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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 --