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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, 1996
--------------------------------------------
Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue (818) 302-1212
Rosemead, California 91770 (Registrant's telephone number,
(Address of principal executive offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Capital Stock
Cumulative Preferred $100 Cumultive Preferred American and Pacific
4.08% Series 4.78% Series 6.05% Series
4.24% Series 5.80% Series 6.45% Series
4.32% Series 7.36% Series 7.23% Series
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of March 21, 1997, there were 419,726,654 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 $518,107,275 on or about March 21, 1997, 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 $229,444,775; $100 CUMULATIVE PREFERRED
STOCK $288,662,500. 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, 1996. . . . . . . . . . . . . . . . . Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement relating to
registrant's 1997 Annual Meeting of Shareholders. . . . . . . Part III
PAGE
TABLE OF CONTENTS
Item Page
- ---- ----
Part I
1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Competitive Environment. . . . . . . . . . . . . . . . . . . . . . 1
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Fuel Supply and Purchased Power Costs. . . . . . . . . . . . . . . 9
Environmental Matters. . . . . . . . . . . . . . . . . . . . . . . 11
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Existing Generating Facilities . . . . . . . . . . . . . . . . . . 13
Construction Program and Capital Expenditures. . . . . . . . . . . 14
Nuclear Power Matters. . . . . . . . . . . . . . . . . . . . . . . 15
3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . 18
QF Litigation. . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Environmental Litigation . . . . . . . . . . . . . . . . . . . . . 19
San Onofre Personal Injury Litigation. . . . . . . . . . . . . . . 20
Employment Discrimination Litigation . . . . . . . . . . . . . . . 21
Oil Pipeline Litigation. . . . . . . . . . . . . . . . . . . . . . 22
4. Submission of Matters to a Vote of Security Holders. . . . . . . . . 22
Executive Officers of the Registrant . . . . . . . . . . . . . . . . 22
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . . . 25
6. Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . 26
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . . . . 26
8. Financial Statements and Supplementary Data. . . . . . . . . . . . . 26
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . 26
Part III
10. Directors and Executive Officers of the Registrant . . . . . . . . . 26
11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . 26
12. Security Ownership of Certain Beneficial
Owners and Management. . . . . . . . . . . . . . . . . . . . . . . . 26
13. Certain Relationships and Related Transactions . . . . . . . . . . . 26
Part IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . 27
Report of Independent Public Accountants on
Supplemental Schedules . . . . . . . . . . . . . . . . . . . . . . . 28
Supplemental Schedules . . . . . . . . . . . . . . . . . . . . . . . 29
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Exhibit Index. . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
PAGE
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 12,057 full-time
employees during 1996. During 1996, 39% of SCE's total operating revenue
was derived from residential customers, 37% from commercial customers, 12%
from industrial customers, 7% 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, its parent holding company.
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 industry.
On September 23, 1996, the State of California enacted legislation to
provide a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision
(discussed below) by addressing stranded-cost recovery for utilities,
providing a certain cost recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, thereby
allowing SCE to give a rate reduction of at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of
a non-bypassable competition transition charge (CTC) that provides
utilities the opportunity to recover costs made uneconomic by electric
utility restructuring. Finally, the legislation contains provisions for
the recovery (through 2006) of reasonable employee-related transition
costs incurred and projected for retraining, severance, early retirement,
outplacement and related expenses for utility workers. In light of the
legislation, the CPUC has indicated that it need not prepare an
environmental impact report in connection with its December 1995
restructuring policy decision.
In December 1995, the CPUC issued its decision on restructuring
California's electric utility industry. The transition to a new market
structure, which is expected to provide competition and customer choice,
would begin January 1, 1998, with all consumers participating by 2003
(changed to 2002 by the recently enacted legislation). Key elements of
the CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
page 1
required to purchase from and sell to the PX all of their power
during the transition period, while other generators could
voluntarily participate.
o Creation of an independent system operator (ISO) to have
operational control of the utilities' transmission facilities and,
therefore, control the scheduling and dispatch of all electricity
on the state's power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission
arrangements through the system operator, and customer-arranged
"contracts for differences" to manage price fluctuations from the
PX.
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the
existing framework and reasonable employee-related costs) through
a non-bypassable charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture
(through spin-off or sale to an unaffiliated entity) of at least
50% of utilities' gas-fueled generation to address market power
issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the FERC regarding the creation of
the PX and the ISO. On November 26, 1996, the FERC conditionally accepted
the proposal and directed the three utilities to file more specific
information by March 31, 1997. In July 1996, the three utilities jointly
filed an application with the CPUC requesting approval to establish a
restructuring trust which would obtain loans up to $250 million for the
development of the ISO and PX through January 1, 1998. The loans would
be backed by utility guarantees; SCE's share would be 45%. Once the ISO
and PX are formed, they will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million which will be used to build the hardware and software
systems for the ISO and PX.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, transmission and distribution (T&D), nuclear decommissioning and
public benefit programs). Nevertheless, the CPUC directed that the
amended application provide estimates of SCE's potential transition costs
from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value), assuming the fossil plants have
a market value equal to their net book value, and $13.8 billion (1998 net
present value), assuming the fossil plants have no market value. These
estimates are based on incurred costs, and forecasts of future costs and
assumed market prices. However, changes in the assumed market prices
could materially affect these estimates. The potential transition
cost estimates are comprised of: $7.5 billion from SCE's qualifying
facility contracts, which are the direct result of legislative and
regulatory mandates; and $5.6 billion to $6.3 billion from costs
pertaining to certain generating plants and regulatory commitments
page 2
consisting of costs incurred (whose recovery has been deferred by the
CPUC) to provide service to customers. Such commitments include the
recovery of income tax benefits previously flowed-through to customers,
postretirement benefit transition costs, accelerated recovery of San
Onofre and Palo Verde and certain other costs. An update to the CTC was
filed by SCE on February 14, 1997, to reflect approval by the CPUC of
settlements regarding ratemaking of SCE's share of the Palo Verde Nuclear
Generating Station and the buyout of a power purchase agreement with
Portland General Electric, as well as other minor data updates. No
substantive changes in the total CTC estimates were included.
On November 27, 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil-and gas-fueled generation
divestiture was requested for late 1997.
In September 1996, the CPUC adopted a non-generation T&D PBR mechanism for
SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion controlled by the ISO is to
be separated from non-generation PBR and subject to ratemaking under the
rules of the FERC. The distribution-only PBR will extend through December
2001. Key elements of the non-generation PBR include: T&D rates indexed
for inflation based on the Consumer Price Index less a productivity
factor; elimination of the kilowatt-hour sales adjustment; adjustments for
cost changes that are not within SCE's control; a cost of capital trigger
mechanism based on changes in a bond index; standards for service
reliability and safety; and a net revenue-sharing mechanism that
determines how customers and shareholders will share gains and losses from
T&D operations. In July 1996, SCE filed a PBR proposal for its
hydroelectric plants and a proposed structure for performance-based local
reliability contracts for certain fossil-fueled plants. If approved, the
hydro PBR would be in effect for three years and the initial terms of the
local reliability contracts, which are subject to FERC approval, would be
in effect for up to three years, both beginning January 1, 1998. A final
CPUC decision on hydro PBR is expected by year-end 1997.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public benefit programs and the CTC. The filing was in
response to CPUC and FERC directives which require electric services, such
as T&D, to be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers. On
December 6, 1996, SCE filed a more comprehensive plan for the functional
unbundling of SCE's rates for electric service, beginning on January 1,
1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates in separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The filing also included proposals for
establishing new regulatory proceedings to replace current proceedings
that will no longer be necessary during the rate freeze period.
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
page 3
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have write-offs
associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
Subsequent Event
If the CPUC's restructuring is implemented as outlined, SCE would be
allowed to recover its CTC (subject to a lower return on equity) and
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996, SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and its
independent accountants continue to believe that SCE meets such criteria
and met with the SEC staff in March 1997 and presented additional and
clarifying information seeking to convince the SEC staff of the merits of
SCE's position. Following the meeting, the SEC staff submitted additional
questions to SCE and the other major California electric utilities. The
companies are preparing responses for submittal to the SEC staff. The
authority to require SCE to discontinue applying regulatory accounting
standards rests with the SEC. If SCE is required to discontinue the
application of these accounting standards for its generation-related
assets, it would have to write off generation-related regulatory assets,
which at December 31, 1996, totaled approximately $600 million on an
after-tax basis, primarily for the recovery of income tax benefits
previously flowed-through to customers, the Palo Verde phase-in plan and
unamortized loss on reacquired debt.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
Unbundling of Distribution Services
On October 25, 1996, the CPUC issued an Order directing SCE to submit
comments on, and cost estimates for, providing metering, billing, and
related customer services. The CPUC issued the Order in connection with
its ongoing investigation of the policies governing the restructuring of
page 4
California's electric services industry. The purpose of this aspect of
the CPUC's investigation is to determine the extent to which, if at all,
nonutility energy service providers should be allowed to offer metering,
billing, and related customer services, which currently are provided
exclusively by SCE as part of its franchise service obligation. Such
"unbundling" would expose SCE to potential financial losses in these
services, potential stranded costs and create the potential for reduced
revenue security. SCE submitted comments in compliance with the CPUC's
Order on December 20, 1996. SCE submitted further comments on January 21,
1997 and February 7, 1997. The CPUC held a full-panel hearing on these
matters on January 15, 1997, following which the Administrative Law Judge
issued a proposed decision recommending that the CPUC "unbundle" metering
and billing services in early 1998. SCE filed opening comments on the
proposed Decision on March 6, 1997; on March 11, SCE submitted reply
comments. The CPUC is expected to issue a decision setting forth its
proposed policies in the second quarter of 1997. The CPUC is not bound
by the proposed decision: they may accept it in whole or part, or may
reject it and consider the matter further. Due to the uncertainty
surrounding any future policies the CPUC may adopt with respect to
unbundling, SCE is unable to provide an estimate of the potential
financial impact of such policies.
Automated Meter Reading Proposal
SCE is developing a pilot automated meter reading (AMR) network capable
of reading 20-50,000 meters at the cost of $12 million. The installation
is underway and should be completed in 1997. If successful, SCE expects
to proceed with full-scale deployment to 85 percent (3.6 million) of its
customers. The full project would start in late 1997 and take four years
to complete at an estimated capital cost of $350 million. The AMR system
would allow SCE to read meters from a remote location and enable customers
to respond to hourly price signals envisioned by electric restructuring
beginning in January 1, 1998. Some of these costs would be offset by
savings in operations and maintenance expenses, due to the reduction of
manual meter reading. The net cost is expected to be approximately $75
million. On December 20, 1996, as part of its comments on unbundling (see
above), SCE presented its AMR proposal to the CPUC. In the comments, SCE
proposed the net cost of the project would be included in rates after the
rate freeze required by Assembly Bill 1890 in 2002. As previously noted,
SCE is expecting a CPUC decision concerning the unbundling of revenue
cycle services and its AMR proposal in the second quarter of 1997.
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
page 5
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 under
Competitive Environment) 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'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. During recent ECAC periods, in excess
of $2.5 billion in costs arising from such contracts has annually been
submitted for CPUC review. 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.
page 6
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 capacity factor). 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 CPUC also modified the NUIP for
Palo Verde Units 1, 2 and 3. The NUIP for Palo Verde will continue
through December 31, 2001, for purposes of calculating a reward only. The
current NUIP period, which would have included the average of Fuel Cycles
6 and 7, was adjusted for Palo Verde to include only Fuel Cycle 6. If any
of the three Palo Verde units operate above an 80% Gross Capacity Factor
(GCF) for a subsequent fuel cycle within the period, the NUIP reward will
be calculated based on the difference between the additional variable cost
and the market price (or replacement power cost until the market becomes
operational) for the output above an 80% GCF. Any NUIP reward based upon
a fuel cycle not completed by December 31, 2001 will be calculated on a
pro-rata basis ending November 1, 2001.
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.
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 million 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, was
reduced by $338 million or 4.4%. SCE was required to credit customer
bills in June 1996 and did refund the $237 million overcollection referred
to above.
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 Office
of Ratepayer Advocates ("ORA") 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; (2)
disallowances of $5,904,143 for the 1992 record period and $5,007,701 for
the 1991 record period regarding QF sales of energy that exceed the
nameplate ratings specified by the QF in Interim Standard Offer No. 4
(ISO4) contracts and negotiated contracts containing similar payment
provisions; and (3) disallowances of $21,150 for the 1992 record period
and $21,751 for the 1991 record period relating to purchases of as-
available capacity from QFs in excess of the nameplate ratings specified
by the QF in ISO4 and similar contracts. 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
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA 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 $13.3 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding SCE's
page 7
Canadian supply and transportation agreements reasonable for the duration
of their terms and that the costs under these contracts be reviewed on a
yearly basis. In October 1996, the ALJ consolidated the hearings for gas
reasonableness issues in A. 95-05-049 covering the period April 1, 1994
through March 31, 1995 with the 1994 Application. ORA has recommended a
disallowance of $37.5 million for excessive costs for the 1995 record
period. If formation of these contracts is not found reasonable by the
CPUC, any costs found unreasonable would be disallowed in subsequent
record periods. An adverse ruling by the CPUC on contract reasonableness
could also affect SCE's future recovery of any termination costs
associated with these contracts. SCE and ORA have filed several rounds
of testimony on this issue. Hearings began in January 1997 and concluded
in February 1997. A decision is expected in late 1997.
1995 Annual ECAC Application
SCE filed its Reasonableness of Operations testimony on May 26, 1996. The
non-QF report addresses power purchases and exchanges, and the operation
of hydro, coal, gas and nuclear resources for the period April 1, 1994,
through March 31, 1995. In May 1996, the ORA issued its reasonableness
report on several reasonableness issues. The Report recommends a
$6,623,936 disallowance for replacement fuel expenses associated with 64
outage days due to the Palo Verde Nuclear Generating Station Unit 2 steam
generator tube rupture in 1993. In February 1997, SCE filed its rebuttal
testimony addressing these issues. No schedule has been set for the
reasonableness phase.
On October 4, 1996, the ORA issued its report on SCE's Canadian gas
procurement contracts discussed above. The report recommends a $37.6
million disallowance for the period April 1994 through March 1995. On
October 17, 1996, the ALJ consolidated the gas reasonableness issues into
the 1994 ECAC proceeding. SCE filed rebuttal testimony on December 31,
1996. Hearings on this matter began in January 1997 and concluded in
February 1997. A decision is expected in late 1997.
Mohave Generating Station
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the ORA which
resulted in a $39 million (including interest) refund to SCE's customers.
The refund, which had been previously reserved, was completed by year-end
1996.
FERC Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission effective July 1996. The FERC issued an order
reaffirming its basic determinations, clarifying certain terms, and making
several changes in March 1997. The decision requires all electric
utilities subject to the FERC's jurisdiction to file transmission tariffs
which provide competitors with increased access to transmission facilities
for wholesale transactions and also establishes information requirements
for the transmission utility. The April 1996 decision, affirmed in the
March 1997 decision, also provides utilities with the recovery of stranded
costs, which are prior-service costs incurred under the current regulatory
framework. In addition to providing recovery of stranded costs associated
with existing wholesale customers, the FERC directed that it would have
primary jurisdiction over the recovery of stranded costs associated with
retail-turned-wholesale customers (e.g., a new municipal electric system),
although the FERC did clarify that it does not intend to prevent or
interfere with the authority of a state and that it has discretion to
defer to a state stranded cost calculation method. Also in the March 1997
decision, the FERC expanded its authority on stranded cost recovery
associated with retail-turned-wholesale customers to include municipal
annexations. Retail stranded costs resulting from a state-authorized
page 8
retail direct-access program are the responsibility of the states and the
FERC would only address recovery of these costs if the state has no
authority to do so. However, the FERC clarified that it will not
entertain such requests if a state regulatory authority has addressed such
costs, regardless of whether the state regulatory authority has allowed
full recovery, partial recovery, or no recovery. In compliance with the
April 1996 FERC decision, SCE filed a revised open access tariff with the
FERC in July 1996. The tariff became effective, on an interim basis,
subject to refund, as of its filing date. The FERC accepted SCE's
compliance filing in February 1997. SCE will revise its tariff to reflect
the few revisions set forth in the March 1997 order.
Palo Verde Ratemaking Proposal
On December 20, 1996, the CPUC issued a final decision on SCE's proposal
for a new rate mechanism for its 15.8% share of the three units at Palo
Verde. The decision adopts the Palo Verde All-Party Settlement filed with
the CPUC on November 15, 1996. The settlement was based on a Memorandum
of Understanding signed by all of the active parties to the Palo Verde
proceeding. Under the settlement, SCE has the opportunity to recover its
remaining investment (approximately $1.2 billion) in Palo Verde beginning
January 1, 1997, and ending December 31, 2001, earning a reduced rate of
return on rate base of 7.35% instead of the current 9.49%. Also, SCE will
utilize a balancing account to pass through Palo Verde's incremental
operating costs (considered reasonable so long as they do not exceed 30%
of a baseline forecast and the site's gross annual capacity factor does
not go below 55%) to ratepayers. Beginning January 1, 1998, this
balancing account will become part of the CTC mechanism. If SCE's actual
costs are less than the forecast, the difference will benefit ratepayers
as a credit to the CTC mechanism. After 2001, SCE's ratepayers will
receive 50% of the benefits derived from the operation of Palo Verde.
Workforce Reductions
During 1996, SCE offered a voluntary retirement program to certain
eligible employees. Approximately 3,000 employees (2,200 non-represented
and 800 represented employees) accepted the terms of this program. After
allowance for the effects of pension settlement gains, SCE's net expense
for this program was $4 million.
Proposed New Accounting Standard
During 1996, the Financial Accounting Standards Board issued an exposure
draft, that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for decommissioning of its nuclear power plants, obligations for coal mine
reclamation costs, and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft, even after deregulation, would
have an adverse effect on its results of operations due to its current and
expected future ability to recover these costs through customer rates.
Fuel Supply and Purchased Power Costs
Fuel and purchased-power costs were approximately $3.3 billion in 1996,
a 4.4% increase over 1995.
SCE's sources of energy during 1996 were: purchased power 45%; natural
gas 15%; nuclear 21%; coal 12%; and hydro 7%.
page 9
Average fuel costs, expressed in cents per kilowatt-hour, for the year
ended December 31, 1996, were: oil, 7.67 cents; natural gas, 2.94 cents;
nuclear, 0.48 cents; and coal, 1.37 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 55% 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) . . . . . . . . . . . . . . . . . . . 2003
Conversion. . . . . . . . . . . . . . . . . . . . . . . . . . 2003
Enrichment. . . . . . . . . . . . . . . . . . . . . . . . . . 2003
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . 2005
Spent fuel storage(2) . . . . . . . . . . . . . . . . . . . . 2006/2006
_______________
(1) Assumes the San Onofre participants meet their supply obligations in
a timely manner.
(2) Assumes full utilization of expanded on-site storage capacity and
normal operation of the units, including interpool transfers and
maintaining full-core reserve. To supplement existing spent fuel
storage, a contingency plan is being developed to construct additional
on-site storage capacity with initial operation scheduled for no later
than 2005. 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 will not be able to meet the 1998
date to start accepting spent nuclear fuel and has requested
stakeholder input as to the best course of action to accommodate the
delay.
page 10
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 1997 from existing contracts.
Contracts cover requirements to provide conversion and fabrication through
2016, and enrichment through 2002.
Palo Verde on-site spent fuel storage capacity will accommodate needs
through 1999 while maintaining full-core offload reserve. Planned
modifications will extend storage capacities with full-core reserve
through 2004 for Units 1 and 2 and through 2005 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, 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 1997
Air Quality Management Plan ("AQMP") Update, adopted in November 1996,
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 has installed the
required NOx controls in Ventura County.
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 Environmental Protection Agency ("EPA") and
SCE will conclude a cooperative tracer study of SO2 emissions from the
Mohave Coal Generating Station in late 1997 or mid- to late- 1998. 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
page 11
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 by EPA 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.
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 Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use and disposal of
polychlorinated biphenyls, a toxic substance used in certain electrical
equipment ("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 55 identified
sites was $114 million at December 31, 1996. 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
page 12
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 $211 million. 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 35 of its
sites, representing $101 million of SCE's 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 successfully settled insurance claims with all responsible
carriers. Costs incurred at SCE's remaining 20 sites are expected to be
recovered through customer rates. SCE has recorded a regulatory asset of
$104 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can be made for these sites 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 million to $8 million. Recorded costs for 1996 were $7
million.
Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not have a
material adverse effect on its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
SCE's total capital expenditures for environmental protection for the
years 1997 through 2001 are projected to be $900 million. These
expenditures are mainly for aesthetics treatment, including undergrounding
certain transmission and distribution lines.
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 1996, the
existing SCE-owned generating capacity (summer effective rating) was
comprised of approximately 65% gas, 15% nuclear, 11% coal, 8%
hydroelectric and 1% oil.
page 13
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 1997 and 2026. 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 59.1
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 1996, SCE's peak demand was 18,207 MW, set on August 14, 1996. Total
area system operating capacity of 21,602 MW was available to SCE at the
time of the 1996 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 $3.7 billion principal amount was outstanding at
December 31, 1996. 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.
SCE Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $616 million in
1996, $773 million in 1995, and $982 million in 1994. Construction
expenditures for the 1997-2001 period are forecasted at $3.4 billion.
page 14
In addition to cash required for construction expenditures for the next
five years as discussed above, $1.8 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 2001 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.
On January 10, 1996, the CPUC's decision for SCE's Test Year 1995 GRC
rejected a settlement agreement proposed by SCE, San Diego Gas & Electric
(SDG&E) and ORA in its original form, but proposed modifications to
certain terms related and granted SCE the opportunity to accept the
portion of the settlement agreement related to San Onofre Units 2 and 3
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. The CPUC adopted the revised proposal on
April 10, 1996. Under this Proposal, SCE would have recovered its
remaining investment in San Onofre Units 2 and 3 at a reduced rate of
return (7.35% 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. Under AB 1890, however, the recovery of the San Onofre
remaining investment must be completed by December 31, 2001. In addition,
the traditional cost-of-service ratemaking for San Onofre Units 2 and 3
was superseded by incremental cost incentive pricing (ICIP), 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. AB 1890 expressly
allowed continuation of ICIP pricing through December 31, 2003, the end
of the eight-year period. SCE was compensated for the incremental costs
required for the continued operation of San Onofre Units 2 and 3 only with
revenues earned through the ICIP. However, SCE also retained the ability
to request recovery of the cost of fuel consumed for generation of
replacement energy for periods in which San Onofre is not generating power
through future ECAC filings. SCE would also continue to collect funds for
decommissioning expenses through traditional ratemaking treatment.
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. On November 15, 1996, SCE, ORA and TURN, entered into
a settlement agreement regarding SCE's Palo Verde Proposal Application.
The settlement retained SCE's proposal to recover its remaining investment
in the Palo Verde units by December 31, 2001 at a reduced rate of return
(7.35% compared to the current 9.55%) consistent with Assembly Bill 1890,
but modified SCE's proposed Palo Verde rate mechanism. Instead of
receiving a preset price for each kilowatt-hour of energy generated during
that period, as proposed, the settling parties agreed that SCE would
page 15
recover its share of Palo Verde incremental operating costs, except if
those costs exceed 95% of the levels forecast by SCE in its application
by more than 30% in any given year. In that case, SCE must demonstrate
that the aggregate amount of the costs exceeding the forecast in that year
are reasonable. In addition, if the annual Palo Verde site Gross Capacity
Factor (GCF) is less than 55% in a calendar year, SCE will bear the burden
of proof to demonstrate that the site's operations causing the GCF to fall
below 55% were reasonable in that year. If operations are determined to
be unreasonable by the CPUC, SCE's replacement power purchases associated
with that period of Palo Verde operations below 55% GCF may be disallowed.
The CPUC approved the settlement agreement on December 20, 1996.
Beginning in 2002, power from Palo Verde Units 1, 2 and 3 will be sold at
the then-current market prices with 50% of the benefits of such operation
given to customers. Likewise, beginning in 2004, power from San Onofre
Units 2 and 3 will be sold at the then-current market prices with 50% of
the benefits of such operation given to customers.
San Onofre Nuclear Generating Station
In August 1992, the CPUC approved a settlement agreement between SCE and
the CPUC's ORA to discontinue operation of Unit 1 at the end of its then-
current fuel cycle. As part of the agreement, SCE recovered its remaining
investment over a four-year period ending August 1996, earning an 8.98%
rate of return on rate base. In November 1992, SCE discontinued operation
of Unit 1.
The Units 2 and 3 steam generators have performed relatively well through
the first 15 years of operation, with low rates of ongoing tube
degradation. During the most recent Unit 2 refueling and inspection
outage, however, an increased rate of degradation was identified,
resulting in removing 1.8% of the tubes from service. The cumulative
total of Unit 2's tubes removed from service is now 5.5%, well below the
maximum 10% allowed in the steam generator design before the rating
capacity of the unit must be reduced. As a result of the increased
degradation, a mid-cycle inspection outage will be conducted in 1998 for
Unit 2. Depending on the results of a forthcoming refueling and
inspection outage for Unit 3, a mid-cycle inspection outage may be
required in 1998 for that unit also.
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 million and $150 million. SCE estimates that this cost
could be higher, such that its share of this cost would be between $16
million and $30 million plus replacement power costs. Unanimous approval
page 16
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
With the exception of San Onofre Unit 1, SCE plans to decommission its
nuclear generating facilities at the end of each facility's operating
license by a prompt removal method authorized by the NRC. Currently, San
Onofre Unit 1, which shut down in 1992, is expected to be stored until
decommissioning begins at the other San Onofre units. Decommissioning is
estimated to cost $2.0 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.
Decommissioning costs, which are recovered through customer rates, are
recorded as a component of depreciation expense. Decommissioning expense
was $148 million in 1996, $151 million in 1995 and $122 million in 1994.
The accumulated provision for decommissioning was $949 million at December
31, 1996, and $823 million at December 31, 1995. The estimated costs to
decommission San Onofre Unit 1 ($263 million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Nuclear Facility Depreciation
In October 1994, the CPUC authorized SCE to accelerate recovery of its
nuclear plant investments by $75 million 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 and Palo Verde nuclear
plant investment has been further accelerated by the 1995 GRC decision,
industry restructuring, legislation, and the Commission's decision
adopting the Palo Verde Settlement.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased
the maximum private primary insurance available ($200 million). The
balance is covered by the industry's retrospective rating plan that uses
deferred premium charges to every reactor licensee if a nuclear incident
at any licensed reactor in the U.S. results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary
level, effective June 1994. The maximum deferred premium for each nuclear
incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its
ownership interests, SCE could be required to pay a maximum of $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such premium amounts include
a 5% surcharge if additional funds are needed to satisfy public liability
claims and are subject to periodic adjustment for inflation. If the
public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a
possible additional assessment on all licensed reactor operators.
page 17
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500 million
has also been purchased in amounts greater than federal requirements.
Additional insurance covers part of replacement power expenses during an
accident-related nuclear unit outage. These policies are issued primarily
by mutual insurance companies owned by utilities with nuclear facilities.
If losses at any nuclear facility covered by these arrangements were to
exceed the accumulated funds for these insurance programs, SCE could be
assessed retrospective premium adjustments of up to $34 million per year.
Insurance premiums are charged to operating expense.
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 was partially owned by a subsidiary of Edison Mission Energy
(a subsidiary of Edison International) at the time of filing. In April
1996, Edison Mission Energy's 50% share in these projects was sold to
CalEnergy. 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 million. 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 million. 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.
On May 1, 1996, the parties entered into an agreement for a settlement of
all claims in dispute. Pursuant to the agreement, the specific terms of
which are confidential, a settlement amount has been paid and the parties
have entered into mutual general releases, with respect to the period
before January 1, 1996. The Company intends to seek recovery of this
payment through rates. The Company has also agreed, subject to CPUC
approval, to increase payments to plaintiffs for specified levels of
energy deliveries for the period after December 31, 1995. Plaintiffs have
reserved the right to continue the litigation with respect to the period
after December 31, 1995, if CPUC approval is not obtained. On August 8,
1996, the Company filed its application with the CPUC for approval of the
settlement as it pertains to the period after 1995. On December 20, 1996,
the ORA filed a protest to the application. In its protest, the ORA
requests that the CPUC not grant the application or, in the alternative,
that the CPUC conduct hearings on the application. On January 17, 1997,
the Company filed a reply to the ORA's request. On February 27, 1997, a
prehearing conference was held, at which time SCE's application was set
for hearing to commence on April 23, 1997.
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
page 18
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 million 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, a ninth lawsuit was
filed in the Los Angeles Superior Court raising claims similar to those
alleged in the first eight. 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 or 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. In light of the Court of Appeal decision in the lead Los Angeles
case, a summary adjudication motion in the Kern County case was withdrawn.
Furthermore, pursuant to stipulation of the parties, the Kern County case
was ordered on April 3, 1996, to be coordinated with the Los Angeles cases
so that it too will be tried in Los Angeles. On March 25, 1996, pursuant
to a court-approved stipulation, all but one of the cases were
consolidated for trial in Los Angeles Superior Court. Trial on the
consolidated cases is set to begin on March 11, 1997. No trial date has
been set in the ninth unconsolidated case.
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. Briefs have been submitted but
no date for oral argument has been set.
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 $13.5 million, plus
unspecified punitive damages. On April 18, 1995, Grubb & Ellis filed a
page 19
cross-complaint against the other co-defendants, requesting
indemnification and declaratory relief concerning the rights and
responsibilities of the parties. This case has been stayed pending
appellate review of the trial judge's sanction order against the
plaintiffs' attorneys. The Court of Appeals has heard oral argument on
this issue, but no decision has been issued.
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 $5.5 million, plus
unspecified punitive damages. No trial date has been set in this case.
San Onofre Personal Injury Litigation
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 court
granted SCE's motion for summary judgment on the sole outstanding claim
against it, basing the ruling on the worker's compensation system being
the exclusive remedy for the claim. Plaintiffs have appealed this ruling
to the Ninth Circuit Court of Appeals. All trial court proceedings have
been stayed 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, the complaint was amended 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. On March 25,
1996, the court granted SCE's motion for summary judgment. Plaintiffs
have appealed this ruling to the Ninth Circuit Court of Appeals. All
trial court proceedings have been stayed pending the ruling of the Court
of Appeals in this case and in the case described in the above paragraph.
The impact to SCE, if any, from further proceedings in this case against
the remaining defendants cannot be determined at this time.
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),
page 20
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. All trial court proceedings have been stayed
pending the rulings of the Court of Appeals in the cases described in the
above two paragraphs.
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 alleged 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 employee's employment related
allegations based on worker's compensation exclusivity was granted on
March 19, 1996. The employee's wife died on August 15, 1996. On
September 20, 1996, the complaint was amended to allege wrongful death and
to add the employee's two children as plaintiffs. The trial is expected
to begin in August 1997.
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. On August 12, 1996, the Court dismissed the
claims of the former worker and her husband with prejudice. The case is
expected to go to trial in late 1997.
Employment Discrimination Litigation
On September 21, 1994, nine African-American employees filed a lawsuit
against Edison International and SCE on behalf of a 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
sought injunctive relief, as well as an unspecified amount of compensatory
and punitive damages, attorneys' fees, costs and interest. Edison
International and SCE responded by denying the material allegations of the
complaint and asserting several affirmative defenses.
Simultaneous with discovery, the parties entered into settlement
discussions. The parties agreed to include the Equal Employment
Opportunity Commission (EEOC) in their settlement discussions after that
agency indicated its intent to intervene in the lawsuit in support of the
plaintiffs. The parties and EEOC agreed upon settlement terms and
submitted a proposed Consent Decree to the court for approval. After
certain issues raised by the court were addressed through a modification
of the proposed Decree, the court granted preliminary approval of the
modified Consent Decree on August 5, 1996, ordered that notice be given
to the class members, and scheduled a final fairness hearing on September
26, 1996.
Fifteen individuals and an organization filed timely objections to the
proposed Consent Decree and a motion to intervene in the lawsuit.
Thirteen individuals filed timely requests to be excluded from the
monetary provisions of the proposed Decree. On September 25, 1996, the
court denied the motion to intervene. After the hearing on September 26,
page 21
at which the court heard oral argument from the objectors, the court on
September 30, 1996, overruled the objections and granted final approval
of the Consent Decree.
The Decree provides that a settlement fund of $8.15 million for back pay
claims and $3.1 million for emotional distress claims be established, and
it contains an expedited claim review process for class members who make
claims to the settlement fund. The Decree also provides for improvements
in the Company's internal claims resolution process, expansion of career
development and skills training programs, expansion of diversity training
programs, and improvements in other human resources systems. The Decree
has a seven-year term, with the possibility of early termination after
five years.
On October 25, 1996, the organization and individuals who sought to
intervene and/or object to the Consent Decree served notice of appeal from
the court's orders denying intervention and approving the Consent Decree.
The Court of Appeals ordered that the appellants file their opening brief
by March 12, 1997, and that appellees file any responsive brief by
April 11, 1997. Appellants have moved for an extension of time to file
their opening brief, but that motion has not been ruled upon and
appellants have not yet filed their brief.
Oil Pipeline Litigation
On November 1, 1996, plaintiff, a crude oil pipeline company, filed a
lawsuit against SCE and the City of Los Angeles (the "City") in the United
States District Court for the Central District of California claiming that
SCE and the City had interfered with its attempt to construct a proposed
132-mile oil pipeline ("Pacific Pipeline") designed to transport oil from
the San Joaquin Valley and Santa Barbara to the Los Angeles refineries.
Plaintiff alleges, among other things, that SCE and the City wrongfully
initiated administrative and other legal proceedings in an attempt to
derail and obstruct the construction of the Pacific Pipeline. Plaintiff
alleges that these acts constitute unfair competition, tortious
interference with economic advantage and violate state and federal
antitrust laws. Plaintiff further claims that because of the alleged
delays, it could suffer losses in excess of $300 million. Additionally,
plaintiff seeks treble and punitive damages.
The deadling for filing a response to the complaint has been continued
pending the outcome of a motion by plaintiff filed in a related lawsuit
seeking to dismiss the City of Los Angeles' complaint therein against the
U.S. Forest Service and plaintiff. SCE intends to deny the substantive
allegations of the complaint.
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, 1996 Company Position(2) Date
- ----------------- -------- ------------------- ---------
John E. Bryson 53 Chairman of the Board, October 1, 1990
Chief Executive Officer
and Director
Stephen E. Frank 55 President, Chief Operating June 19, 1995
Officer and Director
page 22
Bryant C. Danner 59 Executive Vice President June 1, 1995
and General Counsel
Alan J. Fohrer 46 Executive Vice President September 1, 1996
and Chief Financial Officer
Harold B. Ray 56 Executive Vice President, June 1, 1995
Generation Business Unit
Vikram S. Budhraja 49 Senior Vice President, June 1, 1995
Power Grid Business Unit
Robert G. Foster 49 Senior Vice President, November 21, 1996
Public Affairs
Emiko Banfield 50 Vice President, July 22, 1996
Shared Services
Pamela A. Bass 49 Vice President, Customer June 1, 1996
Solutions Business Unit
Richard K. Bushey 56 Vice President and January 1, 1984
Controller
Theodore F. Craver, Jr. 45 Vice President and September 1, 1996
Treasurer
John R. Fielder 51 Vice President, Regulatory February 1, 1992
Policy and Affairs
Bruce C. Foster 44 Vice President, San Francisco January 1, 1995
Regulatory Affairs
Lillian R. Gorman 43 Vice President, July 22, 1996
Human Resources
Lawrence D. Hamlin 52 Vice President, February 1, 1992
Power Production
Thomas J. Higgins 51 Vice President, Corporate April 1, 1995
Communications
R. W. Krieger 48 Vice President, Nuclear June 17, 1993
Generation
J. Michael Mendez 55 Vice President, February 10, 1997
Labor Relations
Dwight E. Nunn 54 Vice President, Nuclear December 18, 1995
Engineering and Technical
Services
Frank J. Quevedo 52 Vice President, June 1, 1996
Equal Opportunity
Richard M. Rosenblum 46 Vice President,
Distribution Business Unit January 1, 1996
Beverly P. Ryder 46 Corporate Secretary and January 1, 1996
Special Assistant to the
Chairman/CEO
______________
(1) Ron Daniels, Vice President of Special Projects, retired on April 1,
1996. On June 1, 1996, Owens F. Alexander left his position as SCE
Vice President of Customer Solutions, to become Senior Vice President
for Edison Source.
On June 1, 1996, Pamela A. Bass became Vice President of Customer
Solutions Business Unit and Frank J. Quevedo was elected Vice
President of Equal Opportunity. On July 22, 1996, Emiko Banfield
page 23
became Vice President of Shared Services, and Lillian R. Gorman was
elected Vice President of Human Resources. Theodore F. Craver, Jr.
was elected Vice President and Treasurer on September 1, 1996. On
November 21, 1996, Robert G. Foster was elected Senior Vice President
of Public Affairs. On February 10, 1997, J. Michael Mendez became
Vice President of Labor Relations.
(2) Executive officers Bryson, Danner, Fohrer, Robert Foster, Bushey,
Craver, Gorman, 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, Theodore F. Craver, Jr., Bruce C. Foster,
Lillian R. Gorman, Thomas J. Higgins, Dwight E. Nunn, Frank J. Quevedo 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, Chief February 1996 to August 1996
Financial Officer and Treasurer
of SCE
Executive Vice President and May 1995 to January 1996
Chief Financial Officer of SCE
Executive Vice President, Chief May 1995 to August 1996
Financial Officer and Treasurer
of Edison International
Senior Vice President, Chief January 1993 to April 1995
Financial Officer and Treasurer
of Edison International
Senior Vice President and Chief January 1993 to April 1995
Financial Officer of SCE
Vice President, Chief Financial April 1991 to January 1993
Officer and Treasurer of Edison
International and SCE
Harold B. Ray Senior Vice President, Power Systems June 1990 to May 1995
Robert G. Foster Vice President, Public Affairs November 1993 to October 1996
Regional Vice President, Sacramento January 1988 to October 1993
Office
Vikram S. Budhraja Vice President, Planning and June 1993 to May 1995
Technology
Vice President, System Planning and February 1992 to May 1993
Operations
Emiko Banfield Vice President, Human Resources January 1996 to July 1996
Manager of Procurement and Material May 1994 to December 1995
Management
Manager of Transportation Services December 1991 to May 1994
Pamela A. Bass Vice President, Shared Services January 1996 to May 1996
Division Vice President, ENvest(3) August 1993 to December 1995
Division Vice President, January 1992 to August 1993
Customer Services
page 24
Theodore F. Craver, Jr. Executive Vice President and Corporate September 1990 to August 1996
Treasurer, First Interstate Bancorp
Bruce C. Foster Regional Vice President, San Francisco January 1992 to December 1994
Office
Lillian R. Gorman Executive Vice President and Human October 1990 to July 1996
Resources Director, First Interstate
Bancorp
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)
R. W. Krieger Station Manager, San Onofre August 1990 to May 1993
J. Michael Mendez Vice President, Regional Leadership February 1993 to January 1997
Vice President, Human Resources August 1991 to January 1993
Dwight E. Nunn Vice President, Tennessee Valley April 1990 to December 1995
Authority(4)
Frank J. Quevedo Director of Equal Opportunity January 1996 to May 1996
Manager of Equal Opportunity July 1992 to December 1995
Director, Corporate Relations, June 1986 to June 1992
Hunt-Wesson, Inc.
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, 1996, ("Annual Report") under
"Quarterly Financial Data" on page 31 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.
page 25
Item 6. Selected Financial Data
Information responding to Item 6 is included in the Annual Report under
"Selected Financial and Operating Data: 1992-1996" 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 10 and is incorporated herein by
reference pursuant to General Instruction G(2).
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in
Part IV. Other information responding to Item 8 is included in the Annual
Report on pages 11, 12, 13, and 14 through 31 under "Quarterly Financial
Data", and is incorporated herein by reference pursuant to General
Instruction G(2).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information concerning executive officers of Edison International is set
forth in Part I in accordance with General Instruction G(3), pursuant to
Instruction 3 to Item 401(b) of Regulation S-K. Other information
responding to Item 10 is included in the Joint Proxy Statement ("Proxy
Statement") filed with the Commission in connection with SCE's Annual
Meeting to be held on April 17, 1997, under the heading, "Election of
Directors of Edison International and SCE" on pages 2 through 6 and
"Section 16(a) Beneficial Ownership Reporting Compliance" on page 22, 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
beginning with the section under the heading "Executive Compensation Table
- - Edison International and SCE" on pages 9 through 21, and is incorporated
herein by reference pursuant to General Instruction G(3).
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information responding to Item 12 is included in the Proxy Statement under
the headings "Stock Ownership of Directors and Executive Officers of
Edison International and SCE" on pages 7 through 10 and "Stock Ownership
of Certain Shareholders" on page 25, and is incorporated herein by
reference pursuant to General Instruction G(3).
Item 13. Certain Relationships and Related Transactions
Information responding to Item 13 is included in the Proxy Statement under
the heading "Certain Additional Affiliations and Transactions of Nominees
and Executive Officers" on pages 22 through 25, and is incorporated herein
by reference pursuant to General Instruction G(3).
page 26
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) Financial Statements
The following items contained in the 1996 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, 1996,
1995 and 1994
Consolidated Statements of Retained Earnings -- Years Ended
December 31, 1996, 1995 and 1994
Consolidated Balance Sheets -- December 31, 1996, and 1995
Consolidated Statements of Cash Flows -- Years Ended December 31, 1996,
1995 and 1994
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(2) Report of Independent Public Accountants and Schedules
Supplementing Financial Statements
The following documents may be found in this report at the indicated page
numbers.
Page
----
Report of Independent Public Accountants on Supplemental
Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Schedule II--Valuation and Qualifying Accounts for the Years
Ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . 29
Schedules I through V, except those referred to above, are omitted as not
required or not applicable.
(3) Exhibits
See Exhibit Index on page 33 of this report.
(b) Reports on Form 8-K
January 18, 1996
Item 5: Other Events: Announcement of 1995 4th Quarter Earnings
October 3, 1996
Item 5: Other Events: Governor Wilson Signs Assembly Bill 1890
December 5, 1996
Item 5: Other Events: Divestiture of 12 natural gas and oil-
fueled power plants
page 27
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements included in the 1996 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
January 31, 1997. Our audits of the consolidated financial statements
were made for the purpose of forming an opinion on those basic
consolidated financial statements taken as a whole. The supplemental
schedules listed in Part IV of this Form 10-K, which are the
responsibility of SCE's management, are presented for purposes of
complying with the Securities and Exchange Commission's rules and
regulations, and are not part of the basic consolidated financial
statements. These supplemental schedules have been subjected to the
auditing procedures applied in the audits of the basic consolidated
financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in relation
to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
January 31, 1997 (except with respect
to the "Subsequent Event" discussed under
"Competitive Environment" in Part I, Item 1,
as to which the date is February 21, 1997)
page 28
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1996
Additions
------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
----------- ------------ ---------- ---------- ---------- ---------
(In thousands)
Group A:
Uncollectible accounts --
Customers. . . . . . . . . $ 22,126 $ 21,831 $ -- $ 19,567 $ 24,390
All other. . . . . . . . . 2,013 376 -- 700 1,689
-------- -------- ------- -------- --------
Total. . . . . . . . . . $ 24,139 $ 22,207 $ -- $ 20,267(a) $ 26,079
======== ======== ======= ======== ========
Group B:
DOE decontamination
and decommissioning. . . . $ 52,742 $ -- $ 1,468(b)$ 5,421(c) $ 48,789
Purchase Power Settlement. . -- -- 107,700(d) -- 107,700
Pension and benefits . . . . 196,662 8,547 21,869(e) 46,151(f) 180,927
Insurance, casualty and
other. . . . . . . . . . . 94,788 59,123 -- 67,402(g) 86,509
-------- -------- ------- -------- --------
Total. . . . . . . . . . $344,192 $67,670 $131,037 $118,974 $423,925
======== ======== ======= ======== ========
_______________
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents payments to be made under agreement to terminate a
purchase-power contract.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
page 29
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 23,931(d) 44,670(e) 196,662
Insurance, casualty and
other. . . . . . . . . . . 79,727 74,751 -- 56,690(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.
page 30
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.
page 31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
By Timothy W. Rogers
----------------------------------
Timothy W. Rogers
Attorney
Date: March 27, 1997
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, 1997
Chief Executive Officer
and Director
Principal Financial Officer:
Alan J. Fohrer* Executive Vice President March 27, 1997
and Chief Financial Officer
Controller or Principal
Accounting Officer:
Richard K. Bushey* Vice President and March 27, 1997
Controller
Majority of Board of Directors:
Howard P. Allen* Director March 27, 1997
Winston H. Chen* Director March 27, 1997
Stephen E. Frank* Director March 27, 1997
Camilla C. Frost* Director March 27, 1997
Joan C. Hanley* Director March 27, 1997
Carl F. Huntsinger* Director March 27, 1997
Charles D. Miller* Director March 27, 1997
Luis G. Nogales* Director March 27, 1997
Ronald L. Olson* Director March 27, 1997
J. J. Pinola* Director March 27, 1997
James M. Rosser* Director March 27, 1997
E. L. Shannon, Jr.* Director March 27, 1997
Robert H. Smith* Director March 27, 1997
Thomas C. Sutton* Director March 27, 1997
Daniel M. Tellep* Director March 27, 1997
James D. Watkins* Director March 27, 1997
Edward Zapanta* Director March 27, 1997
*By Timothy W. Rogers
-----------------------------------------
Timothy W. Rogers, Attorney-in-fact
page 32
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
3.1 Restated Articles of Incorporation as amended through
January 1996 (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)*
page 33
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)*
page 34
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)*
page 35
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
4.82 Eighty-First Supplemental Indenture, dated as of April 1,
1991 (File No. 1-2313)*
4.83 Eighty-Second Supplemental Indenture, dated as of May 1,
1991 (File No. 1-2313)*
4.84 Eighty-Third Supplemental Indenture, dated as of June 1,
1991 (File No. 1-2313)*
4.85 Eighty-Fourth Supplemental Indenture, dated as of December
1, 1991 (File No. 1-2313)*
4.86 Eighty-Fifth Supplemental Indenture, dated as of February
1, 1992 (File No. 1-2313)*
4.87 Eighty-Sixth Supplemental Indenture, dated as of April 1,
1992 (File No. 1-2313)*
4.88 Eighty-Seventh Supplemental Indenture, dated as of July 1,
1992 (File No. 1-2313)*
4.89 Eighty-Eighth Supplemental Indenture, dated as of July 15
1992 (File No. 1-2313)*
4.90 Eighty-Ninth Supplemental Indenture, dated as of December
1, 1992 (File No. 1-2313)*
4.91 Ninetieth Supplemental Indenture, dated as of January 15,
1993 (File No. 1-2313)*
4.92 Ninety-First Supplemental Indenture, dated as of March 1,
1993 (File No. 1-2313)*
4.93 Ninety-Second Supplemental Indenture, dated as of June 1,
1993*
4.94 Ninety-Third Supplemental Indenture, dated as of June 15,
1993 (File No. 1-2313)*
4.95 Ninety-Fourth Supplemental Indenture, dated as of July 15,
1993 (File No. 1-2313)*
4.96 Ninety-Fifth Supplemental Indenture, dated as of September
1, 1993 (File No. 1-2313)*
4.97 Ninety-Sixth Supplemental Indenture, dated as of October
1, 1993 (File No. 1-2313)*
page 36
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
10.1 1981 Deferred Compensation Agreement (File No. 1-2313)*
10.2 1985 Deferred Compensation Agreement for Executives
(File No. 1-2313)*
10.3 1985 Deferred Compensation Agreement for Directors
(File No. 1-2313)*
10.4 Director Deferred Compensation Plan (File No. 1-9936)*
10.5 Director Grantor Trust Agreement (File No. 1-9936)*
10.6 Executive Deferred Compensation Plan (File No. 1-9936)*
10.7 Executive Grantor Trust Agreement (File No. 1-9936)*
10.8 Executive Supplemental Benefit Program (File No. 1-2313)*
10.9 Executive Retirement Plan (File No. 1-2313)*
10.10 Employment Agreement with Howard P. Allen
(File No. 1-2313)*
10.11 1995 Executive Incentive Compensation Plan (File No. 1-9936)*
10.12 1996 Executive Incentive Compensation Plan
10.13 Executive Disability and Survivor Benefit Program
(File No. 1-9936)*
10.14 Retirement Plan for Directors
10.15 Director Incentive Compensation Plan
10.16 Officer Long-Term Incentive Compensation Plan
10.16.1 Form of Agreement for 1989-1995 Awards under the Officer Long-Term
Incentive Compensation Plan (File No. 1-9936)*
10.16.2 Form of Agreement for 1996 Awards under the Officer Long-Term
Incentive Compensation Plan
10.17 Estate and Financial Planning Program (File No. 1-9936)*
10.18 Consulting Agreement with Howard P. Allen (File No. 1-9936)*
10.19 Employment Agreement with Bryant C. Danner (File No. 1-9936)*
10.20 Employment Agreement with Stephen E. Frank (File No. 1-9936)*
12. Computation of Ratios of Earnings to Fixed Charges
13. Annual Report to Shareholders for year ended December 31, 1996
23. Consent of Independent Public Accountants - Arthur Andersen
LLP
24.1 Power of Attorney
24.2 Certified copy of Resolution of Board of Directors
Authorizing Signature
27. Financial Data Schedule
____________
* Incorporated by reference pursuant to Rule 12b-32.
EXHIBIT 10.12
EDISON INTERNATIONAL AND
SOUTHERN CALIFORNIA EDISON COMPANY
1996 EXECUTIVE INCENTIVE COMPENSATION PLAN
As Adopted December 13, 1995
WHEREAS, it has been determined that it is in the best interest of the
Edison International and Southern California Edison Company (SCE) to offer
and maintain competitive executive compensation programs designed to
attract and retain qualified executives; and
WHEREAS, it has been determined that providing financial incentives to
executives that reinforce and recognize corporate, organizational and
individual performance and accomplishments will enhance the financial and
operational performance of Edison International and SCE; and
WHEREAS, it has been determined that an incentive compensation program
would encourage the attainment of short-term corporate goals and
objectives;
NOW, THEREFORE, the 1996 Executive Incentive Compensation Plan has been
established by the Compensation and Executive Personnel Committee of the
Boards of Directors effective January 1, 1996, and made available to
eligible executives of the Edison International and SCE subject to the
following terms and conditions:
1. Definitions. When capitalized herein, the following terms are defined
as indicated:
"Base Salary" is defined to be the annual salary of the Participant on the
last day of the year worked by the Participant.
"Board" means the Board of Directors of the Company.
"Chairman" means the Chairman of the Board and Chief Executive Officer of
the Company.
"Code" means the Internal Revenue Code of 1986, as amended.
"Company" means Edison International and/or Southern California Edison
Company.
"Committee" means the Compensation and Executive Personnel Committees of
the Boards.
page 1
"Participant" means the Chairman, president, executive vice presidents,
senior vice presidents, elected vice presidents, and senior managers whose
participation in this Plan has been approved by the Chairman.
"Plan" means the Edison International and Southern California Edison
Company 1996 Executive Incentive Compensation Plan.
2. Eligibility. To be eligible for the full amount of any incentive
award, an individual must have been a participant for the entire calendar
year. Pro-rata awards may be distributed to participants who are
discharged for reasons other than incompetence, misconduct or fraud, or
who resigned, retired or became disabled during the calendar year, or who
were participants for less than the full year. A pro-rata award may be
made to a participant's designated beneficiary in the event of death of
a participant during a calendar year prior to an award being made.
3. Company Performance Goals. The Chairman will furnish recommended
Company achievement goals to the Committee, out of which the Committee
will, in consultation with the Chairman, select those areas of achievement
upon which they wish the Company to focus particular attention and
identify performance goals for the year.
The performance goals must represent relatively optimistic, but reasonably
attainable goals the accomplishment of which will contribute significantly
to the attainment of Company objectives.
4. Individual Incentive Award Levels. Company, organizational and
individual performance relative to the pre-established goals will
determine the award a Participant can receive.
Although most performance goals will be stated in terms of results to be
achieved during the calendar year, it is important that long-range goals
and objectives be included. These long-range goals and objectives will
have payoffs later than the year in question, but short-term sub-goals may
be established for the calendar year.
If the Committee determines individual and Company performance goals have
been substantially met, Participants will be eligible for individual
incentive awards at the following target award percentages:
70% of Base Salary for the Chairman;
60% of Base Salary for the President;
60% of Base Salary for the Executive Vice Presidents;
45% of Base Salary for the Senior Vice Presidents;
35% of Base Salary for the elected Vice Presidents; and
25-30% of Base Salary for the Senior Managers.
page 2
Stretch-maximum awards of up to 150% of target may be earned on the basis
of performance in excess of targets. All awards shall be made in the
discretion of the Committee on the basis of its assessment of corporate
and individual performance.
5. Approval and Payment of Individual Awards. During the first quarter
of the year following the completion of the calendar year, the Chairman
will assess the degree to which individual and corporate goals and
objectives have been achieved and will develop suggested incentive awards
for eligible Participants other than the Chairman. The Committee will
receive a report from the Chairman as to overall Company performance, will
deliberate on the Chairman's recommendations, will develop an incentive
award for the Chairman, and make its determination as to the approval of
the recommended awards for officers. Awards to non-officers shall be
determined and approved by the Chairman. All decisions of the Committee
and the Chairman regarding individual incentive awards will be final and
conclusive.
Incentive award payments will be made as soon as practical following the
Committee's approval. Payment will be made in cash except to the extent
the Participant has previously elected to defer payment of some or all of
the award pursuant to the terms of a deferred compensation plan of the
Company or to the extent the Committee elects to defer some or all of the
award. Awards (cash or deferred) made will be subject to any income or
payroll tax withholding or other deductions as may required by Federal,
State or local law.
Awards under this Plan will not be considered to be salary or other
compensation for the purpose of computing benefits to which the
Participant may be entitled under any pension plan, stock bonus plan,
including but not limited to the SCE Retirement Plan, SCE Stock Savings
Plus Plan, or other plan or arrangement of the Company for the benefit of
its employees if such plan or arrangement is a plan qualified under
Section 401(a) of the Code and is a trust exempt from Federal income tax
under Section 501(a) of the Code.
Awards owed to participants under this Plan shall constitute an unsecured
general obligation of the Company, and no special fund or trust shall be
created, nor shall any notes or securities be issued with respect to any
awards.
6. Plan Modifications and Adjustments. In order to ensure the incentive
features of the Plan, avoid distortion in its operation and compensate for
or reflect extraordinary changes which may have occurred during the
calendar year, the Committee may make adjustments to the Plan's
performance goals and percentage allocations before, during or after the
end of the calendar year to the extent it determines appropriate in its
sole discretion. Adjustments to the Plan shall be conclusive and binding
upon all parties concerned. The Plan may be modified or terminated by the
Committee at any time.
7. Plan Administration. This Plan and any officer awards under it are
to be approved by the Committee. The Chairman shall approve any non-
officer awards. Administration of the Plan is otherwise delegated to
management under the direction of
page 3
the Chairman. The responsible vice president is authorized to approve
ministerial amendments to the Plan, to interpret Plan provisions, and to
approve changes as may be required by law or regulation. Neither the
Company nor any member of the Committee or the Board shall be liable to
any person for any action taken or omitted in connection with the
interpretation and administration of the Plan.
8. Successors and Assigns. This Plan shall be binding upon and inure to
the benefit of the heirs, legal representatives, successors and assigns
of the Company and Participant. Notwithstanding the foregoing, any right
to receive payment hereunder is hereby expressly declared to be personal,
nonassignable and nontransferable, except by will, intestacy, or as
otherwise required by law, and in the event of any attempted assignment,
alienation or transfer of such rights contrary to the provisions hereof,
the Company shall have no further liability for payments hereunder.
9. Beneficiaries. In the event of the death of a Participant during a
calendar year prior to the making of any individual incentive award, a
pro-rata award may be made at the discretion of the Committee. Any such
payment will be made to the Participant's most recently designated
beneficiary or beneficiaries under the Long-Term Incentive Compensation
Plan of the Company. If no such designated beneficiary or beneficiaries
survive the Participant, or if a designated beneficiary should die before
the award has been paid, any award will be paid in one lump-sum payment
to his or her estate as soon as practicable following the Participant's
or the designated beneficiary's death.
10. Capacity. If any person entitled to payments under this Plan is
incapacitated and unable to use such payments in his or her own best
interest, the Company may direct that payments (or any portion) be made
to that person's legal guardian or conservator, or that person's spouse,
as an alternative to the payment to the person unable to use the payments.
Court-appointed guardianship or conservatorship may be required by the
Company before payment is made. The Company shall have no obligation to
supervise the use of such payments.
11. No Right of Employment. Nothing contained herein shall be construed
as conferring upon the Participant the right to continue in the employ of
the Company as an Officer or Manager of the Company or in any other
capacity.
12. Severability and Controlling Law. The various provisions of this
Plan are severable in their entirety. Any determination of invalidity or
unenforceability of any one provision will have no effect on the
continuing force and effect of the remaining provisions. This Plan shall
be governed by the laws of the State of California.
EDISON INTERNATIONAL
SOUTHERN CALIFORNIA EDISON COMPANY
Emiko Banfield
-------------------------------
Emiko Banfield, Vice President
EXHIBIT 10.14
EDISON INTERNATIONAL
SOUTHERN CALIFORNIA EDISON COMPANY
RETIREMENT PLAN FOR DIRECTORS
As Amended February 15, 1996
I. GENERAL
1.1 Purpose
The purpose of this Plan is to provide recognition and retirement
compensation to eligible members of the Edison International and Southern
California Edison Company Boards of Directors ("Boards") to facilitate the
companies' ability to attract, retain, and reward members of the Boards.
1.2 Eligibility
Eligibility in this Plan is limited to members of the Boards who have at
least five years of total service (which need not be continuous service)
as directors, and who retire or resign from the Boards in good standing
or die while in service and in good standing. This Plan covers periods
of service both as an employee director and as an outside director. For
purposes of this Plan, a year of service will be determined on a calendar
year basis and a full year of service will be credited for any fractional
year served.
II. AMOUNT OF ANNUAL BENEFIT
2.1 Benefit
The Plan pays an annual retirement benefit equal to the annual retainer
in effect at the time of the eligible director's retirement, resignation,
or death. The retirement benefit will be paid quarterly in advance in
equal installments for the period described in Section 3.1(a). No
additional amount will be paid for service on any of the committees of the
Boards, nor will interest be paid.
2.2 Benefit of Directors in Service Before 1996
If a director has Board service prior to 1996, the Plan will pay an annual
retirement benefit determined by multiplying the director's years of
service before and after January 1, 1996 by the applicable compensation
base and dividing the sum of the products by the director's total years
of service. For service before 1996, the compensation base will be the
annual retainer plus eight times the regular monthly meeting fee in effect
at the time of the eligible director's retirement, resignation or death.
For service after 1995, the compensation base will be the annual retainer
in effect at the time of the eligible director's retirement, resignation
or death.
page 1
III. DURATION OF PAYMENTS
3.1 Benefit Period
(a) The Plan benefit will be paid to the retired director or his/her
surviving spouse for the number of years equal to the director's total
years of service on the Boards.
(b) A break in service on the Board of Southern California Edison Company
which was required to allow the director to render a period of
distinguished and uninterrupted government service which was completed
before 1982 and which was followed by reelection to that Board will be
recognized under this Plan as a period of service on that Board.
(c) A year of simultaneous service on the Boards of Edison International
and Southern California Edison Company will be counted as one year for
computation of the Plan's benefit period.
3.2 Commencement of Payments
The first quarterly installment of Plan Benefits will be paid on the first
day of the calendar quarter following the director's retirement as a
director, or the 65th anniversary of the director's birth, whichever
occurs later.
3.3 Survivor Benefits
(a) If the director dies without leaving a surviving spouse, a lump sum
of any benefit payments remaining will be calculated and paid to the
estate of the director.
(b) If the director dies leaving a surviving spouse before retiring from
the Boards, benefit payments to that spouse will begin on the first day
of the calendar quarter following the date of the director's death, or the
65th anniversary of the director's birth, whichever occurs later.
(c) If the director dies leaving a surviving spouse after benefit
payments have begun, benefit payments will continue and be paid to that
spouse.
(d) If the director dies leaving a surviving spouse after retirement from
the Boards but before benefit payments have begun, benefit payments to
that spouse will begin on the first day of the calendar quarter following
the 65th anniversary of the director's birth.
3.4 Termination of Benefit Payments
Once begun, benefit payments to a retired director or his/her surviving
spouse will continue until the earlier of the
o completion of payments for the Benefit Period, or
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o date of death of the later to die of the director or the surviving
spouse. Upon said death, a lump sum of any remaining benefit payments
will be calculated and paid to that person's estate.
V. ADMINISTRATION
(a) This Plan is non-contributory, non-qualified and unfunded, and
represents an unsecured general obligation of each Company. No special
fund or trust will be created, nor will any notes or securities be issued
with respect to any retirement benefits.
(b) The Chair of each Company's Compensation and Executive Personnel
Committee, or the Vice President of Human Resources of Southern California
Edison Company, will have full and final authority to interpret this Plan,
and to make determinations advisable for the administration of this Plan,
to approve ministerial changes, and to approve changes as may be required
by law or regulation. All such decisions and determinations will be final
and binding upon all parties.
(c) If any person entitled to payments under this Plan is, in the opinion
of the Committees or their designee, incapacitated and unable to use such
payments in his/her own best interest, the Committees or their designee
may direct that payments (or any portion) be made to the person's spouse
or legal guardian, as an alternative to the payment to the person unable
to use the payments. The Committees or their designee will have no
obligation to supervise the use of such payments.
(d) This Plan will be governed by the laws of the State of California.
EDISON INTERNATIONAL AND
SOUTHERN CALIFORNIA EDISON COMPANY
Beverly P. Ryder
----------------------------------------
Beverly P. Ryder, Secretary
EXHIBIT 10.15
EDISON INTERNATIONAL
DIRECTOR INCENTIVE COMPENSATION PLAN
As Amended and Restated February 15, 1996
I. GENERAL
1.1 Purpose
The purpose of the Director Incentive Compensation Plan ("Plan") is to
foster and promote the long-term financial success of Edison International
and its affiliates by attracting and retaining outstanding nonemployee
directors by enabling them to participate in the corporation's growth
through automatic, nondiscretionary awards of stock ("Awards").
1.2 Eligibility
Eligibility in this Plan shall be limited to members of the Board of
Directors of Edison International or, an Edison International affiliate,
who at the time the Award is made are not employees or officers of Edison
International or an Edison International affiliate.
1.3 Shares Subject to the Plan
Shares of stock covered by Awards under the Plan may be, in whole or
in part, authorized and unissued shares of Edison International's common
stock, or previously issued shares of common stock reacquired by Edison
International including shares purchased on the open market, or such other
shares as may be substituted pursuant to Section 3.3 ("Common Stock").
The maximum number of shares of Common Stock which may be issued for all
purposes under the Plan shall be 196,800 (subject to adjustment pursuant
to Section 3.3).
II. STOCK AWARDS
2.1 Award Formula
Effective with a Director's election on April 16, 1992, and on each
subsequent date a Director is elected or reelected to the Board of
Directors of Edison International at an annual meeting of the
stockholders, such Director will automatically be granted
500 shares of fully vested Common Stock, at no cost to the Director. Each
stock certificate evidencing an Award shall be registered in the name of
the Director and delivered to him or her on that date, or as soon
thereafter as practicable. Directors serving on more than one Board will
receive only one Award per year under the Plan.
2.2 Award Limitation
Subject to the limitations of Section 3.2, the award formula may be
modified from time to time by the Board of Directors, with respect to
pricing, timing and amount, but such formula will not be modified to
provide an Award in excess of 1000 shares of Common Stock per Director per
year.
III. ADMINISTRATION
3.1 Administration of the Plan
The Plan shall be self-effectuating. Administrative determinations
necessary or advisable for the administration or interpretation of the
Plan in order to carry out its provisions and purposes shall be made by
Edison International.
3.2 Amendment, Suspension and Termination of Plan
The Board of Directors may suspend or terminate the Plan or any portion
thereof at any time and may amend the Plan from time to time in such
respects as the Board of Directors may deem advisable; provided, however,
the Plan shall not be amended more than once every six months, other than
to comport with changes in the Internal Revenue Code of 1986, as amended,
or the rules promulgated thereunder; and provided further, the Plan shall
not be amended, without shareholder approval to the extent required by law
or the rules of any exchange upon which the Common Stock is listed, (a)
to materially increase the number of shares of Common Stock which may be
issued under the Plan, except as provided in Section 3.3, (b) to
materially modify the requirements as to eligibility for participation in
the Plan, or (c) to materially increase the benefits accruing to Directors
under the Plan. No such amendment, suspension or termination shall make
any change that would disqualify the Plan, or any other Plan of Edison
International intended to be so qualified, from the exemption provided by
Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as
amended.
3.3 Capital Adjustments
In the event of a stock dividend or stock split, combination or other
reduction in the number of issued shares of Common Stock, a merger,
consolidation, reorganization, recapitalization, sale or exchange of
substantially all assets or dissolution of Edison International, the Board
of Directors shall, in order to prevent the dilution or enlargement of
rights under the Plan, make such adjustments in the number
page 2
and type of shares authorized and the number and type of shares that may
be awarded under this Plan as may be determined to be appropriate and
equitable.
IV. MISCELLANEOUS
4.1 Rights of Directors
Nothing in the Plan shall confer upon any Director any right to serve
as a Director for any period of time or to continue his or her present or
any other rate of compensation.
4.2 Plan Not Exclusive
The adoption of the Plan shall not preclude the adoption by appropriate
means of a stock option or other incentive plan for Directors.
4.3 Requirements of Law; Governing Law
The granting of Awards and issuance of shares of Common Stock shall be
subject to all applicable rules and regulations, and to such approvals by
any governmental agencies or national securities exchanges as may be
required. The Plan shall be construed in accordance with and governed by
the laws of the State of California.
4.4 Term of Plan
This Plan shall become effective upon its approval by the stockholders
of Edison International at their annual meeting on April 16, 1992, and
shall continue in effect until terminated by the Edison International
Board of Directors or the Edison International stockholders.
EDISON INTERNATIONAL
Beverly P. Ryder
- ---------------------------------
Beverly P. Ryder
Secretary
EXHIBIT 10.16
EDISON INTERNATIONAL
OFFICER LONG-TERM INCENTIVE COMPENSATION PLAN
Amended and Restated as of February 15, 1996
WHEREAS, the 1987 Long-Term Incentive Compensation Plan (the "1987 Plan")
was approved by the shareholders of Southern California Edison Company
effective January 15, 1987;
WHEREAS, SCEcorp assumed sponsorship of the 1987 Plan with the formation
of the holding company approved by the shareholders of Southern California
Edison Company on April 21, 1988; and
WHEREAS, it is deemed desirable to amend and restate the Plan as the
Edison International Officer Long-Term Incentive Compensation Plan;
NOW, THEREFORE, the Edison International Officer Long-Term Incentive
Compensation Plan is restated subject to the following terms and
conditions:
1. Purpose.
The purpose of the Edison International Officer Long-Term Incentive
Compensation Plan is to improve the long-term financial and operational
performance of Edison International and its affiliates by providing
eligible Participants a financial incentive which reinforces and
recognizes long-term corporate, organizational and individual performance
and accomplishments. The Plan is intended to promote the interests of
Edison International and its shareholders by encouraging eligible
Participants to acquire stock or increase their proprietary interest in
Edison International.
2. Definitions.
Whenever the following terms are used in this Plan, they will have the
meanings specified below unless the context clearly indicates the
contrary:
"Board of Directors" or "Board" means the Board of Directors of Edison
International.
"Cash Equivalent" means a stock-based award payable in cash only granted
pursuant to Section 14.
"Code" means the Internal Revenue Code of 1986, as amended.
"Committee" means the Compensation and Executive Personnel Committee of
the Board of Directors excluding those members ineligible to administer
this Plan as determined under Section 4.
page 1
"Common Stock" means the common shares of Edison International.
"Company" means Edison International or the Edison International affiliate
employing the Participant.
"Dividend Equivalent" means the additional amount of cash or Common Stock
as described in Section 12.
"Eligible Person" or "Participant" means an officer of the Company whose
participation has been approved by the Committee, including without
limitation, executive officers under Section 16 of the Securities Exchange
Act of 1934, as amended, but excluding those persons participating in the
Edison International Management Long-Term Incentive Compensation Plan.
"Fair Market Value" means the average of the highest and lowest sale
prices for the Common Stock as reported in the western edition of The Wall
Street Journal for the New York Stock Exchange Composite Transactions for
the date as of which such determination is made.
"Former Rule 16b-3" means Rule 16b-3 promulgated by the Securities and
Exchange Commission under the Securities Exchange Act of 1934, as amended,
and effective until May 1, 1991.
"Holder" means a person holding an Incentive Award.
"Incentive Award" means any award which may be made under the Plan by the
Committee.
"Incentive Stock Option" means an option as defined under Section 422A of
the Code granted pursuant to Section 7 of the Plan.
"Nonqualified Stock Option" means an option, other than an Incentive Stock
Option, granted pursuant to Section 6 of the Plan.
"Option" means either a Nonqualified Stock Option or Incentive Stock
Option.
"Performance Award" means an award granted pursuant to Section 10 which
may be based on stock value, book value, or other specific performance
criteria.
"Plan" means the Officer Long-Term Incentive Compensation Plan as set
forth herein, which may be amended from time-to-time.
"Restricted Stock" means Common Stock granted or awarded pursuant to
Section 8 of the Plan, which is nontransferable and subject to substantial
risk of forfeiture until restrictions lapse.
page 2
"Rule 16b-3" means Rule 16b-3 promulgated by the Securities and Exchange
Commission under the Securities Exchange Act of 1934, as amended, and
effective May 1, 1991.
"Stock Appreciation Equivalent" means an award based on Common Stock
appreciation or other specific performance criteria which is granted
pursuant to Section 11.
"Stock Appreciation Right" or "Right" means a right granted pursuant to
Section 9 of the Plan.
"Stock Payment" means a payment pursuant to Section 13 in shares of Common
Stock to replace all or any portion of the compensation (other than base
salary) that would otherwise become payable to a Participant in cash.
3. Aggregate Awards Under Plan.
Pursuant to the terms of the Plan, and subject to the provisions of this
Section 3 and Section 16 of the Plan, the aggregate number of shares of
Common Stock that may be issued or transferred pursuant to Incentive
Awards, and the total aggregate value of Incentive Awards other than
Dividend Equivalents which are payable in a form other than Common Stock,
will not exceed 1.5 million shares, or the fair market value of such
shares as determined on the dates of payment of the Incentive Awards. On
an annual basis, as long as any Incentive Awards are outstanding and have
not been paid, Dividend Equivalents payable in cash will not exceed the
annual dividend payable on 1.5 million shares of Common Stock.
The shares to be delivered under the Plan will be made available, at the
discretion of the Board or Committee, either from authorized but unissued
shares of Common Stock or from previously issued shares of Common Stock
reacquired by Edison International including shares purchased on the open
market.
If any Incentive Award expires, is forfeited, is canceled, or otherwise
terminates for any reason other than upon exercise or payment, the shares
of Common Stock (provided the Participant receives no benefit of
ownership) or equivalent value that could have been delivered will not be
charged against the limitations provided above and may again be made
subject to Incentive Awards. However, shares subject to Stock
Appreciation Rights settled in cash will not be charged against the share
limitations provided above, but only against the fair market value
limitation.
4. Administration.
The Plan will be administered by the Committee, which will consist of
those directors on the Compensation Committee of the Board who, (i) as
long as Former Rule 16b-3 is elected to apply to this Plan, are not
eligible to receive Incentive Awards under the Plan at the time he or she
exercises discretion in administering the Plan, and have not been eligible
for selection for at least one year prior thereto to receive Incentive
Awards or
page 3
Common Stock pursuant to the Plan, or any other plan of Edison
International or any of its affiliates entitling the Participants therein
to acquire Common Stock, Stock Appreciation Rights, or Options of Edison
International or any of its affiliates, other than plans permitted by
Former Rule 16b-3, or, (ii) from the time Rule 16b-3 is elected to apply
to this Plan, during the one year prior to service as an administrator of
the Plan, or during such service, have not been granted or awarded
Incentive Awards or Common Stock pursuant to the Plan or any other plan
of Edison International or any of its affiliates, other than plans
permitted by Rule 16b-3. To the extent the members of the Compensation
Committee of the Board satisfying the above criteria are fewer than three
in number and Former Rule 16b-3 is elected to apply to this Plan, the
Board shall appoint additional directors until at least three members are
qualified to administer this Plan. From the time Rule 16-3b is elected
to apply to the Plan, the Board shall ensure at least two members are
qualified to administer the Plan.
The Committee has, and may exercise, such powers and authority of the
Board as may be necessary or appropriate for the Committee to carry out
its functions as described in the Plan. The Committee has sole authority
in its discretion to determine the Officers to whom, and the time or times
at which, Incentive Awards may be granted, the nature of the Incentive
Award, the number of shares of Common Stock or the amount of cash that
makes up each Incentive Award, the pricing and amount of any Incentive
Award, the objectives, goals and performance criteria (which need not be
identical) utilized to measure the value of Incentive Awards, the form of
payment (cash or Common Stock or a combination thereof) payable upon the
event or events giving rise to payment of an Incentive Award, the vesting
schedule of any Incentive Award, the term of any Incentive Award, and such
other terms and conditions applicable to each individual Incentive Award
as the Committee shall determine. The Committee may grant at any time new
Incentive Awards to a Participant who has previously received Incentive
Awards whether such prior Incentive Awards are still outstanding, have
previously been exercised in whole or in part, or are canceled in
connection with the issuance of new Incentive Awards. The purchase price
or initial value of the Incentive Awards may be established by the
Committee without regard to the existing Incentive Awards or such other
grants. Further, the Committee may, with the consent of a Participant,
amend the terms of any existing Incentive Award previously granted to
include or amend any provisions which could be incorporated in such an
Incentive Award at the time of such amendment.
The Committee has the sole authority to interpret the Plan, to determine
the terms and provisions of the Incentive Award agreements, and to make
all determinations necessary or advisable for the administration of the
Plan. The Committee has authority to prescribe, amend, and rescind rules
and regulations relating to the Plan. All interpretations,
determinations, and actions by the Committee will be final, conclusive,
and binding upon all parties. Any action of the Committee with respect
to the administration of the Plan shall be taken pursuant to a majority
vote or by the unanimous written consent of its members. The Committee
may delegate to one or more agents such nondiscretionary administrative
duties as it may deem advisable.
page 4
No member of the Board or the Committee or agent or designee thereof will
be liable for any action or determination made in good faith by the Board
or the Committee with respect to the Plan or any transaction arising under
the Plan.
5. Eligibility and Date of Grant.
The Committee has authority, in its sole discretion, to determine and
designate from time-to-time those Eligible Persons who are to be granted
Incentive Awards, the type of Incentive Awards to be granted, the times
at which Incentive Awards will be granted, the prices of Incentive Awards
(which may be any lawful consideration determined by the Committee), the
amount of any Incentive Award, and the number of shares of Common Stock
or the amount of cash subject to each Incentive Award.
Each Incentive Award will be evidenced by a written instrument signed by
Edison International and the Participant and may include any other terms
and conditions consistent with the Plan as the Committee may in its
discretion determine. The date of grant of an Incentive Award will be the
date of the Agreement between the Company and the Participant.
6. Nonqualified Stock Options.
The Committee may approve the grant of Nonqualified Stock Options to
Eligible Persons, subject to the following terms and conditions:
(a) The purchase price of Common Stock under each Nonqualified Stock
Option may not be less than one hundred percent of the Fair Market Value
of the Common Stock on the date the Nonqualified Stock Option is granted.
(b) No Nonqualified Stock Option may be exercised after ten years and one
day from the date of grant.
(c) Upon the exercise of a Nonqualified Stock Option, the purchase price
will be payable in full in cash and/or its equivalent, such as Common
Stock, acceptable to Edison International. Any shares so assigned and
delivered to Edison International in payment or partial payment of the
purchase price will be valued at their Fair Market Value on the exercise
date.
(d) No fractional shares will be issued pursuant to the exercise of a
Nonqualified Stock Option. Only cash payments will be made in lieu of
fractional shares.
7. Incentive Stock Options.
The Committee may approve the grant of Incentive Stock Options to Eligible
Persons, subject to the following terms and conditions:
(a) The purchase price of each share of Common Stock under an Incentive
Stock Option will be at least equal to the Fair Market Value of a share
of the Common Stock on the date of grant; provided, however, that if a
Participant, at the time an Incentive Stock Option is granted, owns stock
representing more than ten (10%) percent of the
page 5
total combined voting power of all classes of stock of Edison
International (as defined in Section 425(e) or (d) of the Code), then the
exercise price of each share of Common Stock subject to such Incentive
Stock Option shall be at least one hundred and ten (110%) percent of the
Fair Market Value of such share of Common Stock, as determined in the
manner stated in this paragraph.
(b) No Incentive Stock Option may be exercised after ten (10) years from
the date of the grant. Each Incentive Stock Option granted under this
Plan shall also be subject to earlier termination as provided in this
Plan.
(c) Upon the exercise of an Incentive Stock Option, the purchase price
will be payable in full in cash and/or its equivalent, such as Common
Stock, acceptable to Edison International. Any shares so assigned and
delivered to Edison International in payment or partial payment of the
purchase price will be valued at their Fair Market Value on the exercise
date.
(d) The Fair Market Value (determined at the time the Incentive Stock
Option is granted) of the shares of Common Stock for which any Participant
may be granted Incentive Stock Options that are first exercisable during
any one calendar year (including Incentive Stock Options under all plans
of the Company) will not in the aggregate exceed One Hundred Thousand
($100,000) Dollars.
(e) No fractional share will be issued pursuant to the exercise of an
Incentive Stock Option. Only cash payments will be made in lieu of
fractional shares.
8. Restricted Stock.
The Committee may approve the grant or award of Restricted Stock to
Eligible Persons subject to the conditions of this Section 8.
(a) All shares of Restricted Stock granted or awarded pursuant to the
Plan (including any shares of Restricted Stock received by the Holder as
a result of stock dividends, stock splits, or any other forms of
adjustment) will be subject to the following restrictions:
(i) The shares may not be sold, transferred, or otherwise alienated
or hypothecated until the restrictions are removed or expire.
(ii) The Committee may require the Holder to enter into an escrow
agreement providing that the certificates representing Restricted Stock
granted or awarded pursuant to the Plan will remain in the physical
custody of an escrow holder or Edison International until all restrictions
are removed or expire.
(iii)Each certificate representing Restricted Stock granted or
awarded pursuant to the Plan will bear a legend making appropriate
reference to the restrictions imposed on the Restricted Stock.
page 6
(iv) The Committee may impose restrictions on any shares granted or
awarded as it may deem advisable, including, without limitation,
restrictions designed to facilitate exemption from or compliance with the
Securities Exchange Act of 1934, as amended, with requirements of any
stock exchange upon which such shares or shares of the same class are then
listed, and with any blue sky or other securities laws applicable to such
shares.
(b) The restrictions imposed under subparagraph (a) above upon Restricted
Stock will lapse in accordance with a schedule or other conditions as
determined by the Committee, subject to the provisions of Sections 18 and
19.
(c) Upon acceptance of the Restricted Stock offer, the purchase price,
if any, established by the Committee will be payable in full in cash
and/or its equivalent, such as Common Stock, acceptable to Edison
International.
(d) Subject to the provisions of subparagraph (a) above and Section 19,
the Holder will have all rights of a shareholder with respect to the
Restricted Stock granted or awarded, including the right to vote the
shares and receive all dividends and other distributions paid or made with
respect thereto.
9. Stock Appreciation Rights.
The Committee may approve the grant of Rights related or unrelated to
Options to Eligible Persons, subject to the following terms and
conditions:
(a) A Stock Appreciation Right may be granted:
(i) at any time if unrelated to an option;
(ii) either at the time of grant, or at any time thereafter during the
option term if related to a Nonqualified Stock Option;
(iii)only at the time of grant if related to an Incentive Stock
Option.
(b) A Stock Appreciation Right grant in connection with an Option will
entitle the Holder of the related Option, upon exercise of the Stock
Appreciation Right, to surrender such Option, or any portion thereof to
the extent unexercised, with respect to the number of shares as to which
such Stock Appreciation Right is exercised, and to receive payment of an
amount computed pursuant to Section 9(d). Such Option will, to the extent
surrendered, then cease to be exercisable.
(c) Subject to Section 9(g), a Stock Appreciation Right granted in
connection with an Option hereunder will be exercisable at such time or
times, and only to the extent that a related Option is exercisable, and
will not be transferable except to the extent that such related Option may
be transferable.
page 7
(d) Upon the exercise of a Stock Appreciation Right related to an Option,
the Holder will be entitled to receive payment of an amount determined by
multiplying:
(i) The difference obtained by subtracting the purchase price of a
share of Common Stock specified in the related Option from the
Fair Market Value of a share of Common Stock on the date of
exercise of such Stock Appreciation Right, by
(ii) The number of shares to which such Stock Appreciation Right has
been exercised.
(e) The Committee may grant Stock Appreciation Rights unrelated to
Options to Eligible Persons. Section 9(d) shall be used to determine the
amount payable at exercise of such Stock Appreciation Right(s) if Fair
Market Value is not used, except that Fair Market Value shall not be used
if the Committee specified in the award that book value or another measure
as deemed appropriate by the Committee was to be used. In applying the
formula in Section 9(d), the initial share value specified in the Stock
Appreciation Right award shall be used in lieu of the price "specified in
the related Option."
(f) Payment of the amount determined under Section 9(d) or (e) may be
made solely in whole shares of Common Stock in a number determined at
their Fair Market Value on the date of exercise of the Stock Appreciation
Right or alternatively, at the sole discretion of the Committee, solely
in cash or in a combination of cash and shares as the Committee deems
advisable. If the Committee decides to make full payment in shares of
Common Stock, and the amount payable results in a fractional share, no
fractional share will be issued. Payment for the fractional share will
be made in cash only.
(g) The Committee may, at the time a Stock Appreciation Right is granted,
impose such conditions on the exercise of the Stock Appreciation Right as
may be required to satisfy the requirements of Former Rule 16b-3 and/or
Rule 16b-3, as applicable (or any other comparable provisions in effect
at the time or times in question). Without limiting the generality of the
foregoing, the Committee may determine that a Stock Appreciation Right
may be exercised only during the period beginning on the third business
day and ending on the twelfth business day following the publication of
Edison International's quarterly and annual summarized financial data.
10. Performance Awards.
The Committee may approve Performance Awards to Eligible Persons. Such
awards may be based on Common Stock performance over a period determined
in advance by the Committee or any other measures as determined
appropriate by the Committee. Payment will be in cash unless replaced by
a Stock Payment in full or in part as determined by the Committee.
page 8
11. Stock Appreciation Equivalents.
The Committee may approve Stock Appreciation Equivalents to Eligible
Persons. Such awards may be based on Common Stock performance over a
period determined in advance by the Committee, or any other measures as
determined appropriate by the Committee. Payment will be in cash unless
replaced by a Stock Payment in full or in part as determined by the
Committee.
12. Dividend Equivalents.
The Committee may approve Dividend Equivalents based on the dividends
declared on the Common Stock on record dates during the period between the
date an Incentive Award is granted and the date such Incentive Award is
exercised or paid. Dividend Equivalents may be awarded separately or in
connection with Incentive Awards payable, whether payable in cash or
Common Stock. Subject to Sections 3 and 16, such Dividend Equivalents
shall be converted to cash or additional shares by such formula and at
such time as may be determined by the Committee.
13. Stock Payments.
The Committee may approve Stock Payments of Common Stock to Eligible
Persons for all or any portion of the compensation (other than base
salary) that would otherwise become payable to a Participant in cash.
Notwithstanding anything to the contrary contained in this Plan, if the
written instrument signed by Edison International and the Holder
evidencing any Incentive Award states that the Incentive Award(s) will be
paid in cash, the Committee may not make a Stock Payment in lieu thereof,
and the Incentive Award(s) will be redeemable or exercisable by the Holder
only for cash.
14. Cash Equivalents.
The Committee may grant any Incentive Award permitted under the Plan which
is otherwise payable in stock in the form of a cash equivalent award.
15. Deferral of Payment.
The Committee may approve the deferral of any payments which may become
due under the Plan. Such deferrals shall be subject to any conditions,
restrictions or requirements as the Committee may determine.
16. Adjustment Provisions.
Subject to the provisions of this Section 16 below, if the outstanding
shares of Common Stock are increased, decreased, or exchanged for a
different number or kind of shares or other securities, or if additional
shares or new or different shares or other securities are distributed with
respect to such shares of Common Stock or other securities, through
merger, consolidation, sale of all or substantially all of the property
of Edison International, reorganization, recapitalization,
reclassification, stock dividend, stock split, reverse stock split or
other distribution with respect to such shares of Common Stock or other
securities, an appropriate and proportionate adjustment may be made in (i)
the maximum number and kind of shares provided in Section 3 of the Plan,
(ii) the
page 9
number and kind of shares or other securities subject to the then
outstanding Incentive Awards, and (iii) the price for each share or other
unit of any other securities subject to the then outstanding Incentive
Awards without change in the aggregate purchase price or value as to which
Incentive Awards remain exercisable or subject to restrictions.
Despite the foregoing, upon dissolution or liquidation of Edison
International, or upon a reorganization, merger, or consolidation of
Edison International with one or more corporations as a result of which
Edison International is not the surviving corporation, or upon the sale
of all or substantially all the property of Edison International, all
Options, Stock Appreciation Rights, and other Incentive Awards then
outstanding under the Plan will be fully vested and exercisable and all
restrictions on Restricted Stock will immediately cease, unless provisions
are made in connection with such transaction for the continuance of the
Plan and the assumption of or the substitution for such Incentive Awards
of new Options, Stock Appreciation Rights, or other Incentive Awards, or
Restricted Stock covering the stock of a successor employer corporation,
or a parent or subsidiary thereof, with appropriate adjustments as to the
number and kind of shares and prices.
Any adjustments pursuant to this Section will be made by the Committee,
whose determination as to what adjustments will be made and the extent
thereof will be final, binding, and conclusive. No fractional interest
will be issued under the Plan on account of any such adjustments. Only
cash payments will be made in lieu of fractional shares.
17. General Provisions.
(a) With respect to any share of Common Stock issued or transferred under
any provision of the Plan, such shares may be issued or transferred
subject to such conditions, in addition to those specifically provided in
the Plan, as the Committee may direct.
(b) Nothing in the Plan or in any instrument executed pursuant to the
Plan will confer upon any Holder any right to continue in the employ of
the Company or affect the right of the Company to terminate the employment
of any Holder at any time with or without cause.
(c) No shares of Common Stock will be issued or transferred pursuant to
an Incentive Award unless and until all then applicable requirements
imposed by federal and state securities and other laws, rules, and
regulations and by any regulatory agencies having jurisdiction, and by any
stock exchanges upon which the Common Stock may be listed, have been fully
met. As a condition precedent to the issue of shares pursuant to the
grant or exercise of an Incentive Award, Edison International may require
the Holder to take any reasonable action to meet such requirements.
(d) No Holder (individually or as a member of a group) and no beneficiary
or other person claiming under or through such Holder will have any right,
title, or interest in or to any shares of Common Stock allocated or
reserved under the Plan or subject to any
Incentive Award except as to such shares of Common Stock, if any, that
have been issued or transferred to such Holder.
(e) Edison International may make such provisions as it deems appropriate
to withhold any taxes which it determines it is required to withhold in
connection with any Incentive Award. Subject to this Section 17(e),
however, and without in anyway limiting the generality of Section 9, the
Committee, in its sole discretion and subject to such rules as the
Committee may adopt, may permit Participants to elect (i) cash settlement
of any Incentive Award, or (ii) to apply a portion of the shares of Common
Stock they are otherwise entitled to receive pursuant to an Incentive
Award, or shares of Common Stock already owned, to satisfy the tax
withholding obligation arising from the receipt, vesting, or exercise of
any Incentive Award, as applicable.
(f) No Incentive Award and no right under the Plan, contingent or
otherwise, will be assignable or subject to any encumbrance, pledge, or
charge of any nature, or otherwise transferable (meaning, without
limitation, that such Incentive Award or right is exercisable during the
Holder's lifetime only by him or her or by his or her guardian or legal
representative) except that, under such rules and regulations as Edison
International may establish pursuant to the terms of the Plan, a
beneficiary may be designated with respect to an Incentive Award in the
event of death of a Holder of such Incentive Award, and from the time Rule
16b-3 is elected to apply to this Plan, Incentive Awards may be
transferred pursuant to a qualified domestic relations order as defined
by the Code or Title I of the Employee Retirement Income Security Act, or
the regulations promulgated thereunder. If such beneficiary is the
executor or administrator of the estate of the Holder of such Incentive
Award, any rights with respect to such Incentive Award may be transferred
to the person or persons or entity (including a trust) entitled thereto
under the will of the Holder of such Incentive Award, or, in the case of
intestacy, under the laws relating to intestacy.
(g) Notwithstanding Section 17(f), the Committee may, to the extent
permitted by applicable law and Former Rule 16b-3 and/or Rule 16b-3, as
applicable, permit a Holder to assign the rights to exercise Options or
Rights to a trust or to exercise options or rights in favor of a trust,
provided that, in the case of Incentive Stock Options, such exercise in
favor of a trust shall be permitted only if and to the extent that such
exercise is not deemed to be a transfer to or exercise by someone other
than the Holder in contravention of Section 422A(b)(5) of the Code.
(h) Whenever a Holder is entitled to receive cash in lieu of a fractional
share, recognizing that such payment may be deemed a sale of the
underlying Common Stock under Section 16 of the Securities Exchange Act
of 1934, as amended, the Holder may alternatively elect, at least six
months in advance of the payment date, to receive the cash payment or to
forfeit his or her rights to such cash payment. This election will be
evidenced in the Incentive Award agreement.
(i) This Plan shall be governed by the laws of the State of California.
page 11
18. Amendment and Termination of the Plan.
The Board of Directors or the Committee will have the power, in its
discretion, to amend, suspend, or terminate the Plan at any time. No such
amendment will, without approval of the shareholders of Edison
International to the extent required by law or the rules of any exchange
upon which the Common Stock is listed, and except as provided in Section
16 of the Plan:
(a) Materially modify the requirements as to eligibility for
participation in the Plan;
(b) Materially increase the benefits accruing to Eligible Persons under
the Plan; or
(c) Materially increase the number of securities which may be issued
under the Plan.
The Committee may, with the consent of a Holder, make such modifications
in the terms and conditions of any Incentive Award as it deems advisable
or cancel the Incentive Award (with or without consideration). No
amendment, suspension, or termination of the Plan will, without the
consent of the Holder, alter, terminate, impair, or adversely affect any
right or obligation under any Incentive Award previously granted under the
Plan.
19. Termination of Employment.
(a) A Stock Appreciation Right or an Option held by a person who was an
employee at the time such Right or Option was granted will expire
immediately if and when the Holder ceases to be an employee, except as
follows:
(i) If the employment of a Participant is terminated by the Company
other than for cause, then the Stock Appreciation Rights and
Options will expire six months thereafter unless the terms of the
Incentive Award agreement specify otherwise. For purposes of
this provision, termination "for cause" shall include, but shall
not be limited to, termination because of dishonesty, criminal
offense, or violation of work rule, and shall be determined by,
and in the sole discretion of, the Company. During the six-month
period, the Stock Appreciation Rights and Options may be
exercised in accordance with their terms, but only to the extent
exercisable on the date of termination of employment.
(ii) If a Participant dies or becomes permanently and totally disabled
while employed by the Company, the Stock Appreciation Rights and
Options of the Participant will expire three years after the date
of death or permanent and total disability unless the terms of
the Incentive Award agreement specify otherwise. If the
Participant dies or becomes permanently and totally disabled
within the six-month period referred to in subparagraph (a)
above, the Stock Appreciation Rights and Options will expire six
months after the date of death or permanent and total disability,
unless the terms of the Incentive Award agreement specify
otherwise.
page 12
(b) In the event a Holder of other Incentive Awards ceases to be an
employee, all such Incentive Awards will terminate except in the case of
retirement, death, or permanent and total disability. To be eligible for
the full amount of any such Incentive Award, an individual must have been
a Participant for the entire period to which the Incentive Award applies.
Pro-rata awards may be distributed to Participants who are discharged or
who terminate their employment for reasons other than incompetence,
misconduct or fraud, or who retired or became disabled during the
incentive period, or who were Participants for less than the full
incentive period. A pro-rata award may be made to a Participant's
designated beneficiary in the event of death of a Participant during an
incentive period prior to an award being made.
(c) The Committee may in its sole discretion determine, with respect to
an Incentive Award, that any Holder who is on a leave of absence for any
reason will be considered as still in the employ of the Company, provided
that rights to such Incentive Award during an unpaid leave of absence will
be limited to the extent to which such right was earned or vested at the
commencement of such leave of absence.
(d) The Committee may vary the strict requirements of this Section 19 by
agreement at the time of grant, or on a case-by-case basis thereafter, as
it deems appropriate and in the best interests of Edison International.
The Committee may accelerate the vesting of all, or a portion of any
Incentive Award, and may extend the above-described exercise periods to
as long as the term provided in the original Incentive Award agreement.
20. Effective Date of Plan and Duration of Plan.
This Plan as amended and restated will become effective on the date
specified by the Board of Directors of Edison International, subject,
however, to approval by the stockholders of Edison International at their
next annual meeting or at any adjournment thereof, within twelve (12)
months following the date of its adoption by the Board of Directors.
Unless previously terminated by the Board of Directors, the Plan will
terminate April 16, 2002.
EDISON INTERNATIONAL
Beverly P. Ryder
-----------------------------
Beverly P. Ryder
Secretary
EXHIBIT 10.16.2
EDISON INTERNATIONAL
OFFICER AND MANAGEMENT LONG-TERM INCENTIVE COMPENSATION PLANS
1996 AWARD AGREEMENT
This award is made by Edison International to NAME, ("Employee") as of
January 2, 1996 pursuant to the Officer or Management Long-Term Incentive
Compensation Plan and subject to the conditions contained in the 1996
Statement of Terms and Conditions which is incorporated herein by
reference and receipt of which is acknowledged by Employee. Edison
International hereby grants to Employee, as a matter of separate agreement
and not in lieu of salary or any other compensation for services, the
right and option to purchase the following:
XXXX shares of authorized Edison International
Common Stock, coupled with dividend equivalents,
at an exercise price of $0000 per share.
------------------------------------------------
XXX Shares if Edison Mission Energy XXXX Shares of Edison Capital phantom
phantom stock having a base price of $0000stock having a base price of $0000 per
per share and the following exercise prices:share and the following exercise prices:
-------------------------------------------------------------------------------------
Period Price $ Period Price $ Period Price $ Period Price $
------ ------- ------ ------- ------ ------- ------ -------
1997 2002 1997 2002
1998 2002 1998 2002
1999 2004 1999 2004
2000 2005 2000 2005
2001 2006 2001 2006
IN WITNESS WHEREOF, Edison International and Employee have caused this
instrument to be executed as of the day and year first written above.
Edison International Employee
By:---------------------------- By: ----------------------------
page 1
Edison International Officer and Management Long-Term
Incentive Compensation Plans
1996 Statement of Terms and Conditions
1996 Award Grants made under the Edison International Officer and
Management Long-Term Incentive Compensation Plans ("Plans") are subject
to the following terms and conditions:
1. PRICE
(a) The exercise price for the option to purchase Edison International
Common Stock stated in the Award Grant is the average of the high and low
sales prices of Edison International Stock as reported in the Western
Edition of The Wall Street Journal for the New York Stock Exchange
Composite Transactions for the date of grant.
(b) The exercise prices stated in the Award Grant for Edison Mission
Energy and Edison Capital phantom stock options are derived from
escalating base prices as described in Section 5.
2. VESTING
(a) Subject to the provisions of Section 3, only vested options may be
exercised. The initial vesting date will be January 2nd of the year
following the date of the Award Grant, or six months after the date of the
Award Grant, whichever date is later. The options will vest as follows:
o On the initial vesting date, the options will vest as to 33-1/3% of the
covered shares.
o On January 2nd of the following year, the options will vest as to an
additional 33-1/3% of the covered shares.
o On January 2nd of the third year following the date of the Award Grant,
the options will be fully vested.
(b) The vested options will be exercisable by the Employee, subject to the
provisions of Section 3, in whole or in part, in any subsequent period but
not later than the first business day of the 10th year following the date
of the Award Grant, or, in the case of Edison Mission Energy or Edison
Capital phantom stock options, not later than the end of the final 60-day
exercise period.
(c) If an Employee is removed from a position entitling him/her to
benefits under the Plan, retires, dies or is permanently and totally
disabled during the three-year vesting period, the options will vest and
be exercisable to the extent of 1/36th of the aggregate number of shares
originally covered by the options for each full month of service during
the vesting period. Notwithstanding the foregoing, the options of an
officer who has served as a member of the Southern California Edison
Company Management Committee will be fully vested and exercisable upon
his/her retirement, death or permanent and total disability.
(d) Upon termination of an Employee for any reason other than those
specified in Subsection (c), only those options which have vested on or
before the anniversary date of the Award Grant preceding the date of
termination may be exercised, and those options, together with any earned
dividend equivalents, will be forfeited unless exercised within 180 days
following the date of termination, or in the case of Edison Mission Energy
or Edison Capital phantom stock options, the first 60-day exercise period
following the date of termination.
(e) Notwithstanding the foregoing, the options and earned dividend
equivalents may vest in accordance with Section 15 of the Plan as a result
of certain events, including liquidation of Edison International or
merger, reorganization or consolidation of Edison International as a
result of which Edison International is not the surviving corporation.
page 2
3. OPTION EXERCISE
(a) The Employee may exercise an option by providing written notice to
Edison International on the form prescribed by Edison International for
this purpose specifying the number of options to be exercised, and
accompanied by full payment of the exercise price. A sample notice is
attached as Exhibit 1. Payment must be in cash, or its equivalent, such
as Edison International Stock, acceptable to Edison International. A
"cashless" exercise will be accommodated for all Edison Mission Energy and
Edison Capital phantom options, and may be accommodated for Edison
International stock options at the discretion of Edison International.
Until payment is accepted, the Employee will have no rights in the
optioned stock. If Edison International stock options are exercised, the
Employee may elect to apply any earned dividend equivalents related to the
shares for which the options are being exercised to the exercise price for
such shares.
(b) Edison International stock options may be exercised at any time after
they have vested through the first business day of the 10th year following
the date of the Award Grant. Edison Mission Energy and Edison Capital
phantom options may be exercised after they have vested, but only during
an annually specified 60-day period following the fiscal year-end and the
completion of an independently reviewed valuation report which indicates
a share value for the fiscal year higher than the applicable Edison
Mission Energy or Edison Capital phantom stock option exercise price for
that period. The final 60-day Edison Mission Energy or Edison Capital
exercise period will commence no later than the end of the second quarter
of the 10th year following the date of the Award Grant. Edison Mission
Energy and Edison Capital phantom stock options are payable in cash to the
Employee upon exercise to the extent the actual value of an Edison Mission
Energy or Edison Capital share exceeds the applicable exercise price.
(c) The Employee agrees that any securities acquired by him/her hereunder
are being acquired for his/her own account for investment and not with a
view to or for sale in connection with any distribution thereof and that
he/she understands that such securities may not be sold, transferred,
pledged, hypothecated, alienated, or otherwise assigned or disposed of
without either registration under the Securities Act of 1933 or compliance
with the exemption provided by Rule 144 or another applicable exemption
under such act.
(d) In accordance with Section 17(d) of the Plan, the Employee will have
no right or claim to any specific funds, property or assets of Edison
International as a result of the Award Grant.
4. EDISON INTERNATIONAL OPTION DIVIDEND EQUIVALENTS
(a) An Edison International dividend equivalent account will be
established on behalf of the Employee if Edison International stock
options have been granted pursuant to the Award Grant. This account may
be credited with all or a portion of the dividends payable after the date
of grant on the number of shares of stock covered by such Edison
International stock options depending upon Edison International's
performance during the first three years of the option period as provided
in Subsection (b). No amount will be credited prior to January 2nd of the
third year following the date of grant. No dividend equivalent will
accrue to any option exercised during that period regardless of Edison
International performance. Dividend equivalents credited after that date,
if any, will accumulate in this account without interest and will vest and
become payable upon the exercise of the option to purchase the
corresponding shares of Edison International Stock.
(b) Dividend equivalents related to Edison International stock options are
subject to a performance measure based on the percentile ranking of Edison
International's total shareholder return ("TSR") compared to the TSR for
each stock in the Dow Jones Electric Utilities Group Index. The
percentile ranking will be measured at the completion of the three-year
period following the date of grant. If Edison International's average
ranking is in the 60th percentile or higher for the 3-year period, 100%
of the dividend equivalents will be earned from the date of grant through
the date the options are exercised. If Edison International's average
ranking is in the 25th percentile, 25% of the dividend equivalents will
be
page 3
earned. No dividend equivalents will be earned for performance below the
25th percentile, and a pro rata amount will be earned for performance
between the 25th and 60th percentiles.
Dividend equivalents related to unexercised Edison International stock
options that were not earned due to the limitations of this Subsection (b)
may be earned back as of the end of each of the last five years of the
option period if it is determined at that point that the Edison
International cumulative average TSR percentile ranking equals or exceeds
the 60th percentile.
5. EDISON MISSION ENERGY AND EDISON CAPITAL PHANTOM STOCK OPTIONS
(a) The Edison Mission Energy phantom stock options are performance units
under the Plans based on 10 million shares of artificial or "phantom"
Edison Mission Energy stock created for this purpose only. The Edison
Mission Energy phantom stock option exercise prices in the Award Grant
were derived from the base price of a share of Edison Mission Energy
phantom stock by applying a 12% appreciation factor, compounded annually
for the term of the Award Grant. Following the end of each calendar year
during the term of the Award Grant, the actual Edison Mission Energy share
value will be computed. If the actual Edison Mission Energy share value
exceeds the Edison Mission Energy phantom stock option exercise price for
that period, any portion of the vested Edison Mission Energy phantom stock
options may be exercised by the Employee in accordance with Section 3 and
the difference will be paid in cash to the Employee.
(b) The Edison Capital phantom stock options are performance units under
the Plans based on 5 million shares of artificial or "phantom" Edison
Capital stock created for this purpose only. The Edison Capital phantom
stock option exercise prices stated in the Award Grant were derived from
the base price of a share of Edison Capital stock by applying a 10%
appreciation factor, compounded annually for the term of the Award Grant.
Following the end of each calendar year during the term of the Award
Grant, the actual Edison Capital share value will be computed. If the
actual Edison Capital share value exceeds the Edison Capital phantom stock
option exercise price for that period, any portion of the vested Edison
Capital phantom stock option may be exercised by the Employee in
accordance with Section 3 and the difference will be paid in cash to the
Employee.
6. TRANSFER AND BENEFICIARY
The options will not be transferable by the Employee. During the lifetime
of the Employee, the options will be exercisable only by him/her. The
Employee may designate a beneficiary who, upon the death of the Employee,
will be entitled to exercise the then vested portion of the options during
the remaining term of the Award Grant subject to the conditions of the
Plan and the Award Grant.
7. TERMINATION OF OPTIONS
As set forth in Section 2(d), in the event of termination of the
employment of the Employee for any cause, other than retirement, permanent
and total disability or death of the Employee, the options will terminate
180 days from the date on which such employment terminated, or in the case
of Edison Mission Energy or Edison Capital stock options, at the end of
the first 60-day exercise period following the employment termination
date. In addition, the options may be terminated if Edison International
elects to substitute cash awards as provided under Section 11.
8. TAXES
Edison International will have the right to retain and withhold the amount
of taxes required by any government to be withheld or otherwise deducted
and remitted with respect to the exercise of any Edison International,
Edison Mission Energy or Edison Capital option, the receipt of cash, or
the receipt or application by the Employee of any dividend equivalents
under the Award Grant. In its discretion, Edison International may
require the Employee to reimburse Edison International for any such taxes
required to be withheld by Edison International and may withhold any
distribution in whole or in part until Edison International is so
reimbursed. In lieu thereof, Edison International will have the right to
withhold from any other cash amounts due from Edison International to the
Employee an amount equal to such taxes required to be withheld by Edison
International to reimburse Edison International for any such taxes or to
page 4
retain and withhold a number of shares of Edison International Stock
having a market value equal to the taxes and cancel (in whole or in part)
the shares in order to reimburse Edison International for the taxes.
Each recipient of an Edison International Option must attach a statement
to his/her federal and state tax returns for the year in which the Edison
International Option was granted containing certain information about the
option. A sample statement is attached as Exhibit 2.
9. CONTINUED EMPLOYMENT
(a) In consideration of the granting of such options to him/her, the
Employee agrees that he/she will remain in the continuous service of
Edison International or an Edison International affiliate as an officer
or employee during the term of the Award Grant. In the event employment
is terminated, except as a result of death, disability, or retirement
under the Southern California Edison Company Retirement Plan, or a
successor plan, whether voluntarily or otherwise, the restrictions of
Section 2(d) will apply.
(b) Nothing in the Award Grant or this Statement of Terms and Conditions
will be deemed to confer on the Employee any right to continue in the
employ of Edison International or an Edison International affiliate or
interfere in any way with the right of the employer to terminate his/her
employment at any time.
10. NOTICE OF DISPOSITION OF SHARES
Employee agrees that if he/she should dispose of any shares of stock
acquired on the exercise of the Edison International stock options,
including a disposition by sale, exchange, gift or transfer of legal title
within six months from the date such shares are transferred to the
Employee, the Employee will notify Edison International promptly of such
disposition.
11. AMENDMENT
The Award Grant will be subject to the terms of the Plan as amended.
Edison International reserves the right to substitute cash awards
substantially equivalent in value to the options and dividend equivalents.
The options and dividend equivalents which are the subject of the Award
Grant may not otherwise be restricted or limited by any Plan amendment or
termination approved after the date of the Award Grant without the
Employee's written consent.
12. FORCE AND EFFECT
The various provisions of the Award Grant are severable in their entirety.
Any determination of invalidity or unenforceability of any one provision
will have no effect on the continuing force and effect of the remaining
provisions.
13. GOVERNING LAW
This Award Grant will be construed under the laws of the State of
California.
14. NOTICE.
Unless waived by Edison International, any notice required under or
relating to the Award Grant will be in writing, with postage prepaid,
addressed to: Edison International, Attn: Corporate Secretary, P.O. Box
800, Rosemead, CA 91770
Emiko Banfield
- -------------------------------
Emiko Banfield
Vice President, Human Resources
page 5
EXHIBIT 1
Date_________________
Corporate Secretary
Edison International
P.O. Box 800
Rosemead, CA 91770
Dear Sir or Madam:
I hereby elect to exercise an option to purchase _____________ shares,
no par value, of the Common Stock of Edison International under and
pursuant to the Officer or Management Long-Term Incentive Compensation
Plan Award Grant dated ___________________. Delivered herewith is my
check in the amount of $_______________in full payment of the exercise
price.
I elect/do not elect to apply any corresponding dividend equivalents
to the exercise price.
The name(s) to be on the stock certificate or certificates and the address
and Social Security Number of such person is as follows:
Name:
Address:
Social Security Number:
AND/OR
I hereby elect to exercise my option on _________ shares of ____ (specify
Edison Mission Energy or Edison Capital) phantom stock pursuant to the
Officer or Management Long-Term Incentive Compensation Plan Award Grant
dated________________.
Very truly yours,
cc: Executive Compensation Manager
Approved:___________________________
Corporate Secretary
page 6
EXHIBIT 2
STATEMENT PURSUANT TO INCOME TAX
REGULATION SECTION 1.61-15(c)
This statement is attached to my income tax return in compliance with
the requirements of Income Tax Regulation Section 1.61-15(c) relative to a
nonqualified stock option I received on _____________, 19__.
(1) Name and address of the taxpayer:
John Q. Doe
1234 Your Street
Anywhere, CA 90000
(2) Description of Securities subject to the option:
On ____________, 19__, I was granted a nonqualified stock option
covering shares of Edison International common stock.
(3) Period during which the option is exercisable:
The option vests and becomes exercisable as to one-third of the covered
shares on _______________, 19__, ______________, 19__ and ______________,
19__, respectively. To the extent vested, the option may be exercised at
any time through January 2, 20__.
(4) Whether the option had an ascertainable market value:
The option did not have a readily ascertainable fair market value on
the date of the grant.
(5) Whether the option was granted as compensation:
The option was granted as compensation and is subject to Reg. Section
1.61-15(a).
Respectfully Submitted,
EXHIBIT 12
SOUTHERN CALIFORNIA EDISON COMPANY AND CONSOLIDATED UTILITY-RELATED
SUBSIDIARIES
RATIOS OF EARNINGS TO FIXED CHARGES
(Thousands of Dollars)
Year Ended December 31,
----------------------
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
EARNINGS BEFORE INCOME
TAXES AND FIXED CHARGES:
Income before interest
expense(1) $1,172,285 $1,190,051 $1,127,275 $1,081,800 $1,143,477 $1,108,410
Add:
Taxes on income(2) 412,922 443,548 408,033 452,091 509,632 511,819
Rentals(3) 7,539 4,460 3,463 3,512 4,018 3,269
Allocable portion of interest
on long-term Contracts for
the purchase of power(4) 1,925 1,908 1,890 1,870 1,848 1,824
Spent nuclear fuel interest(6) 1,683 1,339 487 68 - -
Amortization of previously
capitalized fixed charges 31,149 22,344 4,878 2,271 1,185 814
---------- ---------- ---------- --------- --------- ---------
Total earnings before
income taxes and fixed
charges (A) $1,627,503 $1,663,650 $1,546,026 $1,541,612 $1,660,160 $1,626,136
========== ========== ========== ========== ========== ==========
FIXED CHARGES:
Interest and amortization $ 542,732 $ 517,142 $449,230 $443,219 $ 463,786 $ 453,015
Rentals(3) 7,539 4,460 3,463 3,512 4,018 3,269
Capitalized fixed charges-
nuclear fuel(5) 2,654 873 978 254 1,531 1,711
Allocable portion of interest
on long-term contracts for
the purchase of power(4) 1,925 1,908 1,890 1,870 1,848 1,824
Spent nuclear fuel interest(6) 1,683 1,339 487 68 - -
---------- ---------- ---------- ---------- ---------- ----------
Total fixed charges(B) $ 556,533 $ 525,722 $ 456,048 $ 448,923 $ 471,183 $ 459,819
========== ========== ========== ========== ========== ==========
RATIO OF EARNINGS TO
FIXED CHARGES(A)/(B): 2.92 3.16 3.39 3.43 3.52 3.54
========== ========== ========== ========== ========== ==========
(1) Includes allowance for funds used during construction and accrual of unbilled revenue.
(2) Includes allocation of federal income and state franchise taxes to other income.
(3) Rentals include the interest factor relating to certain significant rentals plus one-third of all
remaining annual rentals.
(4) Allocable portion of interest included in annual minimum debt service requirement of supplier.
(5) Includes fixed charges associated with Nuclear Fuel.
(6) Represents interest on spent nuclear fuel disposal obligation.
EXHIBIT 13
Southern California Edison Company
1996 Annual Report
A Profile of Southern California Edison Company
Southern California Edison (SCE) is the nation's second-largest electric
utility, based on the number of customers. Headquartered in Rosemead,
California, SCE is a subsidiary of Edison International, which is
primarily an energy-services company.
SCE, a 110-year-old investor-owned utility, serves 4.2 million customers
in Central and Southern California. More than 11 million people live in
its 50,000-square-mile service territory.
Contents
1 Selected Financial and Operating Data: 1992-1996
2 Management's Discussion and Analysis of
Results of Operations and Financial Condition
11 Consolidated Financial Statements
15 Notes to Consolidated Financial Statements
31 Quarterly Financial Data
32 Responsibility for Financial Reporting
33 Report of Independent Public Accountants
34 Board of Directors
34 Executive Officers
PAGE
Selected Financial and Operating Data: 1992-1996
Southern California Edison Company
Dollars in millions 1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Income statement data:
Operating revenue $7,583 $ 7,873 $ 7,799 $7,397 $ 7,722
Operating expenses 6,450 6,724 6,705 6,232 6,492
Fuel and purchased power expenses 3,336 3,197 3,403 3,290 3,086
Income tax from operations 578 560 508 506 520
Allowance for funds used during construction 25 34 29 36 37
Interest expense - net 453 464 443 449 517
Net income 655 680 639 678 673
Earnings available for common stock 621 643 599 637 631
Ratio of earnings to fixed charges 3.54 3.52 3.43 3.39 3.16
- ------------------------------------------------------------------------------------------------------------
Balance sheet data:
Assets $17,737 $18,155 $18,076 $18,098 $15,969
Gross utility plant 21,134 20,717 20,127 19,441 18,652
Accumulated provision for depreciation and
decommissioning 9,431 8,569 7,710 7,138 6,544
Common shareholder's equity 5,045 5,144 5,039 4,932 4,775
Preferred stock:
Not subject to mandatory redemption 284 284 359 359 359
Subject to mandatory redemption 275 275 275 275 278
Long-term debt 4,779 5,215 4,988 5,234 5,184
Capital structure:
Common shareholder's equity 48.6% 47.1% 47.3% 45.7% 45.1%
Preferred stock:
Not subject to mandatory redemption 2.7% 2.6% 3.3% 3.3% 3.4%
Subject to mandatory redemption 2.7% 2.5% 2.6% 2.5% 2.6%
Long-term debt 46.0% 47.8% 46.8% 48.5% 48.9%
- ------------------------------------------------------------------------------------------------------------
Operating data:
Peak demand in megawatts (MW) 18,207 17,548 18,044 16,475 18,413
Generation capacity at peak (MW) 21,602 21,603 20,615 20,606 20,712
Kilowatt-hour sales (kWh) (in millions) 75,572 74,296 77,986 73,308 74,186
Average annual kWh sales per residential
customer 6,322 6,188 6,259 6,070 6,311
Total energy requirement (kWh) (in millions) 84,236 81,924 85,011 81,328 82,199
Energy mix:
Thermal 47.6% 51.6% 59.5% 53.8% 59.8%
Hydro 6.9% 7.7% 3.9% 7.3% 3.4%
Purchased power and other sources 45.5% 40.7% 36.6% 38.9% 36.8%
Customers (in millions) 4.22 4.18 4.15 4.12 4.11
Full-time employees* 12,057 14,886 16,351 16,585 16,922
*1992-1994 are based on twelve-month averages.
page 1
Management's Discussion and Analysis of Results of Operations
and Financial Condition
In the following Management's Discussion and Analysis of Results of
Operations and Financial Condition and elsewhere in this annual report,
the words "estimates," "expects," "anticipates," "believes," and other
similar expressions, are intended to identify forward-looking information
that involves risks and uncertainties. Actual results or outcomes could
differ materially as a result of such important factors as the outcome of
state and federal regulatory proceedings affecting the restructuring of
the electric utility industry, the impacts of new laws and regulations
relating to restructuring and other matters, the effects of increased
competition in the electric utility business, and changes in prices of
electricity and costs for fuel.
Results of Operations
Earnings
Southern California Edison Company's (SCE) 1996 earnings were $621
million, compared with $643 million in 1995 and $599 million in 1994.
Included in earnings are special charges of $18 million in 1996, $15
million in 1995 and $18 million in 1994, primarily related to workforce
management costs. Excluding special charges, SCE's 1996 earnings
decreased $19 million over 1995. The decreased earnings are primarily
attributable to a reduction in authorized rates of return and operating
expenses, partially offset by improved operating performance. Excluding
special charges, SCE's 1995 earnings increased $41 million over 1994,
primarily due to a higher authorized return on common equity for 1995,
partially offset by the financial effect of the 1995 general rate case
settlement.
Operating Revenue
Operating revenue decreased 4% from 1995, as increased sales volume was
offset by lower average rates. The lower rates are attributable to the
California Public Utilities Commission's (CPUC) decision to lower SCE's
1996 authorized revenue by 4.4%. Additionally, during 1996 SCE issued a
one-time bill credit of $237 million to ratepayers as part of a CPUC-
ordered refund of energy-cost balancing account overcollections. Operating
revenue in 1995 increased slightly over 1994, mainly due to a 2.6% CPUC-
authorized rate increase, partially offset by a decrease in sales volume
to resale cities and milder weather in 1995. In 1996, over 98% of
operating revenue was from retail sales. Retail rates are regulated by the
CPUC and wholesale rates are regulated by the Federal Energy Regulatory
Commission (FERC).
Due to warm weather during the summer months, operating revenue during the
third quarter of each year is materially higher than the other quarters.
The changes in operating revenue resulted from:
In millions Year ended December 31, 1996 1995 1994
Operating revenue - net
Rate changes $ (522) $ 168 $ 112
Sales volume changes 206 (120) 308
Other 26 35 (18)
------ ------ ------
Total $ (290) $ 74 $ 402
====== ====== ======
In March 1995, SCE announced its intention to freeze average rates for
residential, small business and agricultural customers through 1996, and
announced a five-year goal to reduce system average rates by 25% on an
inflation-adjusted basis (from 10.7 cents per kilowatt-hour to below 10
cents per kilowatt-hour). In February 1996, the CPUC approved a system-
wide rate reduction which will drop the average price per kilowatt-hour
from 10.7 cents to 10.1 cents. Legislation enacted in September 1996
provides for, among other things, at least a 10% rate reduction for
residential and small commercial customers beginning in 1998 (see
discussion under Competitive Environment).
page2
Southern California Edison Company
Operating Expenses
Fuel expense increased slightly in 1996 due to higher gas prices and
changes in the fuel mix. Fuel expense decreased 27% in 1995 from 1994,
since hydro generation was up significantly in 1995 due to greater
rainfall, resulting in lower gas purchases. In addition, the San Onofre
Nuclear Generating Station units were out of service a total of five
months in 1995 for refueling and maintenance, causing a decrease in
nuclear fuel expense. Lower overall gas prices in 1995 also contributed
to the decrease in energy costs.
Purchased-power expense increased slightly in 1996 and 1995, due to an
increase in power purchased under federally mandated contracts. SCE is
required under federal law to purchase power from certain nonutility
generators even though energy prices under these contracts are generally
higher than other sources. In 1996, SCE paid about $1.7 billion
(including energy and capacity payments) more for these power purchases
than the cost of power available from other sources. The CPUC has
mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially in
1996, compared to 1995. The decrease is mainly due to the energy-cost
balancing account-related refund as discussed above, lower base rate
revenue and undercollections related to the accelerated recovery of SCE's
remaining investment in San Onofre Units 2 and 3 (see discussion in Note
1 to the Consolidated Financial Statements). The provisions increased in
1995, as CPUC-authorized fuel and purchased-power cost estimates exceeded
actual energy costs. Actual energy costs were lower than estimated in
1995, due to the increase in hydro generation and lower gas prices.
Other operating expenses declined in both 1996 and 1995, due to ongoing
cost reduction efforts and improved operating performance.
Maintenance expense decreased 8% in 1996, due to lower overall costs at
SCE's generation, transmission and distribution operating facilities.
Maintenance expense increased 8% in 1995, due to higher expenses related
to the scheduled refueling and maintenance outages at San Onofre Units 2
and 3.
Depreciation and decommissioning expense increased 12% in 1996. The change
is due to higher depreciation rates and the accelerated recovery of San
Onofre Units 2 and 3.
Income taxes increased slightly during 1996, mainly due to an increase in
deferred taxes resulting from the accelerated recovery of San Onofre Units
2 and 3.
Other Income and Deductions
The provision for rate phase-in plan reflects a CPUC-authorized, 10-year
rate phase-in plan, which deferred the collection of revenue during the
first four years of operation for the Palo Verde Nuclear Generating
Station. The deferred revenue (including interest) is being collected
evenly over the final six years of each unit's plan. The plan ended in
February 1996 and September 1996 for Units 1 and 2, respectively. The
plan ends in January 1998 for Unit 3. The provision is a non-cash offset
to the collection of deferred revenue.
Other nonoperating income decreased substantially in 1996, compared to
1995, primarily due to additional accruals for regulatory matters. Other
nonoperating income decreased in 1995, as CPUC-authorized incentive awards
were below 1994 levels.
Interest Expense
Other interest expense decreased in 1996, due to the lower levels of
short-term debt and lower interest rates. Other interest expense
increased 30% in 1995, due to higher interest rates and higher balances
in the regulatory balancing accounts.
Financial Condition
SCE's liquidity is primarily affected by debt maturities, dividend
payments and capital expenditures. Capital resources include cash from
operations and external financings.
In June 1994, SCE lowered its quarterly common stock dividend to its
parent, Edison International, by 30%, due to the uncertainty of future
earnings levels arising from the changing nature of California's electric
utility regulation.
page 3
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Currently, Edison International has authorized the repurchase of up to
$800 million of its common stock. Edison International has repurchased
27.4 million shares ($497 million) through January 31, 1997, funded by
dividends from its subsidiaries and its lines of credit. As excess cash
becomes available, SCE intends to pay cash dividends to Edison
International, while maintaining its CPUC-authorized capital structure.
SCE's cash flow coverage of dividends during 1996 decreased to 2.2 times
from 3.5 times in 1995 and 3.1 times in 1994, due to the additional cash
needs of Edison International for debt repayment and other cash needs.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.8 billion in 1996,
$2.0 billion in 1995 and $1.8 billion in 1994. Cash from operations
exceeded capital requirements for all years presented.
Cash Flows from Financing Activities
Short-term debt is used to finance fuel inventories, balancing account
undercollections and general cash requirements. Long-term debt is used
mainly to finance capital expenditures. External financings are
influenced by market conditions and other factors, including limitations
imposed by its articles of incorporation and trust indenture. As of
December 31, 1996, SCE could issue approximately $7.9 billion of
additional first and refunding mortgage bonds and $4.5 billion of
preferred stock at current interest and dividend rates.
At December 31, 1996, SCE had available lines of credit of $1.1 billion,
with $600 million for short-term debt and $500 million for the long-term
refinancing of its variable-rate pollution-control bonds. These unsecured
lines of credit are at negotiated or bank index rates with various
expiration dates; the majority have five-year terms.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital
structure, limiting the dividends it may pay Edison International. At
December 31, 1996, SCE had the capacity to pay $112 million in additional
dividends and continue to maintain its authorized capital structure.
Cash Flows from Investing Activities
The primary uses of cash for investing activities are additions to
property and plant and funding of nuclear decommissioning trusts.
Decommissioning costs are accrued and recovered in rates over the term of
each nuclear generating facility's operating license through charges to
depreciation expense. SCE estimates that it will spend approximately
$12.7 billion between 2013-2070 to decommission its nuclear facilities.
This estimate is based on SCE's current-dollar decommissioning costs ($2.0
billion), escalated using a 6.65% annual rate. These costs are expected
to be funded from independent decommissioning trusts which receive SCE
contributions of approximately $100 million per year until decommissioning
begins.
Projected Capital Requirements
SCE's projected construction expenditures for the next five years are:
1997--$802 million; 1998--$636 million; 1999--$664 million; 2000--$647
million; and 2001--$650 million.
Long-term debt maturities and sinking fund requirements for the next five
years are: 1997--$501 million; 1998-$447 million; 1999--$155 million;
2000--$325 million; and 2001--$400 million.
Regulatory Matters
SCE's 1997 CPUC-authorized rates remain unchanged from 1996 levels due to
the recently enacted legislation which requires that system average rates
remain frozen at the June 10, 1996, level of 10.1 cents per kilowatt-hour
(see discussion in Competitive Environment).
page 4
Southern California Edison Company
The CPUC's 1997 cost-of-capital decision authorized an 11.6% return on
common equity and a 48% common equity ratio, both unchanged from 1996
levels. SCE's return on rate base was lowered from 9.55% to 9.49%. The
decision, excluding the effects of other rate actions, would reduce 1997
earnings by approximately $5 million.
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the Office of
Ratepayer Advocates (ORA) which resulted in a $39 million (including
interest) refund to SCE's customers. The refund, which had been
previously reserved, was completed by year-end 1996.
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA 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 $13.3 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding SCE's
Canadian supply and transportation agreements reasonable for the duration
of their terms and that the costs under these contracts be reviewed on a
yearly basis. In October 1996, the ORA issued its report for the 1995
record period recommending a $37.6 million disallowance for excessive
costs incurred from April 1994 through March 1995. Both proposed
disallowances have been consolidated into one proceeding. SCE and the ORA
have filed several rounds of testimony on this issue. Hearings began in
January 1997 and are expected to conclude in February 1997. A decision
is expected in late 1997.
On December 23, 1996, the CPUC issued a final decision on SCE's proposal
for a new rate mechanism for its 15.8% share of the three units at Palo
Verde. The decision adopts the Palo Verde All-Party Settlement filed with
the CPUC on November 15, 1996. The settlement was based on a Memorandum
of Understanding signed by all of the active parties to the Palo Verde
proceeding. Under the settlement, SCE has the opportunity to recover
its remaining investment (approximately $1.2 billion) in Palo Verde
beginning January 1, 1997, and ending December 31, 2001, earning a reduced
rate of return on rate base of 7.35% instead of the current 9.49%. Also,
SCE will utilize a balancing account to pass through Palo Verde's
incremental operating costs (considered reasonable as long as they do not
exceed 30% of a baseline forecast and the site's gross annual capacity
factor does not go below 55%) to ratepayers. Beginning January 1, 1998,
this balancing account will become part of the competition transition
charge (CTC) mechanism. If SCE's actual costs are less than the forecast,
the difference will benefit ratepayers as a credit to the CTC mechanism.
The existing nuclear unit incentive procedure will continue only for
purposes of calculating a reward for performance of any unit above an 80%
capacity factor for a fuel cycle. After 2001, SCE's ratepayers will
receive 50% of the benefits derived from the operation of Palo Verde.
The decision is projected to reduce SCE's 1997 earnings by approximately
$21 million.
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 industry.
On September 23, 1996, the State of California enacted legislation to
provide a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision
(discussed below) by addressing stranded-cost recovery for utilities,
providing a certain cost recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, thereby
allowing SCE to give a rate reduction of at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of
a
page 5
Management's Discussion and Analysis of Results of Operations
and Financial Condition
non-bypassable CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Finally, the
legislation contains provisions for the recovery (through 2006) of
reasonable employee-related transition costs incurred and projected for
retraining, severance, early retirement, outplacement and related expenses
for utility workers. In light of the legislation, the CPUC is reassessing
the need to prepare an environmental impact report.
In December 1995, the CPUC issued its decision on restructuring
California's electric utility industry. The transition to a new market
structure, which is expected to provide competition and customer choice,
would begin January 1, 1998, with all consumers participating by 2003
(changed to 2002 by the recently enacted legislation). Key elements of
the CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from and sell to the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore,
control the scheduling and dispatch of all electricity on the state's
power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the
existing framework and reasonable employee-related costs) through a
non-bypassable charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture
(through spin-off or sale to an unaffiliated entity) of at least 50%
of utilities' gas-fueled generation to address market power issues.
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the FERC regarding the creation of
the PX and the ISO. On November 26, 1996, the FERC conditionally accepted
the proposal and directed the three utilities to file more specific
information by March 31, 1997. In July 1996, the three utilities jointly
filed an application with the CPUC requesting approval to establish a
restructuring trust which would obtain loans up to $250 million for the
development of the ISO and PX through January 1, 1998. The loans would
be backed by utility guarantees; SCE's share would be 45%. Once the ISO
and PX are formed, they will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million which will be used to build the hardware and software
systems for the ISO and PX.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, transmission and distribution (T&D), nuclear decommissioning and
public benefit programs). Nevertheless, the CPUC directed that the
amended application provide estimates of SCE's potential transition costs
from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value), assuming the fossil plants have
a market value equal to their net book value, and $13.8 billion (1998 net
present value), assuming the fossil plants have no market value. These
estimates are based on incurred costs, and forecasts of future costs and
assumed market prices. However, changes in the assumed market prices
could materially affect these estimates. The potential transition
costs are comprised of:
page 6
Southern California Edison Company
$7.5 billion from SCE's qualifying facility contracts, which are the
direct result of legislative and regulatory mandates; and $5.6 billion to
$6.3 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 San Onofre (as discussed in Note 1 to the Consolidated
Financial Statements) and Palo Verde, nuclear decommissioning and certain
other costs.
On November 27, 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil-and gas-fueled generation
divestiture was requested for late 1997.
In September 1996, the CPUC adopted a non-generation T&D PBR mechanism for
SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations. In July 1996, SCE filed
a PBR proposal for its hydroelectric plants and a proposed structure for
performance-based local reliability contracts for certain fossil-fueled
plants. If approved, the hydro PBR would be in effect for three years
and the initial terms of the local reliability contracts, which are
subject to FERC approval, would be in effect for up to three years, both
beginning January 1, 1998. A final CPUC decision on hydro PBR is expected
by year-end 1997.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public benefit programs and the CTC. The filing was in
response to CPUC and FERC directives which require electric services, such
as T&D, to be functionally separate and available to all customers on a
nondiscriminatory basis without cost-shifting among customers. On
December 6, 1996, SCE filed a more comprehensive plan for the functional
unbundling of SCE's rates for electric service, beginning on January 1,
1998. In response to CPUC and FERC orders, as well as the new
restructuring legislation, this filing addressed the implementation-level
detail for the functional unbundling of rates in separate charges for
energy, transmission, distribution, the CTC, public benefit programs and
nuclear decommissioning. The filing also included proposals for
establishing new regulatory proceedings to replace current proceedings
that will no longer be necessary during the rate freeze period.
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 physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have write-offs
associated with these costs if they are not recovered through another
regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
page 7
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Subsequent Event
If the CPUC's restructuring is implemented as outlined, SCE would be
allowed to recover its CTC (subject to a lower return on equity) and
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996, SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and its
independent accountants continue to believe that SCE meets such criteria
and plan to meet with the SEC staff to present additional and clarifying
information seeking to convince the SEC staff of the merits of SCE's
position. The authority to require SCE to discontinue applying regulatory
accounting standards rests with the SEC. If SCE is required to
discontinue the application of these accounting standards for its
generation-related assets, it would have to write off generation-related
regulatory assets, which at December 31, 1996, totaled approximately $600
million on an after-tax basis, primarily for the recovery of income tax
benefits previously flowed-through to customers, the Palo Verde phase-in
plan and unamortized loss on reacquired debt.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
FERC Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision requires all
electric utilities subject to the FERC's jurisdiction to file transmission
tariffs which provide competitors with increased access to transmission
facilities for wholesale transactions and also establishes information
requirements for the transmission utility. The decision also provides
utilities with the recovery of stranded costs, which are prior-service
costs incurred under the current regulatory framework. In addition to
providing recovery of stranded costs associated with existing wholesale
customers, the FERC directed that it would have primary jurisdiction over
the recovery of stranded costs associated with retail-turned-wholesale
customers, such as the formation of a new municipal electric system.
Retail stranded costs resulting from a state-authorized retail direct-
access program are the responsibility of the states and the FERC would
only address recovery of these costs if the state has no authority to do
so. In compliance with the April 1996 FERC decision, SCE filed a revised
open access tariff with the FERC in July 1996. The tariff became
effective on an interim basis, subject to refund, as of its filing
date. Several wholesale customers have filed protests with the FERC
on the transmission rate levels, and a ruling from the FERC setting the
rates to be decided at formal hearings is anticipated in early 1997.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which
require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect
of past operations on the environment.
As further discussed in Note 10 to the Consolidated Financial Statements,
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely
page 8
Southern California Edison Company
cleanup costs can be estimated. SCE reviews its sites and measures the
liability quarterly, by assessing a range of reasonably likely costs for
each identified site. Unless there is a probable amount, SCE records the
lower end of this likely range of costs.
SCE's recorded estimated minimum liability to remediate its 55
identified sites was $114 million at December 31, 1996. One of SCE's
sites, a former pole-treating facility, is considered a federal Superfund
site and represents 71% of its recorded liability. The ultimate costs to
clean up SCE's identified sites may vary from its recorded liability due
to numerous uncertainties inherent in the estimation process. SCE
believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $211 million.
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 35 of its
sites, representing $101 million of its recorded liability, through an
incentive mechanism. Under this mechanism, SCE will recover 90% of
cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and
other third parties. SCE has successfully settled insurance claims with
a number of its carriers. Costs incurred at the remaining 20 sites are
expected to be recovered through customer rates. SCE has recorded a
regulatory asset of $104 million for its estimated minimum environmental-
cleanup costs expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible
for contributing to any costs incurred for remediating these sites. Thus,
no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30
years. Remediation costs in each of the next several years are expected
to range from $4 million to $8 million. Recorded costs for 1996 were $7
million.
Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not have a
material adverse effect on its results of operations or financial
position. There can be no assurance, however, that future developments,
including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
The 1990 federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions
allowances from the federal government and may bank or sell excess
allowances. SCE expects to have excess allowances under Phase II of the
Clean Air Act (2000 and later). The act also calls for a study to
determine if additional regulations are needed to reduce regional haze in
the southwestern U.S. In addition, another study is in progress to
determine the specific impact of air contaminant emissions from the Mohave
Coal Generating Station on visibility in Grand Canyon National Park. The
potential effect of these studies on sulfur dioxide emissions regulations
for Mohave is unknown.
SCE's projected capital expenditures to protect the environment are $900
million for the 1997-2001 period, mainly for aesthetics treatment,
including undergrounding certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects is receiving increased
attention. The scientific community has not yet reached a consensus on
the nature of any health effects of EMF. However, the CPUC has issued a
decision which provides for a rate-recoverable research and public
education program conducted by California electric utilities, and
authorizes these utilities to take no-cost or low-cost steps to reduce EMF
in new electric facilities. SCE is unable to predict when or if the
scientific community will be able to reach a consensus on any health
effects of EMF, or the effect that such a consensus, if reached, could
have on future electric operations.
page 9
Management's Discussion and Analysis of Results of Operations
and Financial Condition
Palo Verde Steam Tube Rupture
In 1993, a steam generator tube ruptured at Palo Verde Unit 2; additional
cracking was found in other tubes. Arizona Public Service Company (APS),
the operating agent for Palo Verde, has taken, and will continue to take,
remedial actions that it believes have slowed the rate of steam generator
tube degradation in all three units. APS believes that the steam
generators in only one of the units will have to be replaced within five
to ten years. Based on APS' 100% share estimate, SCE estimates its
share of the costs to be between $22 million and $24 million, plus
replacement power costs. SCE is evaluating APS' analyses, conducting its
own review, and has not yet decided whether it supports replacement of the
steam generators.
Workforce Reductions
During 1996, SCE offered a voluntary retirement program to certain
eligible employees. Approximately 3,000 employees (2,200 non-represented
and 800 represented employees) accepted the terms of this program. After
allowance for the effects of pension settlement gains, SCE's net expense
for this program was $4 million.
Proposed New Accounting Standard
During 1996, the Financial Accounting Standards Board issued an exposure
draft that would establish accounting standards for the recognition and
measurement of closure and removal obligations. The exposure draft would
require the estimated present value of an obligation to be recorded as a
liability, along with a corresponding increase in the plant or regulatory
asset accounts when the obligation is incurred. If the exposure draft is
approved in its present form, it would affect SCE's accounting practices
for the decommissioning of its nuclear power plants, obligations for coal
mine reclamation costs and any other activities related to the closure or
removal of long-lived assets. SCE does not expect that the accounting
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
page 10
Consolidated Statements of Income Southern California Edison Company
In thousands Year ended December 31, 1996 1995 1994
- ------------ ---------------------- -----------------------------------------------------------
Operating revenue $ 7,583,382 $ 7,872,718 $ 7,798,601
Fuel 630,512 614,954 840,607
Purchased power 2,705,880 2,581,878 2,562,890
Provisions for regulatory adjustment clauses-net (225,908) 229,744 54,772
Other operating expenses 1,178,316 1,226,534 1,315,249
Maintenance 329,371 356,693 330,161
Depreciation and decommissioning 1,063,505 954,141 890,656
Income taxes 578,329 559,694 507,626
Property and other taxes 190,284 200,236 202,711
------------------------------------------------------------
Total operating expenses 6,450,289 6,723,874 6,704,672
------------------------------------------------------------
Operating income 1,133,093 1,148,844 1,093,929
------------------------------------------------------------
Provision for rate phase-in plan (84,288) (122,233) (136,596)
Allowance for equity funds used during construction 15,579 19,082 14,348
Interest income 37,855 37,644 31,082
Other nonoperating income-net (3,623) 45,651 64,597
------------------------------------------------------------
Total other income (deductions)-net (34,477) (19,856) (26,569)
------------------------------------------------------------
Income before interest expense 1,098,616 1,128,988 1,067,360
------------------------------------------------------------
Interest on long-term debt 380,812 385,187 381,827
Other interest expense 73,914 80,130 61,646
Allowance for borrowed funds used during construction (9,794) (14,489) (14,440)
Capitalized interest (1,711) (1,531) (254)
------------------------------------------------------------
Total interest expense-net 443,221 449,297 428,779
------------------------------------------------------------
Net income 655,395 679,691 638,581
Dividends on preferred stock 34,395 36,764 40,080
------------------------------------------------------------
Earnings available for common stock $ 621,000 $ 642,927 $ 598,501
============================================================
Consolidated Statements of Retained Earnings
In thousands Year ended December 31, 1996 1995 1994
---- ---- ----
Balance at beginning of year $ 2,780,058 $ 2,683,568 $ 2,586,890
Net income 655,395 679,691 638,581
Dividends declared on common stock (735,429) (545,672) (501,823)
Dividends declared on preferred stock (34,395) (36,764) (40,080)
Reacquired capital stock expense (17) (765) -
----------- ------------ ------------
Balance at end of year $ 2,665,612 $ 2,780,058 $ 2,683,568
=========== ============ ============
The accompanying notes are an integral part of these financial statements.
page 11
Consolidated Balance Sheets
In thousands December 31, 1996 1995
ASSETS
Utility plant, at original cost $ 20,400,387 $ 19,850,179
Less-accumulated provision for depreciation
and decommissioning 9,431,071 8,569,265
------------- ------------
10,969,316 11,280,914
Construction work in progress 556,645 727,865
Nuclear fuel, at amortized cost 176,827 139,411
------------- ------------
Total utility plant 11,702,788 12,148,190
------------- ------------
Nonutility property - less accumulated provision
for depreciation of $25,102 and $25,454
at respective dates 63,931 70,191
Nuclear decommissioning trusts 1,485,525 1,260,095
Other investments 103,973 65,963
------------- ------------
Total other property and investments 1,653,429 1,396,249
------------- ------------
Cash and equivalents 319,942 261,767
Receivables, including unbilled revenue, less allowances
of $26,079 and $24,139 for uncollectible accounts
at respective dates 921,083 911,963
Fuel inventory 72,480 114,357
Materials and supplies, at average cost 154,266 151,180
Accumulated deferred income taxes - net 240,429 476,725
Prepayments and other current assets 105,137 114,289
------------- ------------
Total current assets 1,813,337 2,030,281
------------- ------------
Unamortized debt issuance and reacquisition expense 346,834 350,563
Rate phase-in plan 50,703 129,714
Unamortized nuclear plant - net - 67,185
Income tax-related deferred charges 1,741,091 1,723,605
Other deferred charges 428,370 309,328
------------- ------------
Total deferred charges 2,566,998 2,580,395
------------- ------------
Total assets $ 17,736,552 $ 18,155,115
============= ============
The accompanying notes are an integral part of these financial statements.
page 12
Southern California Edison Company
In thousands, except share amounts December 31, 1996 1995
----------- ---- ----
CAPITALIZATION AND LIABILITIES
Common shareholder's equity:
Common stock (434,888,104 shares outstanding
at each date) $ 2,168,054 $ 2,168,054
Additional paid-in capital and other 210,857 195,815
Retained earnings 2,665,612 2,780,058
------------- ------------
5,044,523 5,143,927
Preferred stock:
Not subject to mandatory redemption 283,755 283,755
Subject to mandatory redemption 275,000 275,000
Long-term debt 4,778,703 5,215,117
------------- ------------
Total capitalization 10,381,981 10,917,799
------------- ------------
Other long-term liabilities 423,925 344,192
------------- ------------
Current portion of long-term debt 501,470 1,375
Short-term debt 230,149 359,508
Accounts payable 392,779 346,258
Accrued taxes 484,688 550,384
Accrued interest 93,363 86,494
Dividends payable 108,563 138,334
Regulatory balancing accounts - net 181,488 337,867
Deferred unbilled revenue and other current liabilities 825,317 778,476
------------- ------------
Total current liabilities 2,817,817 2,598,696
------------- ------------
Accumulated deferred income taxes - net 3,170,696 3,323,190
Accumulated deferred investment tax credits 347,118 374,142
Customer advances and other deferred credits 595,015 597,096
------------- ------------
Total deferred credits 4,112,829 4,294,428
------------- ------------
Commitments and contingencies
(Notes 2, 8, 9 and 10)
Total capitalization and liabilities $ 17,736,552 $ 18,155,115
============= ============
The accompanying notes are an integral part of these financial statements.
page 13
Consolidated Statements of Cash Flows Southern California Edison Company
In thousands Year ended December 31, 1996 1995 1994
----------- ------------ ------------
Cash flows from operating activities:
Net income $ 655,395 $ 679,691 $ 638,581
Adjustments for non-cash items:
Depreciation and decommissioning 1,063,505 954,141 890,656
Amortization 90,931 68,064 126,131
Rate phase-in plan 79,011 111,016 123,479
Deferred income taxes and investment tax credits 46,122 (208,671) (95,218)
Other long-term liabilities 79,733 33,129 44,468
Other - net (153,034) (261) (23,841)
Changes in working capital:
Receivables (9,120) (9,873) (64,311)
Regulatory balancing accounts (156,379) 282,157 (2,222)
Fuel inventory, materials and supplies 38,791 (19,499) (21,087)
Prepayments and other current assets 9,152 (15,511) (1,260)
Accrued interest and taxes (58,827) 34,704 117,819
Accounts payable and other current liabilities 93,362 45,355 89,682
------------ ------------ ------------
Net cash provided by operating activities 1,778,642 1,954,442 1,822,877
------------ ------------ ------------
Cash flows from financing activities:
Long-term debt issued 396,309 393,829 964
Long-term debt repayments (403,957) (422,503) (170,224)
Preferred stock redemptions - (75,000) -
Nuclear fuel financing - net 41,803 31,134 (31,444)
Short-term debt financing - net (129,359) (316,006) 62,420
Dividends paid (799,593) (559,886) (588,917)
Net cash used by financing activities (894,797) (948,432) (727,201)
------------ ------------ ------------
Cash flows from investing activities:
Additions to property and plant (616,427) (772,950) (981,894)
Funding of nuclear decommissioning trusts (148,158) (150,595) (130,155)
Unrealized gain in equity investments 14,900 8,483 9,999
Other - net (75,985) (21,273) (6,453)
------------ ------------ ------------
Net cash used by investing activities (825,670) (936,335) (1,108,503)
------------ ------------ ------------
Net increase (decrease) in cash and equivalents 58,175 69,675 (12,827)
Cash and equivalents, beginning of year 261,767 192,092 204,919
------------ ------------ ------------
Cash and equivalents, end of year $ 319,942 $ 261,767 $ 192,092
============ ============ ============
Cash payments for interest and taxes:
Interest $ 348,691 $ 382,798 $ 365,126
Taxes 545,834 692,780 443,801
The accompanying notes are an integral part of these financial statements.
page 14
Southern California Edison Company
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Southern California Edison Company's (SCE) outstanding common stock is
owned entirely by its parent company, Edison International. SCE is a
public utility which produces and supplies electric energy for its 4.2
million customers in Central and Southern California. The consolidated
financial statements include SCE and its subsidiaries. Intercompany
transactions have been eliminated.
SCE's accounting policies conform with generally accepted accounting
principles (GAAP), including the accounting principles for rate-regulated
enterprises which reflect the rate-making policies of the California
Public Utilities Commission (CPUC) and the Federal Energy Regulatory
Commission (FERC).
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, as further discussed in Note 2 to the
Consolidated Financial Statements. Financial statements prepared in
compliance with GAAP require management to make estimates and assumptions
that affect the amounts reported in the financial statements and
disclosure of contingencies. Actual results could differ from those
estimates. Certain significant estimates related to electric utility
industry restructuring, decommissioning and contingencies, are further
discussed in Notes 2, 9 and 10, respectively.
Certain prior-year amounts were reclassified to conform to the December
31, 1996, financial statement presentation.
Debt Issuance and Reacquisition Expense
Debt premium, discount and issuance expenses are amortized over the life
of each issue. Under CPUC rate-making procedures, debt reacquisition
expenses are amortized over the remaining life of the reacquired debt or,
if refinanced, the life of the new debt.
Financial Instruments
SCE enters into interest rate swap and cap agreements to manage its
interest rate exposure. Interest rate differentials and premiums for
interest rate caps to be paid or received are recorded as adjustments to
interest expense.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil
and natural gas, and under the first-in, first-out method for coal.
Investments
Cash equivalents include tax-exempt investments ($261 million at December
31, 1996, and $235 million at December 31, 1995), and time deposits and
other investments ($43 million at December 31, 1996, and $23 million at
December 31, 1995) with maturities of three months or less.
Net unrealized gains (losses) in equity investments are recorded as a
separate component of shareholder's equity under "Additional paid-in
capital and other." Unrealized gains and losses on decommissioning trust
funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
Nuclear
The CPUC authorized rate phase-in plans to defer the collection of $200
million in revenue for each unit at the Palo Verde Nuclear Generating
Station during the first four years of operation and recover the deferred
revenue (including interest) evenly over the following six years. The
phase-in plans ended in February 1996 and September 1996 for Units 1 and
2, respectively. The plan ends in January 1998 for Unit 3.
page 15
Notes to Consolidated Financial Statements
Decommissioning costs are accrued and recovered in rates over the term of
each nuclear facility's operating license through charges to
decommissioning expense (see Note 9).
Under the Energy Policy Act of 1992, SCE is liable for its share of the
estimated costs to decommission three federal nuclear enrichment
facilities (based on purchases). These costs, which will be paid over 15
years, are recorded as a fuel cost and recovered through customer rates.
In August 1992, the CPUC approved a settlement agreement between SCE and
the CPUC's Office (formerly Division) of Ratepayer Advocates (ORA) to
discontinue operation of San Onofre Nuclear Generating Station Unit 1 at
the end of its then-current fuel cycle because operation of the unit was
no longer cost-effective. In November 1992, SCE discontinued operation
of Unit 1. As part of the agreement, SCE recovered its remaining
investment over a four-year period ending August 1996, earning an 8.98%
rate of return on rate base.
In October 1994, the CPUC authorized accelerated recovery of SCE's nuclear
plant investments by $75 million per year, with a corresponding
deceleration in recovery of its transmission and distribution assets
through revised depreciation estimates over their remaining useful lives.
In April 1996, the CPUC authorized, and SCE began accelerating, the
recovery of its remaining investment of $2.6 billion in San Onofre Units
2 and 3. The accelerated recovery will continue through December 2001
(the original end date of 2003 was changed by legislation enacted in
September 1996), earning a 7.35% fixed rate of return (compared to the
current 9.49%). Future operating costs, including nuclear fuel and
nuclear-fuel financing costs and incremental capital expenditures at San
Onofre Units 2 and 3, are subject to an incentive pricing plan whereby SCE
receives about 4 cents per kilowatt-hour through 2003. Any differences between
these costs and the incentive price will flow through to the shareholders.
Beginning in 2004, SCE will be required to share equally with ratepayers
the benefits received from operation of the units.
Prior to January 1, 1997, the cost of nuclear fuel for Palo Verde,
including disposal, was amortized to fuel expense on the basis of
generation. Under CPUC rate-making procedures in effect for Palo Verde
prior to January 1, 1997, nuclear-fuel financing costs were capitalized
until the fuel was placed into production.
Regulatory Balancing Accounts
The differences between CPUC-authorized and actual base-rate revenue from
kilowatt-hour sales and CPUC-authorized and actual energy costs are
accumulated in balancing accounts until they are refunded to, or recovered
from, utility customers through authorized rate adjustments (with
interest). Income tax effects on balancing account changes are deferred.
Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant
construction. If construction does not occur, these costs are charged to
expense. RD&D expenses are recorded in a balancing account and, at the
end of the rate-case cycle, any authorized but unspent RD&D funds are
refunded to customers. RD&D expenses were $21 million in 1996, $28
million in 1995 and $63 million in 1994.
Revenue
Operating revenue includes amounts for services rendered but unbilled at
the end of each year.
Stock-based Compensation
SCE measures compensation expense relative to stock-based compensation by
the intrinsic-value method.
page 16
Southern California Edison Company
Utility Plant
Plant additions, including replacements and betterments, are capitalized.
Such costs include direct material and labor, construction overhead and
an allowance for funds used during construction (AFUDC). AFUDC represents
the estimated cost of debt and equity funds that finance utility-plant
construction. AFUDC is capitalized during plant construction and reported
in current earnings. AFUDC is recovered in rates through depreciation
expense over the useful life of the related asset. Depreciation of
utility plant is computed on a straight-line, remaining-life basis.
Replaced or retired property and removal costs less salvage are charged
to the accumulated provision for depreciation. Depreciation expense
stated as a percent of average original cost of depreciable utility plant
was 4.2% for 1996, and 3.6% for both 1995 and 1994.
Note 2. Regulatory Matters
Electric Utility Industry Restructuring
On September 23, 1996, the State of California enacted legislation to
provide a transition to a competitive market structure. The legislation
substantially adopts the CPUC's December 1995 restructuring decision
(discussed below) by addressing stranded-cost recovery for utilities,
providing a certain cost recovery time period for the transition costs
associated with utility-owned generation-related assets. Transition costs
related to power-purchase contracts would be recovered through the terms
of their contracts while most of the remaining transition costs would be
recovered through 2001. The legislation also includes provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, thereby
allowing SCE to give a rate reduction of at least 10% to these customers,
beginning January 1, 1998. The financing would occur with securities
issued by the California Infrastructure and Economic Development Bank, or
an entity approved by the Bank. The legislation includes a rate freeze
for all other customers, including large commercial and industrial
customers, as well as provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the
rate freeze, SCE expects to be able to recover its revenue requirement
based on cost-of-service regulation during the 1998-2001 transition
period. In addition, the legislation mandates the implementation of a
non-bypassable competition transition charge (CTC) that provides utilities
the opportunity to recover costs made uneconomic by electric utility
restructuring. Finally, the legislation contains provisions for the
recovery (through 2006) of reasonable employee-related transition costs
incurred and projected for retraining, severance, early retirement,
outplacement and related expenses for utility workers. In light of the
legislation, the CPUC is reassessing the need to prepare an environmental
impact report.
In December 1995, the CPUC issued its decision on restructuring
California's electric utility industry. The transition to a new market
structure, which is expected to provide competition and customer choice,
would begin January 1, 1998, with all consumers participating by 2003
(changed to 2002 by the recently enacted legislation). Key elements of
the CPUC decision include:
o Creation of an independent power exchange (PX) to manage electric
supply and demand. California's investor-owned utilities would be
required to purchase from and sell to the exchange all of their power
during the transition period, while other generators could voluntarily
participate.
o Creation of an independent system operator (ISO) to have operational
control of the utilities' transmission facilities and, therefore,
control the scheduling and dispatch of all electricity on the state's
power grid.
o Availability of customer choice through time-of-use rates, direct
customer access to generation providers with transmission arrangements
through the system operator, and customer-arranged "contracts for
differences" to manage price fluctuations from the PX.
o Recovery of costs to transition to a competitive market (utility
investments, obligations incurred to serve customers under the existing
framework and reasonable employee-related costs) through a non-
bypassable charge, applied to all customers, called the CTC.
o CPUC-established incentives to encourage voluntary divestiture (through
spin-off or sale to an unaffiliated entity) of at least 50% of
utilities' gas-fueled generation to address market power issues.
page 17
Notes to Consolidated Financial Statements
o Performance-based ratemaking (PBR) for those utility services not
subject to competition.
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas &
Electric Company filed a proposal with the FERC regarding the creation of
the PX and the ISO. On November 26, 1996, the FERC conditionally accepted
the proposal and directed the three utilities to file more specific
information by March 31, 1997. In July 1996, the three utilities jointly
filed an application with the CPUC requesting approval to establish a
restructuring trust which would obtain loans up to $250 million for the
development of the ISO and PX through January 1, 1998. The loans would
be backed by utility guarantees; SCE's share would be 45%. Once the ISO
and PX are formed, they will repay the trust's loans and recover funds
from future ISO and PX customers. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million which will be used to build the hardware and software
systems for the ISO and PX.
Recovery of costs to transition to a competitive market would be
implemented through a non-bypassable CTC. This charge would apply to all
customers who were using or began using utility services on or after the
December 20, 1995, decision date. In August 1996, in compliance with the
CPUC's restructuring decision, SCE filed its application to estimate its
1998 transition costs. In October 1996, SCE amended its transition cost
filing to reflect the effects of the legislation enacted in September
1996. Under the rate freeze codified in the legislation, the CTC will be
determined residually (i.e., after subtracting other cost components for
the PX, transmission and distribution (T&D), nuclear decommissioning and
public benefit programs). Nevertheless, the CPUC directed that the
amended application provide estimates of SCE's potential transition costs
from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value), assuming the fossil plants have
a market value equal to their net book value, and $13.8 billion (1998 net
present value), assuming the fossil plants have no market value. These
estimates are based on incurred costs, and forecasts of future costs and
assumed market prices. However, changes in the assumed market prices
could materially affect these estimates. The potential transition costs
are comprised of: $7.5 billion from SCE's qualifying facility contracts,
which are the direct result of legislative and regulatory mandates; and
$5.6 billion to $6.3 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 San Onofre (as discussed in Note 1) and Palo
Verde, nuclear decommissioning and certain other costs.
On November 27, 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all of its oil- and gas-fueled generation
assets. This application builds on SCE's March 1996 plan which outlined
how SCE proposed to divest 50% of these assets. Under the new proposal,
SCE would continue to operate and maintain the divested power plants for
at least two years following their sale, as mandated by the recent
restructuring legislation. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. SCE's proposal is contingent on the overall
electric industry restructuring implementation process continuing on a
satisfactory path. CPUC approval of the oil-and gas-fueled generation
divestiture was requested for late 1997.
In September 1996, the CPUC adopted a non-generation T&D PBR mechanism for
SCE which began on January 1, 1997. According to the CPUC decision,
beginning in 1998, the transmission portion is to be separated from non-
generation PBR and subject to ratemaking under the rules of the FERC. The
distribution-only PBR will extend through December 2001. Key elements of
the non-generation PBR include: T&D rates indexed for inflation based on
the Consumer Price Index less a productivity factor; elimination of the
kilowatt-hour sales adjustment; adjustments for cost changes that are not
within SCE's control; a cost of capital trigger mechanism based on changes
in a bond index; standards for service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders
will share gains and losses from T&D operations. In July 1996, SCE filed
a PBR proposal for its hydroelectric plants and a proposed structure for
performance-based local reliability contracts for certain fossil-fueled
plants. If approved, the hydro PBR would be in effect for three years and
the initial terms of the local reliability contracts, which are subject
to FERC approval, would be in effect for up to three years, both beginning
January 1, 1998. A final CPUC decision on hydro PBR is expected by year-
end 1997.
In July 1996, SCE filed a proposal with the CPUC related to the conceptual
aspects of separating the costs associated with generation, transmission,
distribution, public benefit programs and the CTC. The filing was in
response to CPUC and FERC directives which require electric services, such
as T&D, to be functionally
page 18
Southern California Edison Company
separate and available to all customers on a nondiscriminatory basis
without cost-shifting among customers. On December 6, 1996, SCE filed a
more comprehensive plan for the functional unbundling of SCE's rates for
electric service, beginning on January 1, 1998. In response to CPUC and
FERC orders, as well as the new restructuring legislation, this filing
addressed the implementation-level detail for the functional unbundling
of rates in separate charges for energy, transmission, distribution, the
CTC, public benefit programs and nuclear decommissioning. The filing also
included proposals for establishing new regulatory proceedings to replace
current proceedings that will no longer be necessary during the rate
freeze period.
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 physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
Subsequent Event
If the CPUC's restructuring is implemented as outlined, SCE would be
allowed to recover its CTC (subject to a lower return on equity) and
believes it should be allowed to continue to apply accounting standards
that recognize the economic effects of rate regulation for its generation-
related assets during the 1998-2001 transition period. However, in
response to a request by the staff of the Securities and Exchange
Commission (SEC), in December 1996, SCE submitted its views on the
continued applicability of regulatory accounting standards for its
generation-related assets. In its submittal, SCE and its independent
accountants jointly concluded that, based on their current analysis, SCE
will continue to meet the criteria for applying these accounting standards
through the 1998-2001 transition period. In its February 1997 response,
the SEC staff expressed continuing concern with SCE's conclusion and
indicated that they wanted to meet further with SCE and the other major
California electric utilities to resolve this matter. SCE and its
independent accountants continue to believe that SCE meets such criteria
and plan to meet with the SEC staff to present additional and clarifying
information seeking to convince the SEC staff of the merits of SCE's
position. The authority to require SCE to discontinue applying regulatory
accounting standards rests with the SEC. If SCE is required to
discontinue the application of these accounting standards for its
generation-related assets, it would have to write off generation-related
regulatory assets, which at December 31, 1996, totaled approximately
$600 million on an after-tax basis, primarily for the recovery of income
tax benefits previously flowed-through to customers, the Palo Verde phase-
in plan and unamortized loss on reacquired debt.
SCE believes that a proper application of regulatory accounting standards
will result in it no longer meeting the criteria to apply these accounting
standards to all of its non-hydroelectric generation-related assets after
the end of the 1998-2001 transition period. If SCE continues the
application of these accounting standards during the transition period,
but during the transition period events occur that result in SCE no longer
meeting the criteria for applying such standards, SCE may be required to
write off the remaining balance of its recorded generation-related
regulatory assets existing at that time.
If a non-cash write-off is required, SCE believes that it should not
affect the stranded-cost recovery plans set forth in the CPUC's December
1995 restructuring decision and legislation enacted by the State of
California in September 1996.
FERC Stranded Cost/Open Access Transmission Decision
In April 1996, the FERC issued its decision on stranded cost recovery and
open access transmission, effective July 1996. The decision requires all
electric utilities subject to the FERC's jurisdiction to file transmission
tariffs which provide competitors with increased access to transmission
facilities for wholesale transactions and also establishes information
requirements for the transmission utility. The decision also provides
utilities with the recovery of stranded costs, which are prior-service
costs incurred under the current
page 19
Notes to Consolidated Financial Statements
regulatory framework. In addition to providing recovery of stranded costs
associated with existing wholesale customers, the FERC directed that it
would have primary jurisdiction over the recovery of stranded costs
associated with retail-turned-wholesale customers, such as the formation
of a new municipal electric system. Retail stranded costs resulting from
a state-authorized retail direct-access program are the responsibility of
the states and the FERC would only address recovery of these costs if the
state has no authority to do so. In compliance with the April 1996 FERC
decision, SCE filed a revised open access tariff with the FERC in July
1996. The tariff became effective on an interim basis, subject to refund,
as of its filing date. Several wholesale customers have filed protests
with the FERC on the transmission rate levels, and a ruling from the FERC
setting the rates to be decided at formal hearings is anticipated in early
1997.
Mohave Generating Station
A 1994 CPUC decision stated that SCE was liable for expenditures related
to a 1985 accident at the Mohave Generating Station. In July 1996, the
CPUC approved a settlement agreement between SCE and the ORA which
resulted in a $39 million (including interest) refund to SCE's customers.
The refund, which had been previously reserved, was completed by year-end
1996.
Canadian Gas Contracts
In May 1994, SCE filed its testimony in the non-Qualifying Facilities
phase of the 1994 Energy Cost Adjustment Clause proceeding. In May 1995,
the ORA 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 $13.3 million for excessive costs incurred from November
1993 through March 1994 associated with SCE's Canadian gas purchase and
supply contracts. The report requests that the CPUC defer finding
SCE's Canadian supply and transportation agreements reasonable for the
duration of their terms and that the costs under these contracts be
reviewed on a yearly basis. In October 1996, the ORA issued its report
for the 1995 record period recommending a $37.6 million disallowance for
excessive costs incurred from April 1994 through March 1995. Both
proposed disallowances have been consolidated into one proceeding. SCE
and the ORA have filed several rounds of testimony on this issue.
Hearings began in January 1997 and are expected to conclude in February
1997. A decision is expected in late 1997.
Palo Verde Rate-making Mechanism
On December 23, 1996, the CPUC issued a final decision on SCE's proposal
for a new rate mechanism for its 15.8% share of the three units at Palo
Verde. The decision adopts the Palo Verde All-Party Settlement filed with
the CPUC on November 15, 1996. The settlement was based on a Memorandum
of Understanding signed by all of the active parties to the Palo Verde
proceeding. Under the settlement, SCE has the opportunity to recover
its remaining investment (approximately $1.2 billion) in Palo Verde
beginning January 1, 1997, and ending December 31, 2001, earning a reduced
rate of return on rate base of 7.35% instead of the current 9.49%. Also,
SCE will utilize a balancing account to pass through Palo Verde's
incremental operating costs (considered reasonable as long as they do not
exceed 30% of a baseline forecast and the site's gross annual capacity
factor does not go below 55%) to ratepayers. Beginning January 1, 1998,
this balancing account will become part of the CTC mechanism. If SCE's
actual costs are less than the forecast, the difference will benefit
ratepayers as a credit to the CTC mechanism. The existing nuclear unit
incentive procedure will continue only for purposes of calculating a
reward for performance of any unit above an 80% capacity factor for a fuel
cycle. After 2001, SCE's ratepayers will receive 50% of the benefits
derived from the operation of Palo Verde.
Note 3. Financial Instruments
Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien.
SCE has pledged first and refunding mortgage bonds as security for
borrowed funds obtained from pollution-control bonds issued by government
agencies. SCE uses these proceeds to finance construction of pollution-
control facilities. Bondholders have limited discretion in redeeming
certain pollution-control bonds, and SCE has arranged with securities
dealers to remarket or purchase them if necessary.
page 20
Southern California Edison Company
Long-term debt maturities and sinking-fund requirements for the next
five years are: 1997 - $501 million; 1998 - $447 million; 1999 - $155
million; 2000 - $325 million; and 2001 - $400 million.
Long-term debt consisted of:
In millions December 31, 1996 1995
------------ ------ -------
First and refunding mortgage bonds:
1997 - 2000 (5.45% to 7.5%) $ 1,025 $1,025
2001 - 2005 (5.625% to 6.25%) 450 450
2017 - 2026 (6.9% to 8.875%) 1,250 1,637
Pollution - control bonds:
1999 - 2027 (5.4% to 7.2% and variable) 1,204 1,205
Funds held by trustees (2) (2)
Debentures and notes:
1998 - 2006 (5.6% to 8.25%) 1,195 795
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 112 70
Long-term debt due within one year (501) (1)
Unamortized debt discount - net (54) (64)
------- -------
Total $ 4,779 $5,215
======= =======
Short-Term Debt
SCE has lines of credit it can use at negotiated or bank index rates. At
December 31, 1996, available lines totaled $1.1 billion, with $600 million
for short-term debt and $500 million available for the long-term
refinancing of certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel
inventories, balancing account undercollections and general cash
requirements. Commercial paper outstanding at December 31, 1996, and
1995, was $345 million and $433 million, respectively. Commercial paper
intended to finance nuclear fuel scheduled to be used more than one year
after the balance sheet date is classified as long-term debt in connection
with refinancing terms under five-year term lines of credit with
commercial banks. Weighted-average interest rates were 5.5% and 5.8%, at
December 31, 1996, and 1995, respectively.
Other Financial Instruments
SCE's risk management policy allows the use of derivative financial
instruments to manage financial exposure on its investments and
fluctuations in interest rates, but prohibits the use of these instruments
for speculative or trading purposes.
Interest rate swaps and caps are used to reduce the potential impact of
interest rate fluctuations on floating rate long-term debt. The interest
rate swap agreement requires the parties to pledge collateral according
to bond rating and market interest rate changes. At December 31, 1996,
SCE had pledged $16 million as collateral due to a decline in market
interest rates. SCE is exposed to credit loss in the event of
nonperformance by counterparties to these agreements, but does not expect
the counterparties to fail to meet their obligations.
For both balance sheet dates presented, SCE had the following derivative
financial instruments:
Category Contract Amount/Terms Purpose
Interest rate swap $196 million fix interest rate exposure
due 2008 at 5.585%
Interest rate cap $30 million fix interest rate exposure
expires 1997 at 6% over variable term of
debt due 2027 the debt
page 21
Notes to Consolidated Financial Statements
Fair values of financial instruments were:
December 31, 1996 1995
----- ----
Cost Fair Cost Fair
Instrument In millions Basis Value Basis Value
----- ----- ----- -----
Financial assets:
Decommissioning trusts $1,217 $1,485 $1,069 $1,260
Equity investments 11 68 9 41
Financial liabilities:
DOE decommissioning and decontamination fees 54 45 58 49
Interest rate swap and cap - 16 - 18
Long-term debt 4,779 5,001 5,215 5,487
Preferred stock subject to mandatory redemption 275 286 275 288
Financial assets are carried at their fair value, which is based on quoted
market prices. Financial liabilities are recorded at cost. Financial
liabilities' fair values are based on: termination costs for the interest
rate swap; brokers' quotes for long-term debt, preferred stock and the
cap; and discounted future cash flows for U.S. Department of Energy (DOE)
decommissioning and decontamination fees. Due to their short maturities,
amounts reported for cash equivalents and short-term debt approximate fair
value.
Gross unrealized holding gains on financial assets were:
In millions December 31, 1996 1995
---- ----
Decommissioning trusts:
Municipal bonds $ 79 $ 52
Stocks 138 122
U.S. government issues 39 11
Short-term and other 12 6
----- ----
268 191
Equity investments 57 32
----- ----
Total $325 $223
===== ====
There were no unrealized holding losses on financial assets for the years
presented.
Note 4. Equity
The CPUC regulates SCE's capital structure, limiting the dividends it may
pay Edison International. At December 31, 1996, SCE had the capacity to
pay $112 million in additional dividends and continue to maintain its
authorized capital structure.
Authorized common stock is 560 million shares with no par value.
Authorized shares of preferred and preference stock are: $25 cumulative
preferred--24 million; $100 cumulative preferred--12 million; and
preference--50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund
provisions. When preferred shares are redeemed, the premiums paid are
charged to common equity. There are no preferred stock redemption
requirements for the next five years.
page 22
Southern California Edison Company
Cumulative preferred stock consisted of:
Dollars in millions, except per-share amounts December 31, 1996 1995
------------ ---- ----
December 31, 1996
---------------------------
Shares Redemption
Outstanding Price
----------- ----------
Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000 $25.50 $ 25 $ 25
4.24 1,200,000 25.80 30 30
4.32 1,653,429 28.75 41 41
4.78 1,296,769 25.80 33 33
5.80 2,200,000 25.25 55 55
7.36 4,000,000 25.00 100 100
---- ----
Total $284 $284
==== ====
Subject to mandatory redemption:
$100 par value preferred stock:
6.05% Series 750,000 $100.00 $ 75 $ 75
6.45 1,000,000 100.00 100 100
7.23 1,000,000 100.00 100 100
---- ----
Total $275 $275
==== ====
In 1995, 750,000 shares of Series 7.58% preferred stock were redeemed.
There were no other preferred stock issuances or redemptions for the years
presented.
Note 5. Income Taxes
SCE and its subsidiaries will be included in Edison International's
consolidated federal income tax and combined state franchise tax returns.
Under income tax allocation agreements, each subsidiary calculates its own
tax liability.
Income tax expense includes the current tax liability from operations and
the change in deferred income taxes during the year. Investment tax
credits are amortized over the lives of the related properties.
The components of the net accumulated deferred income tax liability were:
In millions December 31, 1996 1995
------------ ---- ----
Deferred tax assets:
Property-related $ 247 $ 276
Investment tax credits 206 222
Regulatory balancing accounts 205 166
Decommissioning-related 208 73
Other 429 601
---------- -------
Total $ 1,295 $ 1,338
---------- -------
Deferred tax liabilities:
Property-related $ 3,550 $ 3,670
Other 675 514
---------- -------
Total $ 4,225 $ 4,184
---------- -------
Accumulated deferred income taxes -net $ 2,930 $ 2,846
========== =======
Classification of accumulated deferred income taxes:
Included in deferred credits $ 3,170 $ 3,323
Included in current assets 240 477
page 23
Notes to Consolidated Financial Statements
The current and deferred components of income tax expense were:
In millions Year ended December 31, 1996 1995 1994
----------------------- ---- ---- ----
Current:
Federal $386 $560 $ 431
State 129 165 123
---- ---- -----
515 725 554
---- ---- -----
Deferred - federal and state:
Accrued charges (14) 1 (25)
Depreciation (14) 21 46
Investment and energy tax credits - net (24) (25) (22)
Pension reserves 45 (3) (8)
Rate phase-in plan (32) (46) (51)
Regulatory balancing accounts 34 (118) (7)
State tax privilege year 21 (12) (14)
Other (20) (33) (21)
---- ---- -----
(4) (215) (102)
---- ---- -----
Total income tax expense $511 $510 $ 452
==== ==== =====
Classification of income taxes:
Included in operating income $578 $560 $ 508
Included in other income (67) (50) (56)
The composite federal and state statutory income tax rate was 41.045% for
all years presented.
The federal statutory income tax rate is reconciled to the effective tax
rate below:
Year ended December 31, 1996 1995 1994
----------------------- ---- ---- ----
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software (0.8) (0.8) (2.1)
Depreciation and other 4.5 4.3 4.9
Investment and energy tax credits (2.0) (2.2) (2.0)
State tax - net of federal deduction 7.1 6.5 5.7
---- ---- ----
Effective tax rate 43.8% 42.8% 41.5%
==== ==== ====
Note 6. Employee Benefit Plans
Stock Option Plans
Under its Long-Term Incentive Compensation Plan, SCE participates in the
use of 8.2 million shares of parent company common stock reserved for
potential issuance under various stock compensation programs to directors,
officers and senior managers of Edison International and its affiliates.
Under these programs, there are currently outstanding to officers and
senior managers of SCE, options on 2.9 million shares of Edison
International common stock.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market
value of the underlying stock at the date of grant. Edison International
stock options include a dividend equivalent feature. Generally, for
options issued before 1994, amounts equal to dividends accrue on the
options at the same time and at the same rate as would be payable on the
number of shares of Edison International common stock covered by the
options. The amounts accumulate without interest. The optionee has no
right to payment of these dividend equivalents until the underlying stock
options are exercised. For Edison International stock options issued
subsequent to 1993, dividend equivalents are subject to reduction unless
certain shareholder return performance criteria are met.
page 24
Southern California Edison Company
Edison International stock options have a 10-year term with one-third of
the total award vesting after each of the first three years of the award
term. The options are not transferable, except by will or domestic
relations order. If an optionee retires, dies or is permanently and
totally disabled during the three-year vesting period, the unvested
options will vest and be exercisable to the extent of 1/36 of the grant
for each full month of service during the vesting period. Unvested
options of any person who has served in the past on the Edison
International or SCE Management Committee will vest and be exercisable
upon the member's retirement, death or permanent and total disability.
Upon retirement, death or permanent and total disability, the vested
options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by
retirement, death or permanent and total disability, options which had
vested as of the prior anniversary date of the grant are forfeited unless
exercised within 180 days of the date of termination. All unvested
options are forfeited on the date of termination.
Compensation expense recorded under the stock-compensation program was
$8 million, $4 million and $(2) million for 1996, 1995 and 1994,
respectively. A decline during 1994 in the market value of the underlying
shares optioned resulted in the recapture of previously recognized
expense.
Stock-based compensation expense under the fair-value method of accounting
would have resulted in pro forma net income of approximately $653 million
in 1996 and $677 million in 1995.
The weighted-average fair value of options granted during 1996 and 1995,
was $6.27 per share option and $6.92 per share option, respectively. The
weighted-average remaining life of options outstanding, as of December 31,
1996, and 1995, was 7 years and 8 years, respectively.
The fair value for each option granted during 1996 and 1995, reflecting
the basis for the above pro forma disclosures, was determined on the date
of grant using the Black-Scholes option-pricing model. The following
assumptions were used in determining fair value through the model:
1996 1995
---- -----
Expected life 7 years 8 years
Risk-free interest rate 5.5% 7.9%
Expected volatility 17% 17%
The recognition of dividend equivalents results in no dividends assumed
for purposes of fair-value determination. The application of fair-value
accounting in arriving at the pro forma disclosures above is not an
indication of future income statement effects. The pro forma disclosures
do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers
employees meeting minimum service requirements. Benefits are based on
years of accredited service and average base pay. SCE funds the plan on
a level-premium actuarial method. These funds are accumulated in an
independent trust. Annual contributions meet minimum legal funding
requirements and do not exceed the maximum amounts deductible for income
taxes. Prior service costs from pension plan amendments are funded over
30 years. Plan assets are primarily common stocks, corporate and
government bonds, and short-term investments. In 1996, SCE recorded
pension gains from a special voluntary early retirement program.
page 25>
Notes to Consolidated Financial Statements
The plan's funded status was:
In millions December 31, 1996 1995
- ----------- ------------ ---- ----
Actuarial present value of benefit obligations:
Vested benefits $1,670 $1,696
Nonvested benefits 71 210
------ ------
Accumulated benefit obligation 1,741 1,906
Value of projected future compensation levels 261 479
------ ------
Projected benefit obligation $2,002 $2,385
====== ======
Fair value of plan assets $2,165 $2,620
====== ======
Projected benefit obligation less than plan assets $ (163) $ (235)
Unrecognized net gain 300 326
Unrecognized prior service cost (199) (6)
Unrecognized net obligation (17-year amortization) (43) (49)
------ ------
Pension liability (asset) $ (105) $ 36
====== ======
Discount rate 7.75% 7.25%
Rate of increase in future compensation 5.0% 5.0%
Expected long-term rate of return on assets 8.0% 8.0%
SCE recognizes pension expense calculated under the actuarial method used
for ratemaking.
The components of pension expense were:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Service cost for benefits earned $ 49 $ 57 $ 67
Interest cost on projected benefit obligation 178 156 148
Actual return on plan assets (343) (454) (28)
Net amortization and deferral 145 268 (140)
----- ----- -----
Pension expense under accounting standards 29 27 47
Special termination benefits - 3 15
Regulatory adjustment - deferred 22 22 1
----- ----- -----
Net pension expense recognized 51 52 63
Settlement gain (121) - -
----- -----
Total expense (gain) $ (70) $ 52 $ 63
===== ===== ======
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service
(or those eligible under the 1996 special voluntary early retirement
program), are eligible for postretirement health and dental care, life
insurance and other benefits. Health and dental care benefits are subject
to deductibles, copayment provisions and other limitations.
SCE is amortizing its obligation related to prior service over 20 years.
SCE funds these benefits (by contributions to independent trusts) up to
tax-deductible limits, in accordance with rate-making practices. In 1996,
SCE recorded special termination expenses due to a special voluntary early
retirement program. Any difference between recognized expense and amounts
authorized for rate recovery is not expected to be material (except for
the impact of the early retirement program) and will be charged to
earnings.
Trust assets are primarily common stocks, corporate and government bonds,
and short-term investments.
page 26
Southern California Edison Company
The funded status of these benefits is reconciled to the recorded
liability below:
In millions December 31, 1996 1995
- ----------- ------------ ---- ----
Actuarial present value of benefit obligation:
Retirees $ 928 $ 402
Employees eligible to retire 35 103
Other employees 386 556
------ ------
Accumulated benefit obligation $1,349 $1,061
====== ======
Fair value of plan assets $ 617 $ 400
====== ======
Plan assets less than accumulated benefit obligation $ 732 $ 661
Unrecognized transition obligation (430) (457)
Unrecognized net gain (loss) (231) (203)
------ ------
Recorded liability $ 71 $ 1
====== ======
Discount rate 7.75% 7.5%
Expected long-term rate of return on assets 8.5% 8.5%
The components of postretirement benefits other than pensions expense
were:
In millions Year ended December 31, 1996 1995 1994
- ----------- ----------------------- ---- ---- ----
Service cost for benefits earned $ 31 $ 35 $ 29
Interest cost on benefit obligation 90 77 72
Actual return on plan assets (43) (28) (20)
Amortization of loss 6 1 -
Amortization of transition obligation 27 27 36
------ ------ ------
Net expense 111 112 117
Amortization of prior funding - - 2
Special termination expense 72 - -
------ ------ ------
Total expense $ 183 $ 112 $ 119
====== ====== ======
The assumed rate of future increases in the per-capita cost of health care
benefits is 8.25% for 1997, gradually decreasing to 5% for 2004 and
beyond. Increasing the health care cost trend rate by one percentage
point would increase the accumulated obligation as of December 31, 1996,
by $206 million annual aggregate service and interest costs by $24
million.
Employee Savings Plan
SCE has a 401(k) defined contribution savings plan designed to supplement
employees' retirement income. The plan received employer contributions
of $24 million in 1996, $19 million in 1995 and $21 million in 1994.
page 27
Notes to Consolidated Financial Statements
Note 7. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems
for which each participant provides its own financing. SCE's share of
expenses for each project is included in the consolidated statements of
income.
The investment in each project, as included in the consolidated balance
sheet as of December 31, 1996, was:
Plant in Accumulated Under Ownership
In millions Service Depreciation Construction Interest
-------- ------------ ------------ ---------
Transmission systems:
Eldorado $ 29 $ 8 $ 2 60%
Pacific Intertie 227 72 12 50
Generating stations:
Four Corners Units 4 and 5 (coal) 458 236 2 48
Mohave (coal) 300 142 8 56
Palo Verde (nuclear) 1,596 425 6 16
San Onofre (nuclear) 4,186 1,836 28 75
------ ------ ---- ----
Total $6,796 $2,719 $58
======= ====== ====
Note 8. Leases
SCE has operating leases, primarily for vehicles, with varying terms,
provisions and expiration dates.
Estimated remaining commitments for noncancelable leases at December 31,
1996, were:
Year ended December 31, In millions
- ---------------------- -----------
1997 $18
1998 15
1999 11
2000 9
2001 5
Thereafter 7
----
Total $65
====
Note 9. Commitments
Nuclear 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 Nuclear Regulatory Commission. Decommissioning is estimated to
cost $2.0 billion in current-year dollars, based on site-specific studies
performed in 1993 for San Onofre and 1992 for Palo Verde. Changes in the
estimated costs, timing of decommissioning, or the assumptions underlying
these estimates could cause material revisions to the estimated total cost
to decommission in the near term. Decommissioning is scheduled to begin
in 2013 at San Onofre and 2024 at Palo Verde. San Onofre Unit 1, which
shut down in 1992, is expected to be secured until decommissioning begins
at the other San Onofre units.
Decommissioning costs, which are recovered through customer rates, are
recorded as a component of depreciation expense. Decommissioning expense
was $148 million in 1996, $151 million in 1995 and $122 million in 1994.
The accumulated provision for decommissioning was $949 million at December
31, 1996,
page 28
Southern California Edison Company
and $823 million at December 31, 1995. The estimated costs to
decommission San Onofre Unit 1 ($263 million) are recorded as a
liability.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Trust investments include:
December 31,
Maturity -------------------
In millions Dates 1996 1995
- ----------- --------------- -------- -------
Municipal bonds 1999-2021 $ 400 $348
Stocks - 549 390
U.S. government issues 1998-2024 212 145
Short-term and other 1996-2024 56 186
-------- -------
Trust fund balance (at cost) $1,217 $1,069
======== =======
Trust fund earnings (based on specific identification) increase the trust
fund balance and the accumulated provision for decommissioning. Net
earnings were $49 million in 1996, $51 million in 1995 and $26 million in
1994. Proceeds from the sales of securities (which are reinvested) were
$1.0 billion in both 1996 and 1995, and $1.1 billion in 1994.
Approximately 89% of the trust fund contributions were tax-deductible.
The Financial Accounting Standards Board has issued an exposure draft
related to accounting practices for removal costs, including
decommissioning of nuclear power plants. The exposure draft would require
SCE to report its estimated decommissioning costs as a liability, rather
than recognizing these costs over the term of each facility's operating
license (current industry practice). SCE does not believe that the
changes proposed in the exposure draft would have an adverse effect on its
results of operations even after deregulation due to its current and
expected future ability to recover these costs through customer rates.
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is
made available for purchase.
SCE has power-purchase contracts with certain qualifying facilities
(cogenerators and small power producers) and other utilities. The
qualifying facility contracts provide for capacity payments if a facility
meets certain performance obligations and energy payments based on actual
power supplied to SCE. There are no requirements to make debt-service
payments.
SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another
utility. Minimum payments are based, in part, on the debt-service
requirements of the provider, whether or not the plant or transmission
line is operable. The purchased-power contract is not expected to provide
more than 5% of current or estimated future operating capacity. SCE's
minimum commitment under both contracts is approximately $205 million
through 2017.
Certain commitments for the years 1997 through 2001 are estimated below:
In millions 1997 1998 1999 2000 2001
---- ---- ---- ---- ----
Projected construction expenditures $ 802 $ 636 $ 664 $ 647 $ 650
Fuel supply contracts 269 231 221 240 234
Purchased-power capacity payments 696 699 701 702 695
Unconditional purchase obligations 9 10 10 10 10
page 29
Notes to Consolidated Financial Statements
Note 10. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in
legal, tax and regulatory proceedings before various courts and
governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these proceedings will not
materially affect its results of operations or liquidity.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which
require it to incur substantial costs to operate existing facilities,
construct and operate new facilities, and mitigate or remove the effect
of past operations on the environment.
SCE records its environmental liabilities when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup
costs can be estimated. SCE reviews its sites and measures the liability
quarterly, by assessing a range of reasonably likely costs for each
identified site using currently available information, including existing
technology, presently enacted laws and regulations, experience gained at
similar sites, and the probable level of involvement and financial
condition of other potentially responsible parties. These estimates
include costs for site investigations, remediation, operations and
maintenance, monitoring and site closure. Unless there is a probable
amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities at undiscounted amounts).
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 55
identified sites was $114 million at December 31, 1996. 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 $211 million. 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 35 of its
sites, representing $101 million of its recorded liability, through an
incentive mechanism. SCE may request to include additional sites. Under
this mechanism, SCE will recover 90% of cleanup costs through customer
rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties. SCE
has successfully settled insurance claims with a number of its carriers.
Costs incurred at the remaining 20 sites are expected to be recovered
through customer rates. SCE has recorded a regulatory asset of $104
million for its estimated minimum environmental-cleanup costs expected to
be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible
for contributing to any costs incurred for remediating these sites. Thus,
no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30
years. Remediation costs in each of the next several years are expected
to range from $4 million to $8 million. Recorded costs for 1996 were $7
million.
Based on currently available information, SCE believes it is unlikely that
it will incur amounts in excess of the upper limit of the estimated range
and, based upon the CPUC's regulatory treatment of environmental-cleanup
costs, SCE believes that costs ultimately recorded will not have a
material adverse effect on its results of operations or financial
position. There can be no assurance, however, that future developments,
page 30
Southern California Edison Company
including additional information about existing sites or the
identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $8.9
billion. SCE and other owners of San Onofre and Palo Verde have purchased
the maximum private primary insurance available ($200 million). The
balance is covered by the industry's retrospective rating plan that uses
deferred premium charges to every reactor licensee if a nuclear incident
at any licensed reactor in the U.S. results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations
require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary
level, effective June 1994. The maximum deferred premium for each nuclear
incident is $79 million per reactor, but not more than $10 million per
reactor may be charged in any one year for each incident. Based on its
ownership interests, SCE could be required to pay a maximum of $158
million per nuclear incident. However, it would have to pay no more than
$20 million per incident in any one year. Such amounts include a 5%
surcharge if additional funds are needed to satisfy public liability
claims and are subject to adjustment for inflation. If the public
liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination
liability and property damage coverage exceeding the primary $500
million has also been purchased in amounts greater than federal
requirements. Additional insurance covers part of replacement power
expenses during an accident-related nuclear unit outage. These policies
are issued primarily by mutual insurance companies owned by utilities with
nuclear facilities. If losses at any nuclear facility covered by the
arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up
to $34 million per year. Insurance premiums are charged to operating
expense.
Quarterly Financial Data
1996 1995
In millions Total Fourth Third Second First Total Fourth Third Second First
-----------------------------------------------------------------------------------------------
Operating revenue $7,583 $1,866 $2,346 $1,611 $1,760 $7,873 $1,903 $2,510 $1,738 $1,722
Operating income 1,133 231 382 257 263 1,149 246 369 261 273
Net income 655 121 256 131 147 680 130 251 150 149
Earnings available for
common stock 621 113 247 123 138 643 121 243 140 139
Common dividends declared 735 196 178 180 181 546 136 136 137 137
page 31
Responsibility for Financial Reporting
The management of Southern California Edison Company (SCE) is responsible
for the integrity and objectivity of the accompanying financial
statements. The statements have been prepared in accordance with
generally accepted accounting principles applied on a consistent basis and
are based, in part, on management estimates and judgment.
SCE maintains systems of internal control to provide reasonable, but not
absolute, assurance that assets are safeguarded, transactions are executed
in accordance with management's authorization and the accounting records
may be relied upon for the preparation of the financial statements. There
are limits inherent in all systems of internal control, the design of
which involves management's judgment and the recognition that the costs
of such systems should not exceed the benefits to be derived. SCE
believes its systems of internal control achieve this appropriate balance.
These systems are augmented by internal audit programs through which the
adequacy and effectiveness of internal controls and policies and
procedures are monitored, evaluated and reported to management. Actions
are taken to correct deficiencies as they are identified.
SCE's independent public accountants, Arthur Andersen LLP, are engaged to
audit the financial statements in accordance with generally accepted
auditing standards and to express an informed opinion on the fairness, in
all material respects, of SCE's reported results of operations, cash flows
and financial position.
As a further measure to assure the ongoing objectivity of financial
information, the audit committee of the board of directors, which is
composed of outside directors, meets periodically, both jointly and
separately, with management, the independent public accountants and
internal auditors, who have unrestricted access to the committee. The
committee recommends annually to the board of directors the appointment
of a firm of independent public accountants to conduct audits of its
financial statements; considers the independence of such firm and the
overall adequacy of the audit scope and SCE's systems of internal control;
reviews financial reporting issues; and is advised of management's actions
regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing
personnel to assure that its operations are conducted in conformity with
applicable laws and is committed to maintaining the highest standards of
personal and corporate conduct. Management maintains programs to
encourage and assess compliance with these standards.
Richard K. Bushey John E. Bryson
Richard K. Bushey John E. Bryson
Vice President Chairman of the Board
and Controller and Chief Executive Officer
January 31, 1997
page 32
Southern California Edison Company
Report of Independent Public Accountants
To the Shareholders and the Board of Directors,
Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE, a California corporation) and its
subsidiaries as of December 31, 1996, and 1995, and the related
consolidated statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of SCE's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of SCE and its
subsidiaries as of December 31, 1996, and 1995, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
January 31, 1997 (except with respect to the
"Subsequent Event" discussed under "Electric
Utility Industry Restructuring" in Note 2, as
to which the date is February 21, 1997).
page 33
Board of Directors Southern California Edison Company
John E. Bryson Carl F. Huntsinger E.L. Shannon, Jr.
Chairman of the Board and General Partner, Retired Chairman of the Board
CEO, Edison International DAE Limited Partnership Ltd., Santa Fe International Corporation
and SCE Ojai, California Alhambra, California
Howard P. Allen Charles D. Miller Robert H. Smith
Chairman of the Executive Chairman of the Board Managing Director,
Committee, Edison and CEO, Avery Dennison Smith and Crowley Incorporated,
International and SCE Corporation, Pasadena, California
Pasadena, California
Winston H. Chen
Chairman of the Paramitas Luis G. Nogales Thomas C. Sutton
Foundation and Chairman of President, Chairman of the Board and CEO,
Paramitas Investment Corporation, Nogales Partners, Pacific Mutual Life Insurance
Santa Clara, California Los Angeles, California Company, Lots Angeles, California
Stephen E. Frank Ronald L. Olson Daniel M. Tellep
President and Chief Operating Senior Partner of Munger, Retired Chairman of the Board,
Officer, SCE Tolles and Olson, Lockheed Martin Corporation,
Los Angeles, California Bethesda, Maryland
Camilla C. Frost
Trustee, Chandler Trusts and J.J. Pinola James D. Watkins
Director and Secretary-Treasurer, Retired Chairman of the President, Joint Oceanographic
Chandis Securities Company, Board and CEO, Institutions, Inc. and President,
Los Angeles, California First Interstate Bankcorp. Consortium for Oceanographic
Los Angeles, California Research and Education,
Joan C. Hanley Washington, D.C.
General Partner, James M. Rosser
Miramonte Vineyards, President, Edward Zapanta, M.D.
Rancho Palos Verdes, California California State University Physician and Neurosurgeon,
Los Angeles, California South Pasadena, California
- ------------------------------------------------------------------------------------------------------------
Executive Officers
John E. Bryson Pamela A. Bass R.W. Krieger
Chairman of the Board and CEO Vice President, Vice President,
Customer Solutions Business Unit Nuclear Generation
Stephen E. Frank
President and Chief Richard K. Bushey J. Michael Mendez
Operating Officer Vice President and Controller Vice President,
Labor Relations
Bryant C. Danner Theodore F. Craver, Jr.
Executive Vice President and Vice President and Treasurer Dwight E. Nunn
General Counsel Vice President,
John R. Fielder Nuclear Engineering and
Alan J. Fohrer Vice President, Technical Services
Executive Vice President and Chief Regulatory Policy and Affairs
Financial Officer Frank J. Quevedo
Bruce C. Foster Vice President,
Harold B. Ray Vice President, Equal Opportunity
Executive Vice President, San Francisco Regulatory Affairs
Generation Business Unit Richard M. Rosenblum
Lillian R. Gorman Vice President,
Vikram S. Budhraja Vice President, Distribution Business Unit
Senior Vice President, Human Resources
Power Grid Business Unit Beverly P. Ryder
Lawrence D. Hamlin Corporate Secretary and
Robert G. Foster Vice President, Special Assistant to the
Senior Vice President, Power Production Chairman/CEO
Public Affairs
Thomas J. Higgins
Emiko Banfield Vice President,
Vice President, Corporate Communications
Shared Services
page 34
Shareholder Information
- ----------------------------------------------------------------------------
Annual Meeting of Shareholders
Thursday, April 17, 1997
10:00 a.m.
The Industry Hills Sheraton Resort and Conference Center
One Industry Hills Parkway
City of Industry, California
- ----------------------------------------------------------------------------
Stock Listing and Trading Information
SCE Preferred Stocks
The American and Pacific stock exchanges use the ticker symbol SCE.
Previous day's closing prices, when traded, are listed in the daily
newspapers in the American Stock Exchange table under the symbol SoCalEd.
The 6.05%, 6.45% and 7.23% series are not listed.
Where to Buy and Sell Stock
The listed preferred stocks may be purchased through any brokerage firm.
Firms handling unlisted series can be located through your broker.
- ----------------------------------------------------------------------------
Transfer Agent and Registrar
Southern California Edison Company maintains shareholder records and is
transfer agent and registrar for SCE preferred stock. Shareholders may
call Shareholder Services, (800) 347-8625, between 8:00 a.m. and 4:00 p.m.
(Pacific time) every business day, regarding:
o stock transfer and name-change requirements;
o address changes, including dividend addresses;
o electronic deposit of dividends;
o taxpayer identification number submission or changes;
o duplicate 1099 forms and W-9 forms;
o notices of and replacement of lost or destroyed stock certificates and
o dividend checks; and
o requests to eliminate multiple annual report mailings.
The address of Shareholder Services is:
P.O. Box 400, Rosemead, California 91770-0400
FAX: (818) 302-4815
PAGE
Southern California Edison
2244 Walnut Grove Avenue
Rosemead, California 91770
(818) 302-1212