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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, 1995
--------------------------------------------
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 American and Pacific
4.08% Series 4.78% 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 19, 1996, 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 $502,723,478 on or about
March 19, 1996, 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
$222,723,478; $100 CUMULATIVE PREFERRED STOCK $280,000,000.
The market values for the $100 Cumulative Preferred Stock, which are
unlisted, were obtained from broker quotes.
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, 1995 Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 1996 Annual Meeting
of Shareholders Part III
TABLE OF CONTENTS
Item Page
- ---- ----
Part I
1. Business 1
Competitive Environment 1
Regulation 3
Rate Matters 4
Fuel Supply and Purchased Power Costs 7
Environmental Matters 8
2. Properties 11
Existing Generating Facilities 11
El Paso Electric Company ("El Paso") Bankruptcy 12
Construction Program and Capital Expenditures 13
Nuclear Power Matters 13
3. Legal Proceedings 15
QF Litigation 15
Environmental Litigation 16
San Onofre Personal Injury Litigation 17
Employment Discrimination Litigation 18
4. Submission of Matters to a Vote of Security Holders 19
Executive Officers of the Registrant 19
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 22
6. Selected Financial Data 22
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition 22
8. Financial Statements and Supplementary Data 22
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 22
Part III
10. Directors and Executive Officers of the Registrant 23
11. Executive Compensation 23
12. Security Ownership of Certain Beneficial
Owners and Management 23
13. Certain Relationships and Related Transactions 23
Part IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 23
Report of Independent Public Accountants on
Supplemental Schedule 25
Supplemental Schedule 26
Signatures 29
Exhibit Index 30
PART I
Item 1. Business
Southern California Edison Company ("SCE") was incorporated under
California law in 1909. SCE is a public utility primarily engaged in the
business of supplying electric energy to a 50,000 square-mile area of
central and southern California, excluding the City of Los Angeles and
certain other cities. This area includes some 800 cities and communities
and a population of more than 11 million people. SCE had an average of
15,490 full-time employees during 1995. During 1995, 38% of SCE's total
operating revenue was derived from commercial customers, 37% from
residential customers, 12% from industrial customers, 8% from public
authorities, 4% from agricultural and other customers and 1% from resale
customers. SCE comprises the major portion of the assets and revenue of
Edison International, formerly SCEcorp, its parent holding company.
On March 22, 1996, SCE announced a voluntary early retirement program for
full-time, non-union employees. SCE will record a charge of approximately
$65,000,000 (pretax) against second quarter earnings to reflect the costs
of this program. SCE expects to offset these costs with savings from the
retirement program within a year. SCE is taking this action in response
to the CPUC's 1995 General Rate Case decision and industry restructuring
order, which make adjustments within its workforce inevitable. SCE
designed the voluntary retirement plan as the best approach for meeting
workforce needs, while maintaining commitments to customer service, system
reliability and employee safety. To meet these staffing requirements, SCE
will determine the number of employees in critical business functions who
can accept the retirement offer. SCE anticipates negotiating a program
for represented employees with its four labor unions later this year.
Competitive Environment
SCE currently operates in a highly regulated environment in which it has
an obligation to provide electric service to customers in return for an
exclusive franchise within its service territory. This regulatory
environment is changing. The generation sector has experienced
competition from nonutility power producers, and regulators are
restructuring California's electric utility regulation.
On December 20, 1995, the California Public Utilities Commission ("CPUC")
issued its decision on restructuring California's electric industry, which
it had been considering since April 1994. The new market structure would
provide competition and customer choice. The transition to a competitive
electric market would begin January 1, 1998, with all consumers
participating by 2003. Key elements of the decision are: creation of an
independent power exchange; creation of an independent system operator;
implementation of greater customer choice; transition cost recovery by the
utilities; and CPUC-established incentives to encourage utilities to
voluntarily divest at least 50% of their fossil-fueled units within their
service territory to address market power issues. On March 19, 1996, SCE
filed its voluntary divestiture plans proposing the auction of 50% of its
fossil-fueled units within its service territory, subject to certain
conditions, including assured recovery of various costs. Also, under the
decision the CPUC would regulate the rates, terms and conditions of
utility services not subject to competition using Performance Based
Ratemaking ("PBR") instead of cost-of-service regulation.
The independent power exchange, which would manage supply and demand
through an economic auction, will be under Federal Energy and Regulatory
Commission ("FERC") jurisdiction. Purchasing from and selling to the
power exchange during the transition period, which runs for five years
from the creation of the independent power exchange, will be mandatory for
California's investor-owned utilities, while others can voluntarily
participate. The independent system operator would have operational
control of the utilities' transmission facilities and, therefore, would
control the scheduling and dispatch of all electricity on the state's
power grid.
The new market structure would provide three avenues of customer choice.
The first involves a continuation of utility-tariffed rates with customers
choosing a monthly average rate or hourly time-of-use rates, which allows
customers with specialized meters to access pricing information and alter
their consumption accordingly. The second avenue involves customers
continuing with utility-tariffed rates and entering into "contracts for
differences" which manage risks associated with the market clearing prices
published by the power exchange. The last avenue involves customers
negotiating directly with generation providers and then arranging for
transmission of the power with the transmission system operator (direct
access).
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable competition transition charge
("CTC"). This charge would apply to all customers who currently use
utility services or begin utility service after the restructuring decision
is effective. SCE estimates its potential transition costs, through 2025
to be approximately $9.3 billion (net present value), based on incurred
costs, and forecasts of future costs and assumed market prices. However,
changes in the assumed market price could require material revisions to
such estimates. The potential transition costs are comprised of $4.9
billion from SCE's qualifying facility ("QF") contracts, which are the
direct result of legislative and regulatory mandates; and $4.4
billion from costs pertaining to certain generating plants and
regulatory commitments consisting of costs incurred (whose recovery has
been deferred by the CPUC) to provide service to customers. Such
commitments include the recovery of income-tax benefits previously flowed-
through to customers, postretirement benefit transition costs, accelerated
recovery of nuclear plants (including San Onofre Nuclear Generating
Station ("San Onofre") Unit 1 and San Onofre Units 2 and 3 as discussed
below under "1995 General Rate Case"), nuclear decommissioning and certain
other costs. The undepreciated book value of a utility's generation plant
will be calculated on the amount in ratebase as of the decision date.
Further, adverse financial consequences could result if an ambiguity in
the CPUC's restructuring decision, as to recovery of capital expenditures
made to SCE's fossil generation units in 1996 and beyond during the
calculation of CTC, is not eliminated. SCE believes that recovery of such
capital expenditures is consistent with the intent of the restructuring
decision and has asked the CPUC to clarify the decision. If these efforts
at clarification, consistent with the decision's intent, are unsuccessful
then SCE estimates the effect would be to reduce 1996 earnings by more
than $50,000,000 (before taxes), based on SCE's 1996 capital budget for
its fossil generation units.
Because the restructuring of California's electric industry has widespread
impact and the market structure requires the participation and oversight
of the FERC, the CPUC has said it will seek to build a California
consensus involving the legislature, governor, public and municipal
utilities, and customers. FERC approval will be sought in a filing to be
made on April 29, 1996, and both agencies would need to move forward to
implement the new market structure. In addition, the CPUC plans to
prepare an environmental impact report, which impacts when the CPUC
proceeds with implementation of its decision. If the CPUC's restructuring
decision is upheld and implemented as outlined in the restructuring
decision, SCE would be allowed to recover its CTC (subject to a lower
return on equity) and would continue to apply accounting standards that
recognize the economic effects of rate regulation. The effect of such an
outcome would not be expected to materially affect SCE's results of
operations or financial condition during the transition period.
If revisions are made to the CPUC's restructuring decision that result in
SCE no longer meeting the criteria to apply regulatory accounting
standards to its generation operations, SCE may be required to write off
its recorded generation-related regulatory assets. At December 31, 1995,
these amounts totaled $1.4 billion (excluding balancing account
overcollections of $237,000,000 to be refunded to customers in June 1996),
primarily for the recovery of income-tax benefits previously flowed-
through to customers, the Palo Verde Nuclear Generating Station ("Palo
Verde") phase-in plan and unamortized loss on reacquired debt. Although
depreciation-related differences could result from applying a regulatory
prescribed depreciation method (straight-line, remaining-life method)
rather than a method that would have been applied absent the regulatory
process, SCE believes that the depreciable lives of its generation-
related assets would not vary significantly from that of an unregulated
enterprise, as the CPUC bases depreciable lives on periodic studies that
reflect the assets' physical useful life. SCE also believes that any
depreciation-related differences would be recovered through the CTC.
Additionally, if revisions are made to the CPUC's restructuring decision
that result in all or a portion of the CTC not being probable of recovery,
SCE could have additional write-offs associated with these costs if they
are not recovered through another regulatory mechanism. At this time, SCE
cannot predict when, or if, a consensus on restructuring will be reached,
what revisions will ultimately be made in the CPUC's restructuring plan
in subsequent proceedings or implementation phases, or the effect, after
the transition period, that competition will have on its results of
operations or financial condition.
In March 1995, the FERC proposed rules which would require utilities to
provide wholesale open transmission access to the nation's interstate
transmission grid, while allowing them to recover stranded costs
associated with open access. The proposal defines stranded costs as
legitimate, prudent and verifiable costs incurred to provide service to
customers that would subsequently become unbundled wholesale transmission
service customers of the utility. SCE supports the basic principles in
the FERC's proposal and filed comments in August 1995. A final FERC
decision is expected in mid-1996.
Regulation
SCE's retail operations are subject to regulation by the CPUC. The CPUC
has the authority to regulate, among other things, retail rates, issuances
of securities and accounting practices. SCE's wholesale operations are
subject to regulation by the FERC. The FERC has the authority to regulate
wholesale rates as well as other matters, including transmission service
pricing, accounting practices and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the Nuclear Regulatory Commission
("NRC") with respect to its nuclear power plants. NRC regulations govern
the granting of licenses for the construction and operation of nuclear
power plants and subject those power plants to continuing review and
regulation.
The construction, planning and siting of SCE's power plants within
California are subject to the jurisdiction of the California Energy
Commission and the CPUC. SCE is subject to rules and regulations of the
California Air Resources Board and local air pollution control districts
with respect to the emission of pollutants into the atmosphere, the
regulatory requirements of the California State Water Resources Control
Board and regional boards with respect to the discharge of pollutants into
waters of the state and the requirements of the California Department of
Toxic Substances Control with respect to handling and disposal of
hazardous materials and wastes. SCE is also subject to regulation by the
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 affect SCE.
The California Coastal Commission has continuing jurisdiction over the
coastal permit for San Onofre Units 2 and 3. Although the units are
operating, the permit's mitigation requirements have not yet been
fulfilled. California Coastal Commission jurisdiction may continue for
several years due to implementation and oversight of permit mitigation
conditions, including restoration of wetlands and construction of an
artificial reef for kelp.
The Department of Energy has regulatory authority over certain aspects of
SCE's operations and business relating to energy conservation, solar
energy development, power plant fuel use and disposal, coal conversion,
electric sales for export, public utility regulatory policy and natural
gas pricing.
Rate Matters
CPUC Retail Ratemaking
The rates for electricity provided by SCE to its retail customers comprise
several major components established by the CPUC to compensate SCE 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. CPUC decisions on SCE's PBR proposals (discussed
below) and the ongoing electric industry restructuring (discussed above)
could affect the need for future general rate case proceedings. During
a general rate case, the CPUC critically reviews SCE'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, 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, SCE
and the CPUC proceed to a rate design phase which allocates revenue
requirements and establishes rate levels for customers.
SCE filed for a PBR mechanism in 1993, requesting a revenue-indexing
formula to combine operating expenses and capital-related costs into a
single index to determine most of its revenue (excluding fuel) from 1996-
2000. The filing was subsequently divided between transmission and
distribution, and power generation. Hearings concluded on the
transmission and distribution phase in December 1994. The CPUC's
restructuring decision, as discussed above, requested comments addressing
whether SCE's transmission and distribution PBR proposal should be amended
or reviewed as filed. On January 19, 1996, SCE requested the CPUC approve
its PBR as filed. SCE expects to file a proposal for the generation PBR
mechanism phase in July 1996 which complies with the restructuring
decision.
SCE's fuel, purchased-power and energy-related costs of providing electric
service are recovered through a balancing account mechanism called the
Energy Cost Adjustment Clause ("ECAC"). Under the ECAC balancing account
procedure, actual fuel, purchased power and energy-related revenue 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 reasonableness reviews by the CPUC. The
reasonableness of execution and the ongoing administration of all
purchased-power contracts including contracts with QFs is also reviewed
in ECAC proceedings by the CPUC. The CPUC has not yet completed its
review of all of SCE's energy and fuel related costs for the period April
1, 1990, to the present. Certain incentive provisions are included in the
ECAC that can affect the amount of fuel and energy-related costs actually
recovered. SCE is required to make an ECAC filing for each calendar year,
and must also make a second filing for a mid-year adjustment if it would
result in an ECAC rate change exceeding 5% of total annual revenue.
For SCE's interest in the three units of Palo Verde, the CPUC authorized
a 10-year rate phase-in plan which deferred collection of $200,000,000 of
investment-related revenue during the first four years of operation for
each of the three units, commencing on their respective commercial
operation dates. Revenue collection 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 evenly over the final six years of each unit's phase-in plan.
The plans end in 1996 for Units 1 and 2, and in 1998 for Unit 3.
The CPUC has also adopted a Nuclear Unit Incentive Procedure ("NUIP")
which provides for a sharing of additional energy costs or savings between
SCE and its ratepayers when operation of any of the units of San Onofre
or Palo Verde Units is outside a specified range (55% to 80% of each
unit's rated capacity). The NUIP ended for San Onofre Units 2 and 3 at
the end of fuel cycle number seven which occurred on May 23, 1995 and
September 26, 1995, respectively.
The Electric Revenue Adjustment Mechanism reflects the difference between
the recorded and authorized level of base rate revenue. The CPUC adopted
this mechanism primarily to minimize the effect on earnings of
fluctuations in retail kilowatt-hour sales.
1995 General Rate Case ("GRC")
On January 10, 1996, the CPUC issued its decision on SCE's 1995 general
rate case. The decision affirmed the CPUC's interim order to reduce 1995
operating revenue by $67,000,000, but decreased 1996 operating revenue by
an additional $9,000,000, which includes a decrease of $44,000,000 for
operating and maintenance expenses. The decision also rejected the
original settlement's proposed new rate mechanism for San Onofre Units 2
and 3. However, the CPUC indicated approval of the general concept of
recovery of SCE's remaining investment (approximately $2.7 billion) and
operating costs of San Onofre Units 2 and 3 under a new rate mechanism.
The decision proposed modifications to the San Onofre Units 2 and 3
portions of the settlement and gave SCE 25 days to accept or reject it.
On February 5, 1996, SCE filed a revised San Onofre Units 2 and 3 proposal
under which it accepted the CPUC's proposed modification. Under that
proposal, SCE's San Onofre Units 2 and 3 investment will be recovered at
a reduced rate of return (7.34% compared to the current 9.55%), over an
eight-year period, beginning in the second quarter of 1996. Future
operating costs and incremental capital expenditures at San Onofre are
subject to an incentive pricing plan, where SCE receives about 4 cents per
kilowatt-hour. Profits or losses resulting from cost differences from the
incentive price will flow through to shareholders. Beginning in 2004,
after SCE's investment is fully recovered, power from San Onofre Units 2
and 3 would be sold at the then-current market prices and ratepayers would
receive 50% of the benefits of post-2003 operation. Final approval of the
revised San Onofre Units 2 and 3 proposal is pending at the CPUC.
Energy Cost Adjustment Clause ("ECAC")
A CPUC decision related to SCE's 1996 authorized revenue for fuel and
purchased power was issued on February 23, 1996. At issue was the
treatment of a $237,000,000 overcollection in ECAC. The CPUC ordered a
one-time credit applied to customer bills in 1996. SCE's 1996
CPUC-authorized revenue, including the effects of other rate actions, will
be reduced by $338,000,000, or 4.4%, and SCE is required to credit
customer bills in June 1996 to refund the $237,000,000 overcollection
referred to above. The reduction in authorized revenue resulting from the
$237,000,000 refund will not impact 1996 earnings as these costs receive
balancing account treatment; however, cash flows in 1996 will be affected.
SCE believes it will have sufficient liquidity for the 1996 refund from
cash provided by operating activities, projected investment balances and
available lines of credit.
1992 Annual ECAC Application
SCE filed its testimony in the QF reasonableness phase of SCE's 1992 ECAC
proceeding on September 1, 1992. On January 16, 1996, the CPUC's Division
of Ratepayer Advocates ("DRA") released its report on QF reasonableness
for both the 1992 record period and as to issues that had been reserved
from the 1991 ECAC proceeding. The report recommends: (1) disallowances
of $8,678,458 for the 1992 record period and $8,039,177 for the 1991
record period attributable to alleged deficiencies in how SCE administers
the firm capacity payment provisions in its agreements with QFs; and (2)
an as-yet-to-be-determined disallowance regarding QF sales of energy and
as-available capacity that exceed the nameplate ratings specified by the
QF in Interim Standard Offer No. 4 contracts and negotiated contracts
containing similar payment provisions (the DRA indicates it has not yet
received the data necessary to calculate the overpayments). The report
requests that such disallowances be assessed on a continuing basis until
SCE ends its challenged practices in these areas. No schedule has been
set for further testimony or hearings on these issues.
1994 Annual ECAC Application
SCE filed its testimony in the non-QF phase of SCE's 1994 ECAC proceeding
on May 27, 1994. On May 23, 1995, the DRA filed its report on the
reasonableness of SCE's gas supply costs for both the 1993 and 1994 record
periods. The report recommends a disallowance of $13,300,000 for
excessive costs incurred from November 1993 through March 1994 associated
with the SCE's Canadian gas purchase and supply contracts. The report
requests that the CPUC defer finding the SCE Canadian supply and
transportation agreements reasonable for the duration of their terms and
that the costs procured under these contracts be reviewed on a yearly
basis. SCE filed rebuttal testimony in December 1995 and DRA will file
its rebuttal testimony in April 1996. SCE will then file its rebuttal
testimony in May 1996 prior to hearings which are scheduled in June and
July 1996.
CPUC-Mandated Power Contracts
In 1994, the CPUC ordered the California utilities to proceed with an
energy auction to solicit bids for new contracts with unregulated power
producers. This decision would have forced SCE to purchase 686 MW of new
power at fixed prices starting in 1997, costing SCE customers $14 billion
over the lives of the contracts. SCE negotiated agreements, at
substantially lower costs than those mandated by auction, with eight
unregulated power producers, representing 648 MW of the 686 MW mandated.
These agreements, which are subject to CPUC approval, would save SCE
customers about 85% of anticipated overpayments compared with the mandated
contracts. After extensive review by the CPUC and the FERC, the CPUC
issued a ruling supporting resolution of the energy auction through
negotiated settlements and set criteria to be used to evaluate the
settlements. SCE has evaluated the impact of these criteria on its
existing settlement agreements and, upon conclusion of settlement
negotiations with the remaining parties, will file an application
requesting CPUC approval (expected in 1996).
Mohave Order Instituting Investigation
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. The CPUC ordered a
second phase of this proceeding to quantify the disallowance. On December
22, 1995, SCE and the DRA filed a $38,000,000 settlement agreement subject
to CPUC approval. This agreement has been fully reflected in the
financial statements.
Fuel Supply and Purchased Power Costs
Fuel and purchased-power costs were approximately $3.2 billion in 1995,
a 6% decrease from 1994.
SCE's sources of energy during 1995 were: purchased power 41%; natural
gas 20%; nuclear 18%; coal 13%; and hydro 8%.
Average fuel costs, expressed in cents per kilowatt-hour, for the year
ended December 31, 1995, were: oil, 7.110 cents; natural gas, 2.192
cents; nuclear, 0.460 cents; and coal, 1.235 cents.
Natural Gas Supply
Twelve of SCE's major steam electric generating plants are designed to
burn oil or natural gas as the primary boiler fuel. In 1990, SCE 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 SCE fully responsible for all natural gas
procurement activities previously performed by local distribution
companies.
To implement its all-gas strategy, SCE 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, SCE 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 SCE's
current average annual supply needs. The rest of SCE's gas supply is
acquired under short-term contracts from Texas, New Mexico and the Rocky
Mountain region.
Firm transportation arrangements provide the necessary long-term
reliability for supply deliverability. To transport Canadian supplies,
SCE 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. SCE has a 30-year commitment to this
project, construction of which was completed in late 1993. In addition,
SCE has a 15-year commitment with El Paso Natural Gas to transport
200,000,000 cubic feet per day (option to step down to 130,000,000 cubic
feet per day in 1997) from the southwestern U.S.
Nuclear Fuel Supply
SCE has contractual arrangements covering 100% of the projected nuclear
fuel requirements for San Onofre through the years indicated below:
Units
2 & 3
-----
Uranium concentrates(1)(2) . . . . . . . . . . . . . . . . . . . . . 1995
Conversion(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . 1995
Enrichment(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . 1998
Fabrication. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000
Spent fuel storage(3). . . . . . . . . . . . . . . . . . . . . . . . 2006/2006
_______________
(1) Assumes the San Onofre participants meet their supply obligations in
a timely manner.
(2) SCE is in the process of negotiating uranium, conversion, and
enrichment contracts which will cover a majority of the San Onofre
requirements through 2003.
(3) 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, SCE will furnish its share of uranium
concentrates requirements through at least 1996 from existing contracts.
Contracts cover requirements to provide conversion and fabrication through
2000, and enrichment through 2002.
Palo Verde on-site spent fuel storage capacity will accommodate needs
through 1999 while maintaining full-core reserve. Planned modifications
will extend storage capacities with full-core reserve through 2005 for
Units 1 and 2 and through 2006 for Unit 3.
Environmental Matters
Legislative and regulatory activities in the areas of air and water
pollution, waste management, hazardous chemical use, noise abatement, land
use, aesthetics and nuclear control continue to result in the imposition
of numerous restrictions on SCE's operation of existing facilities, on
the timing, cost, location, design, construction and operation by SCE of
new facilities required to meet its future load requirements, and on the
cost of mitigating the effect of past operations on the environment. These
activities substantially affect future planning and will continue to
require modifications of SCE's existing facilities and operating
procedures. SCE is unable to predict the extent to which additional
regulations may affect its operations and capital expenditure
requirements.
The Clean Air Act provides the statutory framework to implement a program
for achieving national ambient air quality standards in areas exceeding
such standards and provides for maintenance of air quality in areas
already meeting such standards. The Clean Air Act was amended in 1990,
giving the South Coast Air Quality Management District ("SCAQMD") 20 years
to achieve the federal air quality standards for ozone. The SCAQMD's Air
Quality Management Plan ("AQMP"), adopted in 1994, demonstrates a
commitment to attain the federal ozone air quality standard by 2010.
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, require SCE to significantly reduce NOx emissions through
retrofit or purchase of trading credits on all basin generation by 2003.
In Ventura County, a NOx rule was adopted requiring more than an 88% NOx
reduction by June 1996 at all utility boilers. SCE expects to spend a
total of approximately $290,000,000 in capital expenditures by 2001 to
meet these requirements.
The CAAA does 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. Also, the EPA and SCE will conclude a cooperative
tracer study of SO2 emissions from the Mohave plant in late 1996 or early
1997. This study is evaluating potential impact from Mohave emissions on
haze within Grand Canyon National Park. The extent to which these studies
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. SCE
has received more sulfur dioxide allowances than it requires for its
projected operations. 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 required SCE to meet a
new lower opacity limit in early 1994. The NDEP reviewed SCE's
performance relative to the opacity limit again in 1995 and determined to
retain the current standard. Until more definitive information on tracer
study results are available, SCE expects to meet all the present
regulations through improved operations at the plant.
The CAAA also requires 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. The study has not been
completed to date.
Regulations under the Clean Water Act require permits for the discharge
of certain pollutants into waters of the U.S. 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, SCE incurs additional expenses and capital expenditures. SCE
presently has discharge permits for all applicable facilities.
The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure
to individuals of chemicals known to the State of California to cause
cancer or reproductive harm and the discharge of such listed chemicals
into potential sources of drinking water. Additional chemicals are
continuously being put on the state's list, requiring constant monitoring
by SCE.
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.
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.
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing
technology, presently enacted laws and regulations, experience gained at
similar sites, and the probable level of involvement and financial
condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and
maintenance, monitoring and site closure. Unless there is a probable
amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities at undiscounted amounts).
While SCE has numerous insurance policies that it believes may provide
coverage for some of these liabilities, it does not recognize recoveries
in its financial statements until they are realized.
SCE's recorded estimated minimum liability to remediate its 58 identified
sites was $114,000,000, at December 31, 1995, and 1994. The ultimate
costs to clean up SCE's identified sites may vary from its recorded
liability due to numerous uncertainties inherent in the estimation
process, such as: the extent and nature of contamination; the scarcity of
reliable data for identified sites; the varying costs of alternative
cleanup methods; developments resulting from investigatory studies; the
possibility of identifying additional sites; and the time periods over
which site remediation is expected to occur. SCE believes that, due to
these uncertainties, it is reasonably possible that cleanup costs could
exceed its recorded liability by up to $215,000,000. The upper limit of
this range of costs was estimated using assumptions least favorable to SCE
among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 24 of its
sites, representing $90,000,000 of its recorded liability, through an
incentive mechanism (SCE may request to include additional sites). Under
this mechanism, SCE will recover 90% of cleanup costs through customer
rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs through insurance and other third-party recoveries.
SCE has settled insurance claims with several carriers, and is continuing
to pursue additional recovery. Costs incurred at the remaining 34 sites
are expected to be recovered through customer rates. SCE has filed a
request with the CPUC to add 11 of these sites ($6,000,000 in estimated
minimum liability) to the incentive mechanism. SCE has recorded a
regulatory asset of $104,000,000 for its estimated minimum environmental
cleanup costs expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information including, the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible
for contributing to any costs incurred for remediating these sites. Thus,
no reasonable estimate of cleanup costs can be made for these sites at
this time.
SCE expects to clean up its identified sites over a period of up to 30
years. Remediation costs in each of the next several years are expected
to range from $4,000,000 to $8,000,000. Recorded costs for 1995 were
$3,000,000.
Based on currently available information, SCE believes it is not likely
that it will incur amounts in excess of the upper limit of the estimated
range and, based upon the CPUC's regulatory treatment of environmental-
cleanup costs, SCE believes that costs ultimately recorded will not have
a material adverse effect on its results of operations or financial
condition. There can be no assurance, however, that future developments,
including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
SCE's total capital expenditures for environmental protection for the
years 1996 through 2000 are projected to be $1.2 billion. These
expenditures are mainly for placing overhead distribution lines
underground and reducing nitrogen oxides emissions from gas-fired
generators.
Item 2. Properties
Existing Generating Facilities
SCE 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% SCE-owned, 579 MW net) is located near Phoenix, Arizona. SCE 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. SCE 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. At year-end 1995, the
existing SCE-owned generating capacity (summer effective rating) was
comprised of approximately 65% gas, 15% nuclear, 11% coal, 8%
hydroelectric and 1% oil.
San Onofre, the Four Corners Project, certain of SCE'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
SCE, under specified circumstances and at its expense, to relocate
transmission, distribution and communication facilities located on lands
owned or controlled by federal, state or local governments.
With certain exceptions, major and certain minor hydroelectric projects
with related reservoirs, currently having an effective operating capacity
of 1,156 MW and located in whole or in part on lands of the U.S., are
owned and operated by SCE under governmental licenses which expire at
various times between 1996 and 2024. Such licenses impose numerous
restrictions and obligations on SCE, 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 SCE's and then only upon payment of specified compensation to
SCE. Any new licenses issued to SCE are expected to be issued under terms
and conditions less favorable than those of the expired licenses. SCE's
applications for the relicensing of certain hydroelectric projects
referred to above with an aggregate effective operating capacity of 95.9
MW are pending. Annual licenses issued for all SCE projects, whose
licenses have expired and are undergoing relicensing, will be renewed
until the new licenses are issued.
In 1995, SCE's peak demand was 17,548 MW, set on August 30, 1995. Total
area system operating capacity of 21,603 MW was available to SCE at the
time of the 1995 peak. SCE's record peak demand of 18,413 MW occurred on
August 17, 1992.
Substantially all of SCE's properties are subject to the lien of a trust
indenture securing First and Refunding Mortgage Bonds ("Trust Indenture"),
of which approximately $4.1 billion principal amount was outstanding at
December 31, 1995. Such lien and SCE's title to its properties are
subject to the terms of franchises, licenses, easements, leases, permits,
contracts and other instruments under which properties are held or
operated, certain statutes and governmental regulations, liens for taxes
and assessments, and liens of the trustees under the Trust Indenture. In
addition, such lien and SCE's title to its properties are subject to
certain other liens, prior rights and other encumbrances, none of which,
with minor or unsubstantial exceptions, affects SCE's right to use such
properties in its business, unless the matters with respect to SCE's
interest in the Four Corners Project and the related easement and lease
referred to below may be so considered.
SCE's rights in the Four Corners Project, which is located on land of The
Navajo Nation of Indians under an easement from the United States and a
lease from The Navajo Nation, may be subject to possible defects. These
defects include possible conflicting grants or encumbrances not
ascertainable because of the absence of, or inadequacies in, the
applicable recording law and the record systems of the Bureau of Indian
Affairs and The Navajo Nation, the possible inability of SCE to resort to
legal process to enforce its rights against The Navajo Nation without
Congressional consent, possible impairment or termination under certain
circumstances of the easement and lease by The Navajo Nation, Congress or
the Secretary of the Interior and the possible invalidity of the Trust
Indenture lien against SCE's interest in the easement, lease and
improvements on the Four Corners Project.
El Paso Electric Company ("El Paso") Bankruptcy
El Paso owns and leases a combined 15.8% interest in Palo Verde and owns
a 7% interest in Units 4 and 5 of the Four Corners Project. In January
1992, El Paso filed a voluntary petition to reorganize under Chapter 11
of the Bankruptcy Code in the United States Bankruptcy Court for the
Western District of Texas. Pursuant to an agreement among the Palo Verde
participants and an agreement among the participants in Four Corners Units
4 and 5, each participant is required to fund its proportionate share of
operation and maintenance, capital and fuel costs of Palo Verde and Four
Corners Units 4 and 5, respectively. The participation agreements provide
that if a participant fails to meet its payment obligation, each non-
defaulting participant must pay its proportionate share of the payments
owed by the defaulting participant. In February 1992, the bankruptcy
court approved a stipulation between El Paso and Arizona Public Service
("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 an Amended Plan of Reorganization and
Disclosure Statement ("Amended Plan") that was contingent on a merger in
which El Paso would have become a wholly-owned subsidiary of Central and
South West Corporation ("CSW").
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 and
subsequently, El Paso cured its pre-petition default.
On June 9, 1995, CSW notified El Paso and the Bankruptcy Court that the
Merger Agreement by and among El Paso and CSW was terminated and the
Amended Plan is revoked. In its notification, CSW stated as a basis for
its action, the fact that a number of closing conditions were not
fulfilled and certain material breaches had not been cured.
Subsequently, El Paso filed a consensual Fourth Amended Stand Alone Plan
of Reorganization, dated October 27, 1995. This Plan modifies the Fourth
Amended Stand Alone Plan of Reorganization initially filed by El Paso on
September 29, 1995. The Fourth Amended Plan 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. The Fourth Amended Plan was
confirmed on January 9, 1996, in the U.S. Bankruptcy Court for the Western
District of Texas. El Paso emerged from bankruptcy when the Fourth
Amended Plan became effective on February 12, 1996.
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $773,000,000 in
1995, $982,000,000 in 1994 and $1.04 billion in 1993. Construction
expenditures for the 1996-2000 period are forecasted at $3.5 billion.
These estimates assume clarification of the ambiguity in the restructuring
structure decision as to capital expenditures for fossil generation.
In addition to cash required for construction expenditures for the next
five years as discussed above, $1.4 billion is needed to meet requirements
for long-term debt maturities and sinking fund redemption requirements.
SCE's estimates of cash available for operations for the five years
through 2000 assume, among other things, the receipt of adequate and
timely rate relief and the realization of its assumptions regarding cost
increases, including the cost of capital. SCE's estimates and underlying
assumptions are subject to continuous review and periodic revision.
The timing, type and amount of all additional long-term financing are also
influenced by market conditions, rate relief and other factors, including
limitations imposed by SCE's Articles of Incorporation and Trust
Indenture.
Nuclear Power Matters
SCE's nuclear facilities have been reliable sources of inexpensive, non-
polluting power for SCE's customers for more than a decade. Throughout
the operating life of these facilities, SCE's customers have supported
the revenue requirements of SCE's capital investment in these facilities
and for their incremental costs through traditional cost-of-service
ratemaking.
As discovered above, on January 10, 1996, the CPUC issued its decision for
SCE's Test Year 1995 GRC. The CPUC rejected the settlement agreement in
its original form, but proposed modifications to certain terms and granted
SCE the opportunity to accept the settlement agreement with the proposed
modifications. The CPUC gave SCE 25 days to prepare a detailed proposal
consistent with the policy adopted in its Decision. On February 5, 1996,
SCE filed a revised San Onofre Unit 2 and 3 proposal in which it accepted
the modifications to certain settlement agreement terms as proposed by the
CPUC. Under this Proposal, SCE would recover its remaining investment in
San Onofre Units 2 and 3 at a reduced rate of return (7.34% compared to
the current 9.55%), but on an accelerated basis during the eight-year
period from the effective date in 1996 through December 31, 2003. In
addition, the traditional cost-of-service ratemaking for San Onofre Units
2 and 3 would be superseded by incremental cost incentive pricing, in
which SCE's customers would pay a preset price for each kilowatt-hour of
energy generated at San Onofre during the eight-year period. SCE would
be compensated for the incremental costs required for the continued
operation of San Onofre Units 2 and 3 only with revenues earned through
the incremental cost incentive pricing. However, SCE would also retain
the ability to request recovery of the cost of fuel consumed for
generation of replacement energy for periods in which San Onofre is not
generating power through future ECAC filings. SCE would also continue to
collect funds for decommissioning expenses through traditional ratemaking
treatment. In addition, SCE would continue to receive traditional cost-
of-service ratemaking for its share of Palo Verde Units 1, 2, and 3.
Intervenors filed comments on February 20, 1996, and a final CPUC decision
is expected May 1, 1996.
In the restructuring decision, the CPUC ordered SCE to file an application
by March 29, 1996, requesting a new rate mechanism for its share of the
Palo Verde units to be effective January 1, 1997. On February 29, 1996,
SCE filed its Palo Verde proposal application requesting adoption of a new
rate mechanism for Palo Verde consistent with the San Onofre Units 2 and
3 rate mechanism.
SCE cannot predict what other effects, if any, legislative or regulatory
actions may have upon it or upon the future operation of the San Onofre
or Palo Verde units, or the extent of any additional costs it may incur
as a result thereof, except for those that follow.
San Onofre Unit 1
In August 1992, the CPUC approved a settlement agreement between SCE and
the CPUC's DRA to discontinue operation of San Onofre Unit 1 at the end
of its then-current fuel cycle because operation of the unit was no longer
cost-effective. As part of the agreement, SCE will recover its
investment, earning an 8.98% rate of return on rate base, by August 1996.
In November 1992, SCE discontinued operation of San Onofre Unit 1.
Palo Verde Nuclear Generating Station
On March 14, 1993, Arizona Public Service Company ("APS"), the operating
agent for Palo Verde, manually shut down 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.
APS performed an extensive inspection of the Unit 2 steam generators 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. Subsequent inspections have revealed
similar, though less severe, corrosion in the Unit 1 and Unit 3 steam
generators. APS has taken, and indicates it will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units.
Based on latest available data, APS estimates that the Unit 1 and Unit 3
steam generators should operate for the 40 year licensed operating life
of those units, although APS continues to monitor the situation. APS has
disclosed that it believes it will be economically desirable to replace
the Unit 2 steam generators, which have been most affected by tube
cracking, in five to ten years. APS has indicated to the participants
that it believes that replacement of the Unit 2 steam generators would
cost between $100,000,000 and $150,000,000. SCE estimates that this cost
could be higher, such that its share of this cost would be between
$16,000,000 and $30,000,000, plus replacement power costs. Unanimous
approval of the Palo Verde participants is required for capital
improvements, including steam generator replacement. SCE is evaluating
APS' analyses, conducting its own review, and has not yet decided whether
it supports replacement of the steam generators.
Nuclear Facility Decommissioning
SCE plans to decommission its nuclear generating facilities at the end of
each facility's operating license by a prompt removal method authorized
by the NRC. Decommissioning is estimated to cost $1.8 billion in current-
year dollars based on site-specific studies performed in 1993 for San
Onofre and 1992 for Palo Verde. This estimate considers the total cost
of decommissioning and dismantling the plant, including labor, material,
burial and other costs. The site specific studies are updated
approximately every three years. Changes in the estimated costs, timing
of decommissioning, or the assumptions underlying these estimates could
cause material revisions to the estimated total cost to decommission in
the near term. Decommissioning is scheduled to begin in 2013 at San
Onofre and 2024 at Palo Verde. Currently, San Onofre Unit 1, which shut
down in 1992, is expected to be stored until decommissioning begins at the
other San Onofre units.
SCE is currently collecting $104,381,000 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, 1995, SCE's decommissioning trust
funds totaled approximately $1.260 billion (market value).
Nuclear Facility Depreciation
In October 1994, the CPUC authorized SCE to accelerate recovery of its
nuclear plant investments by $75,000,000 per year through 2011, with a
corresponding deceleration in recovery of its transmission and
distribution assets through revised depreciation estimates over their
remaining useful lives. Recovery of the San Onofre nuclear plant
investment has been further accelerated by the 1995 GRC decision.
Nuclear Insurance
SCE carries Nuclear Property Insurance well in excess of limits required
by Federal law and in amounts determined adequate 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 SCE believes an accident at its nuclear units is extremely
unlikely, in the event of an accident, regardless of fault, SCE's
insurance coverage might be inadequate to cover the losses to SCE. In
addition, such an accident could result in NRC action to suspend operation
of the damaged unit. Further, the NRC could suspend operation at SCE'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 SCE.
Item 3. Legal Proceedings
QF Litigation
On May 20, 1993, four geothermal QFs filed a lawsuit against SCE in Los
Angeles County Superior Court, claiming that SCE underpaid, and continues
to underpay, the plaintiffs for energy. SCE denied the allegations in its
response to the complaint. The action was brought on behalf of Vulcan/BN
Geothermal Power Company, Elmore L.P., Del Ranch L.P., and Leathers L.P.,
each of which is partially owned by a subsidiary of Edison Mission Energy
(a subsidiary of Edison International). In October 1994, plaintiffs
submitted an amended complaint to the court to add causes of action for
unfair competition and restraint of trade. In July 1995, after several
motions to strike had been heard by the court, the plaintiffs served a
fourth amended complaint, which omitted the previous claims based on
alleged restraint of trade. The plaintiffs allege in the fourth amended
complaint that past underpayments have totaled at least $21,000,000. In
other court filings, plaintiffs contend that additional contract payments
owing from the beginning of the alleged underpayments through the end of
the contract term could total approximately $60,000,000. Plaintiffs also
seek unspecified punitive damages and an injunction to enjoin SCE from
"future" unfair competition.
After SCE's motion to strike portions of the fourth amended complaint was
denied, SCE filed an answer to the fourth amended complaint which denies
its material allegations. Trial on the fourth amended complaint is set
for May 15 1996. The materiality of a judgment in favor of the plaintiffs
would be largely dependent on the extent to which additional payments
resulting from such a judgment are recoverable through SCE's ECAC.
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189,000,000 in
damages, which includes consequential damages claimed in seven of the
eight lawsuits. On March 1, 1995, the court in the lead Los Angeles
Superior Court case granted the plaintiffs' motion seeking summary
adjudication that the contract language in question is not reasonably
susceptible to SCE's position that there is only a single, 10-year period
of fixed payments. Following the March 1 ruling, an eighth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first seven. SCE subsequently responded to the complaint
in the new lawsuit by denying its material allegations. On April 5, 1995,
SCE filed a petition for Writ of Mandate, Prohibition of Other Appropriate
Relief, requesting that the Court of Appeal of the State of California,
Second Appellate District issue a writ directing the Los Angeles Superior
Court to vacate its March 1 order granting summary adjudication. In a
decision filed August 9, 1995, the Court of Appeal issued a writ directing
that the order be overturned, and a new order be entered denying the
motion. Trial is currently set in the single Kern County Superior Court
case for April 22, 1996. In the Los Angeles Superior Court cases, the
lead case is set for trial on June 26, 1996, although a motion to
consolidate all of the Los Angeles cases for trial is before the court.
The materiality of final judgments in favor of the plaintiffs would be
largely dependent on the extent to which any damages or additional
payments which might result from such judgments would be recoverable
through SCE's ECAC.
Environmental Litigation
Electric and Magnetic Fields ("EMF")
SCE is involved in three lawsuits alleging that various plaintiffs
developed cancer as a result of exposure to EMF from SCE facilities. SCE
denied the material allegations in its responses to each of these
lawsuits.
The first lawsuit was filed in Orange County Superior Court and served on
SCE in June 1994. There are five named plaintiffs and six named
defendants, including SCE. Three of the five plaintiffs are presently or
were formerly employed by Grubb & Ellis, a real estate brokerage firm with
offices located in a commercial building known as the Koll Center in
Newport Beach. Two of the named plaintiffs are spouses of the other
plaintiffs. Grubb & Ellis and the owners and developers of the Koll
Center are also named as defendants in the lawsuit. This lawsuit alleges,
among other things, that the three plaintiffs employed by Grubb & Ellis
developed various forms of cancer as a result of exposure to EMF from
electrical facilities owned by SCE and/or the other defendants located on
Koll Center property. No specific damage amounts are alleged in the
complaint, but supplemental documentation prepared by the plaintiffs
indicates that plaintiffs allege compensatory damages of approximately $8
million, plus unspecified punitive damages. In December 1995, the court
granted SCE's motion for summary judgment and dismissed the case.
Plaintiffs have filed a Notice of Appeal.
A second lawsuit was filed in Orange County Superior Court and served on
SCE in January 1995. This lawsuit arises out of the same fact situation
as the June 1994 lawsuit described above and involves the same defendants.
There are four named plaintiffs, two of whom were formerly employed by
Grubb & Ellis and now allegedly have various forms of cancer. The other
two plaintiffs are the spouses of those two individuals. No specific
damage amounts are alleged in the complaint, but supplemental
documentation prepared by the plaintiffs indicates that plaintiffs will
allege compensatory damages of approximately $13,500,000, plus unspecified
punitive damages. On April 18, 1995, Grubb & Ellis filed a cross-
complaint against the other co-defendants, requesting indemnification and
declaratory relief concerning the rights and responsibilities of the
parties. Trial date in this case has been set for November 4, 1996.
A third case was filed in Orange County Superior Court and served on SCE
in March 1995. The plaintiff alleges, among other things, that he
developed cancer as a result of EMF emitted from SCE distribution lines
which he alleges were not constructed in accordance with CPUC standards.
No specific damage amounts are alleged in the complaint but supplemental
documentation prepared by the plaintiff indicates that plaintiff will
allege compensatory damages of approximately $5,500,000, plus unspecified
punitive damages. The trial date in this case has been continued to late
1996.
San Onofre Personal Injury Litigation
An engineer for two contractors providing services for San Onofre, was
diagnosed with leukemia. On July 12, 1994, the engineer and his wife sued
SCE and San Diego Gas & Electric Company ("SDG&E"), as well as Combustion
Engineering, the manufacturer of the fuel rods for the plant, in the U.S.
District Court for the Southern District of California. The plaintiffs
alleged that the engineer's illness resulted from contact with the
radioactive fuel particles released from failed fuel rods. Plant records
showed that the engineer's exposure to radiation was well below NRC safety
levels. Plaintiffs sought unspecified compensatory and punitive damages.
SCE's December 23, 1994, answer to the complaint denied all material
allegations. The trial began on August 3, 1995, and on October 12, 1995,
an eight-member jury unanimously decided that radiation exposure at San
Onofre was not the cause of the engineer's leukemia. The court entered
the judgment for the defendants on October 24, 1995. Plaintiffs' motion
for a new trial was denied on December 5, 1995. Plaintiffs have filed an
appeal with the Ninth Circuit Court of Appeals. Oral argument on that
appeal is scheduled for April 11, 1996.
An SCE engineer employed at San Onofre died in 1991 from cancer of the
abdomen. On February 6, 1995, his children sued SCE and SDG&E, as well
as Combustion Engineering, the manufacturer of the fuel rods for the
plant, in the U.S. District court for the Southern District of California.
Plaintiffs alleged that the former employee's illness resulted from, and
was aggravated by, exposure to radiation at San Onofre, including contact
with radioactive fuel particles released from failed fuel rods.
Plaintiffs sought unspecified compensatory and punitive damages. On April
3, 1995, the court granted the defendants' motion to dismiss 14 of the
plaintiffs' claims. SCE's April 20, 1995, answer to the complaint denied
all material allegations. On October 10, 1995, the court granted
plaintiffs' motion to include the Institute of Nuclear Power Operations
(an organization dedicated to achieving excellence in nuclear power
operations) as a defendant in the suit. On December 7, 1995, the judge
granted SCE's motion for summary judgment on the sole outstanding claim
against it, basing his ruling on the worker's compensation system being
the exclusive remedy for the claim. Plaintiffs will appeal this ruling
to the Ninth Circuit Court of Appeals. Trial of the case will be delayed
pending the ruling of the Court of Appeals. The impact to SCE, if any,
from further proceedings in this case against the remaining defendants
cannot be determined at this time.
On July 5, 1995, a former SCE reactor operator and his wife sued SCE and
SDG&E in the U.S. District court for the Southern District of California.
Plaintiffs also named Combustion Engineering, the manufacturer of the fuel
rods for the plant, and the Institute of Nuclear Power Operations as
defendants. The former employee died of leukemia shortly after the
complaint was filed. Plaintiffs allege that the former operator's illness
resulted from, and was aggravated by, exposure to radiation at San Onofre,
including contact with radioactive fuel particles released from failed
fuel rods. Plaintiffs seek unspecified compensatory and punitive damages.
On November 22, 1995, plaintiffs amended their complaint to allege
wrongful death and added the former employee's two children as plaintiffs.
On December 22, 1995, SCE filed a motion to dismiss or, in the
alternative, for summary judgment based on worker's compensation
exclusivity. This motion was heard on March 18, 1996. The court has not
ruled on the motion. If SCE's motion is unsuccessful, it intends to deny
plaintiffs' material allegations.
On August 31, 1995, the wife and daughter of a former San Onofre security
supervisor sued SCE and SDG&E in the U.S. District court for the Southern
District of California. Plaintiffs also named Combustion Engineering, the
manufacturer of fuel rods for the plant, and the Institute of Nuclear
Power Operations as defendants. The security officer worked for a
contractor in 1982, worked for SCE as a temporary employee (1982-1984),
and later worked as an SCE security supervisor (1984-1994). The officer
died of leukemia in 1994. Plaintiffs allege that the former officer's
illness resulted from, and was aggravated by, his exposure to radiation
at San Onofre, including contact with radioactive fuel particles released
from failed fuel rods. Plaintiffs seek unspecified compensatory and
punitive damages. SCE's November 13, 1995, answer to the complaint denied
all material allegations. A trial date will be set at the pretrial
conference that is scheduled for October 7, 1996.
On November 17, 1995, an SCE employee and his wife sued SCE in the U.S.
District Court for the Southern District of California. Plaintiffs also
named Combustion Engineering, the manufacturer of the fuel rods for the
San Onofre plant. The employee worked for SCE at San Onofre from 1981 to
1990. Plaintiffs allege that the employee transported radioactive
byproducts on his person, clothing and/or tools to his home where his wife
was then exposed to radiation that caused her leukemia. Plaintiffs seek
unspecified compensatory and punitive damages. SCE's December 19, 1995,
partial answer to the complaint denied all material non-employment related
allegations. SCE's motion to dismiss the employment related allegations
was heard March 11, 1996. The court has not ruled on the motion. The
plaintiffs' motion for an expedited trial date was denied by the court on
January 16, 1996.
On November 28, 1995, a former contract worker at San Onofre, her husband,
and her son, sued SCE in the U.S. District Court for the Southern District
of California. Plaintiffs also named Combustion Engineering, the
manufacturer of the fuel rods for the San Onofre plant. Plaintiffs allege
that the former contract worker transported radioactive byproducts on her
person and clothing to her home where her son was then exposed to
radiation that caused his leukemia. Plaintiffs seek unspecified
compensatory and punitive damages. SCE's January 2, 1996, answer denied
all material allegations.
Employment Discrimination Litigation
On September 21, 1994, nine African-American employees filed a lawsuit
against Edison International and SCE on behalf of an alleged class of
African-American employees, alleging racial discrimination in job
advancement, pay, training and evaluation. The lawsuit was filed in the
United States District Court for the Central District of California. The
plaintiffs seek injunctive relief, as well as an unspecified amount of
compensatory and punitive damages, attorneys' fees, costs and interest.
Edison International and SCE have responded by denying the material
allegations of the complaint and asserting several affirmative defenses.
The parties are engaged in discovery, and no trial date has been set.
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, 1995 Company Position(2) Date
John E. Bryson 52 Chairman of the Board, October 1, 1990
Chief Executive Officer
and Director
Stephen E. Frank 54 President, Chief Operating June 19, 1995
Officer and Director
Bryant C. Danner 58 Executive Vice President June 1, 1995
and General Counsel
Alan J. Fohrer 45 Executive Vice President, February 15, 1996
Chief Financial Officer
and Treasurer
Harold B. Ray 55 Executive Vice President, June 1, 1995
Generation
Vikram S. Budhraja 48 Senior Vice President, June 1, 1995
Power Grid
Owens F. Alexander 46 Vice President, January 1, 1996
Customer Solutions
Emiko Banfield 49 Vice President, January 1, 1996
Human Resources
Pamela Bass 48 Vice President, January 1, 1996
Shared Services
Richard K. Bushey 55 Vice President and January 1, 1984
Controller
Ronald Daniels 56 Vice President, August 10, 1992
Special Projects
John R. Fielder 50 Vice President, Regulatory February 1, 1992
Policy and Affairs
Bruce C. Foster 43 Vice President, San Francisco January 1, 1995
Regulatory Operations
Robert G. Foster 48 Vice President, Public November 18, 1993
Affairs
Lawrence D. Hamlin 51 Vice President, Power Production February 1, 1992
Thomas J. Higgins 50 Vice President, Corporate April 1, 1995
Communications
R. W. Krieger 47 Vice President, Nuclear June 17, 1993
Generation
J. Michael Mendez 54 Vice President, Regional February 8, 1993
Leadership
Dwight E. Nunn 53 Vice President, Nuclear December 18, 1995
Engineering and Technical
Services
Richard M. Rosenblum 45 Vice President, Distribution January 1, 1996
Beverly P. Ryder 45 Corporate Secretary and January 1, 1996
Special Assistant to the
Chairman/CEO
______________
(1) R. H. Bridenbecker retired from his position as Senior Vice President,
Customer Solutions, on December 31, 1995, and Margaret Jordan resigned
as Vice President, Health Care and Employee Services on February 1,
1996. Georgia Nelson resigned from her position as Senior Vice
President, Performance Support, on January 1, 1996, to become
President of the Americas Division and Senior Vice President of World
Wide Operations for Edison Mission Energy. C. Alex Miller resigned
as Vice President and Treasurer on January 26, 1996, to become
President of Edison Source. Effective January 1, 1996, former
Corporate Secretary Kenneth S. Stewart became Assistant General
Counsel and Assistant Secretary.
(2) Executive officers Bryson, Danner, Fohrer, Banfield, Bushey, Robert
Foster, Higgins, and Ryder hold the same positions with Edison
International. Edison International is the parent holding company of
SCE.
None of SCE's executive officers are related to each other by blood or
marriage. As set forth in Article IV of SCE's Bylaws, the officers of SCE
are chosen annually by and serve at the pleasure of SCE's Board of
Directors and hold their respective offices until their resignation,
removal, other disqualification from service, or until their respective
successors are elected. All of the executive officers have been actively
engaged in the business of SCE for more than five years except for Stephen
E. Frank, Bryant C. Danner, Owens F. Alexander, Bruce C. Foster, Thomas
J. Higgins, Dwight E. Nunn, and Beverly P. Ryder. Those officers who have
not held their present position for the past five years had the following
business experience:
Stephen E. Frank President and Chief Operating Officer, August 1990 to January 1995
Florida Power and Light Company(4)
Bryant C. Danner Senior Vice President and General July 1992 to May 1995
Counsel of Edison International and SCE
Partner with the Law Firm January 1970 to June 1992
of Latham & Watkins(1)(4)
Alan J. Fohrer Executive Vice President and June 1995 to February 1996
Chief Financial Officer of SCE
Senior Vice President, Chief January 1993 to May 1995
Financial Officer and Treasurer
of Edison International
Senior Vice President and Chief January 1993 to May 1995
Financial Officer of SCE
Vice President, Chief Financial April 1991 to January 1993
Officer and Treasurer of Edison
International and SCE
Assistant Treasurer and Manager September 1987 to March 1991
of Cost Control of SCE
Harold B. Ray Senior Vice President, Power Systems June 1990 to May 1995
Vikram S. Budhraja Vice President, Planning and June 1993 to May 1995
Technology
Vice President, System Planning and February 1992 to May 1993
Operations
Vice President, System Planning and April 1991 to January 1992
Fuel Supply
Manager, Electric Systems Planning September 1986 to March 1991
Owens F. Alexander Vice President, Marketing April 1994 to December 1995
South Central Bell and BellSouth
Telecommunications in
Atlanta, Georgia:(4)
Marketing Group Quality Director September 1991 to February 1994
General Manager Customer Service March 1991 to August 1991
General Manager Business Marketing October 1988 to February 1991
Emiko Banfield Manager of Procurement and Material May 1994 to December 1995
Management
Manager of Transportation Services December 1991 to May 1994
Manager of Power Contracts August 1991 to December 1991
Manager of Transmission January 1991 to August 1991
Pamela Bass Division Vice President, ENvest(3) August 1993 to December 1995
Division Vice President,
Customer Services January 1992 to August 1993
Manager of Customer Services November 1989 to December 1991
Ronald Daniels Vice President, Revenue Requirements August 1989 to July 1992
John R. Fielder Vice President, Information Services January 1989 to January 1992
Bruce C. Foster Regional Vice President (San Francisco January 1992 to December 1994
Office)
Vice President, New England January 1990 to December 1991
Electric(4)
Robert G. Foster Regional Vice President (Sacramento January 1988 to October 1993
Office)
Lawrence D. Hamlin Manager, Steam Generation April 1990 to January 1992
Thomas J. Higgins President, The Laurel Company(2)(4) January 1994 to December 1994
Senior Vice President of Blue October 1990 to December 1993
Cross/Blue Shield of Maryland(4)
Russell W. Krieger Station Manager (San Onofre) August 1990 to May 1993
J. Michael Mendez Vice President (Human Resources) August 1991 to January 1993
Division Vice President January 1991 to July 1991
(Customer Solutions)
Dwight E. Nunn Vice President, Tennessee Valley April 1990 to December 1995
Authority(4)
Richard M. Rosenblum Vice President, Engineering and June 1993 to December 1995
Technical Services
Manager of Nuclear Regulatory June 1989 to May 1993
Affairs
Beverly P. Ryder Special Assistant to the Chairman May 1995 to December 1995
of Edison International and SCE
Director, Strategic Alliances, October 1993 to April 1995
EnvestSCE(3)
General Manager, Customer Solutions June 1992 to September 1993
Vice President, Corporate Asset April 1985 to June 1992
Funding, Citibank, N.A.(4)
______________
(1) Prior to leaving the law firm of Latham & Watkins, Mr. Danner was in
the firm's environmental department.
(2) As President of The Laurel Company, Thomas J. Higgins provided advice
on planning and financing for mergers and acquisitions for clients in
the managed health care business.
(3) This entity is a division of SCE.
(4) This entity is not a parent, subsidiary or other affiliate of SCE.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
Certain information responding to Item 5 with respect to frequency and
amount of cash dividends is included in SCE's Annual Report to
Shareholders for the year ended December 31, 1995, ("Annual Report") under
"Quarterly Financial Data" on page 8 and is incorporated by reference
pursuant to General Instruction G(2). As a result of the formation of
a holding company described above in Item 1, all of the issued and
outstanding common stock of SCE is owned by Edison International and there
is no market for such stock.
Item 6. Selected Financial Data
Information responding to Item 6 is included in the Annual Report under
"Selected Financial and Operating Data: 1991-1995" on page 1 and is
incorporated herein by reference pursuant to General Instruction G(2).
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition
Information responding to Item 7 is included in the Annual Report under
"Management's Discussion and Analysis of Results of Operations and
Financial Condition" on pages 2 through 8 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 8 under "Quarterly Financial Data" and on pages 9 through
26 and is incorporated herein by reference pursuant to General Instruction
G(2).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information concerning executive officers of SCE is set forth in Part I
in accordance with General Instruction G(3), pursuant to Instruction 3 to
Item 401(b) of Regulation S-K. Other information responding to Item 10
is included in the Joint Proxy Statement ("Proxy Statement") filed with
the Commission in connection with SCE's Annual Meeting of Shareholders to
be held on April 18, 1996, under the heading "Election of Directors of
Edison International and SCE," 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 Edison International and SCE," 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 Edison International and SCE," 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 Edison International and SCE," 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 1995 Annual Report to Shareholders
are incorporated by reference in this report.
Management's Discussion and Analysis of Results of Operations and
Financial Condition
Consolidated Statements of Income -- Years Ended December 31, 1995,
1994 and 1993
Consolidated Statements of Retained Earnings -- Years Ended December
31, 1995, 1994 and 1993
Consolidated Balance Sheets -- December 31, 1995, and 1994
Consolidated Statements of Cash Flows -- Years Ended December 31, 1995,
1994 and 1993
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
Schedule 25
Schedule II--Valuation and Qualifying Accounts for the Years
Ended December 31, 1995, 1994 and 1993 26
Schedules I through V, except those referred to above, are omitted as not
required or not applicable.
(3) Exhibits
See Exhibit Index on page 30 of this report.
(b) Reports on Form 8-K
November 22, 1995
Item 5: Other Events: Alternate Proposed General Rate Case
Decision
December 14, 1995
Item 5: Other Events: 1995 General Rate Case Proposal
December 21, 1995
Item 5: Other Events: CPUC Restructuring Decision
January 11, 1996
Item 5: Other Events: CPUC 1995 General Rate Case Decision
January 17, 1996
Item 5: Other Events: Sale of 5-7/8% Notes, Due 2001 and 6-3/8%
Notes, Due 2006
February 23, 1996
Item 5: Other Events: 1995 Financial Information
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULE
To Southern California Edison Company:
We have audited in accordance with generally accepted auditing standards
the consolidated financial statements included in the 1995 Annual Report
to Shareholders of Southern California Edison Company (SCE), incorporated
by reference in this Form 10-K, and have issued our report thereon dated
February 2, 1996. 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
schedule listed in Part IV of this Form 10-K which is the responsibility
of SCE's management is presented for purposes of complying with the
Securities and Exchange Commission's rules and regulations, and is not
part of the basic consolidated financial statements. This supplemental
schedule has been subjected to the auditing procedures applied in the
audits of the basic consolidated financial statements and, in our opinion,
fairly states in all material respects the financial data required to be
set forth therein in relation to the basic consolidated financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
February 2, 1996
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1995
Additions
------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
----------- ------------ ---------- ---------- ---------- ---------
(In thousands)
Group A:
Uncollectible accounts --
Customers. . . . . . . . . . . $ 21,000 $ 22,179 $ -- $ 21,053 $ 22,126
All other. . . . . . . . . . . 2,806 801 -- 1,594 2,013
-------- -------- ------- -------- --------
Total. . . . . . . . . . . . $ 23,806 $ 22,980 $ -- $ 22,647(a) $ 24,139
======== ======== ======= ======== ========
Group B:
DOE decontamination
and decommissioning. . . . . . $ 56,485 $ -- $ 1,531(b) $ 5,274(c) $ 52,742
Pension and benefits . . . . . . 174,851 42,805 23,676(d) 44,670(e) 196,662
Insurance, casualty and
other. . . . . . . . . . . . . 79,727 74,751 -- 59,690(f) 94,788
-------- -------- ------- -------- --------
Total. . . . . . . . . . . . $311,063 $117,556 $25,207 $109,634 $344,192
======== ======== ======= ======== ========
_______________
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(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.
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1994
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. . . . . . . . . . . $ 15,664 $ 27,071 $ -- $ 21,735 $ 21,000
All other. . . . . . . . . . . 2,758 1,428 -- 1,380 2,806
-------- -------- ------- -------- --------
Total. . . . . . . . . . . . $ 18,422 $ 28,499 $ -- $ 23,115(a) $ 23,806
======== ======== ======= ======== ========
Group B:
DOE Decontamination
and Decommissioning. . . . . . $ 67,128 $ -- $ (452)(b) $ 10,191(c) $ 56,485
Pension and benefits . . . . . . 131,764 147,037 23,931 (d) 127,881(e) 174,851
Insurance, casualty and
other. . . . . . . . . . . . . 67,703 67,197 -- 55,173(f) 79,727
-------- -------- ------- -------- --------
Total. . . . . . . . . . . . $266,595 $214,234 $23,479 $193,245 $311,063
======== ======== ======= ======== ========
________________
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(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.
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- 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(b) $ -- $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 revision to estimate based on actual billings.
(d) Represents amounts paid.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
By Kenneth S. Stewart
----------------------------------
Kenneth S. Stewart
Assistant General Counsel
Date: March 27, 1996
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 27, 1996
Chief Executive Officer
and Director
Principal Financial Officer:
Alan J. Fohrer* Executive Vice President, March 27, 1996
Chief Financial Officer
and Treasurer
Controller or Principal
Accounting Officer:
Richard K. Bushey* Vice President and March 27, 1996
Controller
Majority of Board of Directors:
Howard P. Allen* Director March 27, 1996
Stephen E. Frank* Director March 27, 1996
Camilla C. Frost* Director March 27, 1996
Joan C. Hanley* Director March 27, 1996
Carl F. Huntsinger* Director March 27, 1996
Luis G. Nogales* Director March 27, 1996
James M. Rosser* Director March 27, 1996
E. L. Shannon, Jr.* Director March 27, 1996
Robert H. Smith* Director March 27, 1996
Thomas C. Sutton* Director March 27, 1996
James D. Watkins* Director March 27, 1996
Edward Zapanta* Director March 27, 1996
Kenneth S. Stewart
*By -----------------------------------------
Kenneth S. Stewart, Attorney-in-fact)
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
3.1 Restated Articles of Incorporation as amended through June
1, 1993 (File No. 1-2313)*
3.2 Bylaws as adopted by the Board of Directors on February 15,
1996
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)*
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)*
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)*
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)*