during construction . . 38 44 43 43 43 211
------ ------ ------ ------ ------ ------
Cash required for construction expenditures . . . . . $1,141 $1,183 $1,067 $1,093 $1,348 $5,832
------ ------ ------ ------ ------ ------
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
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.
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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 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).
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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 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
17
20
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.
The Public Utility Regulatory Policies Act of 1978
("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.
18
21
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.
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 which dismissed the lawsuit.
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
19
22
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.
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 plaintiff's 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.
20
23
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:
EXECUTIVE OFFICERS(1) OF THE REGISTRANT
AGE AT
DECEMBER EFFECTIVE
EXECUTIVE OFFICER 31, 1993 COMPANY POSITION(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 3 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) Messrs. Bryson, Danner, Bushey and Stewart also hold
the same positions with SCEcorp. Mr. Fohrer holds
the office of Senior Vice President, Treasurer and
Chief Financial Officer of SCEcorp. SCEcorp is the
parent holding company of Edison.
21
24
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
22
25
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 Relations September 1985 to
September 1989
Georgia R. Nelson Special Assistant to the Chairman February 1992 to
March 1993
Manager -- Procurement and Material Management September 1989 to
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, Mr. Danner was in
the firm's environmental department.
(2) As Vice President of the Kaiser Foundation Health Plan of Texas,
Ms. 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.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Certain information responding to Item 5 with
respect to frequency and amount of cash dividends is included in Edison's
Annual Report to Shareholders for the year ended December 31, 1993, ("Annual
Report") under "Quarterly Financial Data" on page 6 and is incorporated by
reference pursuant to General Instruction G(2). As a result of the formation
of a holding company described above in Item 1, all of the issued and
outstanding common stock of Edison is owned by SCEcorp and there is no market
for such stock.
ITEM 6. SELECTED FINANCIAL DATA
Information responding to Item 6 is included in the
Annual Report under "Selected Financial and Operating Data: 1989-1993" on page
1 and is incorporated herein by reference pursuant to General Instruction G(2).
23
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
Information responding to Item 7 is included in the
Annual Report under "Management's Discussion and Analysis of Results of
Operations and Financial Condition" on pages 2 through 6 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 page 6 under "Quarterly Financial Data" and on
pages 7 through 21 and is incorporated herein by reference pursuant to General
Instruction G(2).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information concerning executive officers of Edison
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 Edison's Annual Meeting of Shareholders
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.
24
27
Management's Discussion and Analysis of Results of Operations and
Financial Condition
Consolidated Statements of Income -- Years Ended December 31, 1993,
1992 and 1991
Consolidated Statements of Retained Earnings -- 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
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(2) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS AND
SCHEDULES SUPPLEMENTING FINANCIAL STATEMENTS
The following documents may be found in this report
at the indicated page numbers.
Page
----
Report of Independent Public Accountants on Supplemental
Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 26
Schedule V -- Property, Plant and Equipment for the Years
Ended December 31, 1993, 1992 and 1991 . . . . . . .. 27
Schedule VI -- Accumulated Depreciation and Amortization of
Property, Plant, and Equipment for the Years
Ended December 31, 1993, 1992 and 1991 . . . . . . .. 30
Schedule VIII -- Valuation and Qualifying Accounts for the Years
Ended December 31, 1993, 1992 and 1991 . . . . . . .. 33
Schedule IX -- Short-Term Borrowings For Each of the Three
Years in the Period Ended December 31, 1993 . . . . .. 36
Schedule X -- Supplementary Income Statement Information For
Each of the Three Years in the Period Ended
December 31, 1993 . . . . . . . . . . . . . . . . . .. 37
Schedule XIII --Other Investments, December 31, 1993 . . . . . . . . . . . . . . . . .. 38
Schedules I through XIII, except those referred to
above, are omitted as not required or not applicable.
(3) EXHIBITS
See Exhibit Index on page 40 of this report.
(B) REPORTS ON FORM 8-K
October 5, 1993
Item 5: Other Events: Palo Verde Settlement
December 20, 1993
Item 5: Other Events: Cost of Capital
Financing Results
25
28
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited, in accordance with generally
accepted auditing standards, the consolidated financial statements included in
the 1993 Annual Report to Shareholders of Southern California Edison Company,
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 the Company'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.
Los Angeles, California
February 4, 1994
29
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . $ 59,356 $ 38,548 $ (4,640) $ 147 $ 93,411
----------- ---------- --------- --------- -----------
_______________
(a) Reflects transfers to plant in service, which are
net of additions to construction work in progress.
(b) Reflects prior-year adjustments.
27
30
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . . $ 53,848 $ 1,541 $ (147) $ 4,114 $ 59,356
----------- -------- --------- -------- -----------
_______________
(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.
28
31
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . $ 50,777 $ 3,701 $ (584) $ (46) $ 53,848
----------- --------- --------- -------- -----------
_______________
(a) Reflects transfers to plant in service, which are
net of additions to construction work in progress.
29
32
SOUTHERN CALIFORNIA EDISON COMPANY
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 ------------------------------ Balace
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 . . . . . . . $ 29,540 $ 762 $ (7) $ 1,278 $ -- $ 31,573
----------- --------- --------- ---------- -------- ----------
_______________
(a) Includes removal costs related to facilities retired,
damage claims and relocation costs collected from
others, and various other adjustments of depreciation
and amortization.
30
33
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . $ 27,266 $ 1,245 $ (17) $ 1,046 $ -- $ 29,540
---------- -------- ----------- -------- ------- ----------
_______________
(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.
31
34
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . $ 26,418 $ 784 $ (244) $ 308 $ -- $ 27,266
---------- -------- --------- -------- ------- ----------
_______________
(a) Includes removal costs related to facilities retired,
damage claims and relocation costs collected from others,
and various other adjustments of depreciation and amortization.
32
35
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . . . $ 8,728 $ 38,310 $ -- $ 31,374 $ 15,664
All other . . . . . . . . . . 4,591 (12) -- 1,821 2,758
-------- -------- ------- -------- --------
Total . . . . . . . . . . . $ 13,319 $ 38,298 $ -- $ 33,195(a) $ 18,422
-------- -------- ------- -------- --------
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 acrued paid
absense 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 charge to operations that were not covered by
insurance.
33
36
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . . . $ 9,982 $ 22,805 $ -- $ 24,059 $ 8,728
All other . . . . . . . . . . 4,934 3,346 -- 3,689 4,591
-------- -------- ------- -------- --------
Total . . . . . . . . . . . $ 14,916 $ 26,151 $ -- $ 27,748(a) $ 13,319
-------- -------- ------- -------- --------
Group B:
Regulatory settlement . . . . . . $124,000 $ -- $ 9,320(b) $ 19,940(c) $113,380
DOE decontamination
and decommissioning . . . . . -- -- 53,136(d) -- 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) Accounts written off, net.
(b) Represents reserve addition for the settlement with the
California Public Utilities Commission's Division of
Ratepayer Advocates regarding affiliated company power
purchases.
(c) Represents the amortization of the difference between
the nominal value and the present value.
(d) Represents the estimated long-term costs to be incurred
and recovered through rates over 15 years; reclassified
from account 253, other deferred credits.
(e) Represents an additional estimated liability established
for environmental cleanup costs expected to be incurred
and recovered through rates in future years.
(f) Amount reclassified to account 253.
(g) Primarily represents transfers from the accrued paid absence
allowance account for required additioins to the comprehensive
disability plan accounts.
(h) Includes pension payments to retired employees, amounts paid
to active employees during periods of illness and the funding of
certain pension benefits.
(i) Amounts charged to operations that were not covered by insurance.
34
37
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . . . $ 10,399 $ 22,507 $ -- $22,924 $ 9,982
All other . . . . . . . . . . 7,814 2,358 -- 5,238 4,934
-------- -------- ------- ------- --------
Total . . . . . . . . . . . $ 18,213 $ 24,865 $ -- $28,162(a) $ 14,916
-------- -------- ------- ------- --------
Group B:
Regulatory settlement . . . . . . $ -- $124,000(b) $ -- $ -- $124,000
Environmental cleanup . . . . . . -- -- 40,000(c) -- 40,000
Pension and benefits . . . . . . 98,886 29,267 18,749(d) 34,895(e) 112,007
Insurance, casualty and
other . . . . . . . . . . . . 61,620 63,901 -- 55,008(f) 70,513
-------- -------- ------- ------- -------
Total . . . . . . . . . . . $160,506 $217,168 $58,749 $89,903 $346,520
-------- -------- ------- ------- --------
_______________
(a) Accounts written off, net.
(b) Represents a reserve addition for a proposed settlement
with the California Public Utilities Commission's
Division of Ratepayer Advocates regarding affiliated
company power purchases.
(c) Represents an estimated minimum liability established
for environmental cleanup costs expected to be incurred
and recovered through rates in future years.
(d) Primarily represents transfers from the accrued paid
absence allowance account for required additions to the
comprehensive disability plan accounts.
(e) Includes pension payments to retired employees, amounts
paid to active employees during periods of illness and
the funding of certain pension benefits.
(f) Amounts charged to operations that were not covered by
insurance.
35
38
SOUTHERN CALIFORNIA EDISON COMPANY
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)
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
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 3.65 455,700 361,100 4.03
Payable to holders of commercial
paper--fuel . . . . . . . . . . . . . 228,300(c) 3.65 400,100 318,000 4.03
DECEMBER 31, 1991:
Payable to holders of commercial
paper--general purpose . . . . . . . -- -- $409,900 $145,300 6.36%
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
_______________
(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 Edison to refinance short-term borrowings on a
long-term basis, borrowings of $70,000,000 as of
December 31, 1993, $63,000,000 as of December 31, 1992,
and $151,000,000 as of December 31, 1991, have been
reclassified as long-term debt on the Consolidated
Balance Sheets in the 1993 Annual Report to reflect the
anticipated timing of repayment of nuclear fuel
indebtedness.
36
39
SOUTHERN CALIFORNIA EDISON COMPANY
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 . . . . . . . . . . . . . . . . . . . . . . . $150,763
Year ended December 31, 1992:
Property taxes . . . . . . . . . . . . . . . . . . . . . . . 150,638
Year ended December 31, 1991:
Property taxes . . . . . . . . . . . . . . . . . . . . . . . 150,252
_______________
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.
37
40
SOUTHERN CALIFORNIA EDISON COMPANY
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
-------- -------- --------
OTHER INVESTMENTS . . . . . . . . . . . . . -- $ 20,577 $ 20,577 $ 20,577
-------- -------- --------
38
41
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
By 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 March 17, 1994
and Chief 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)
39
42
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 Restated Articles of Incorporation as amended through June 1, 1993
3.2 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)*
4.25 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)*
40
43
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)*
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)*
41
44
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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)*
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)*
42
45
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
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-Eighth 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)*
10.6 1987 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.7 1988 Deferred Compensation Plan for Executives (File No. 1-2313)*
43
46
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.8 1988 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.9 1989 Deferred Compensation Plan for Executives (File No. 1-2313)*
10.10 1989 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.11 1990 Deferred Compensation Plan for Executives (File No. 1-2313)*
10.12 1990 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.13 Annual Deferred Compensation Plan for Executives (File No. 1-2313)*
10.14 Annual Deferred Compensation Plan for Directors (File No. 1-2313)*
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. 1-2313)*
10.19 1992 Executive Incentive Compensation Plan (File No. 1-2313)*
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. 1-2313)*
10.24 Consulting Agreement with Jack K. Horton (File No. 1-2313)*
10.25 Consulting Agreement with Howard P. Allen (File No. 1-2313)*
10.26 Consulting Agreement with Michael R. Peevey (File No. 1-2313)*
10.27 Resignation and General Release Agreement of Michael R. Peevey (File No. 1-2313)*
10.28 Employment Agreement with Bryant C. Danner (File No. 1-2313)*
10.29 Resignation Agreement of Charles B. McCarthy, Jr.
12. Computation of Ratios of Earnings to Fixed Charges
13. Selected portions of the Annual Report to Shareholders for year ended December 31, 1993
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.
44