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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, 1997
--------------------------------------------
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 (626) 302-1212
Rosemead, California 91770 (Registrant's telephone number,
(Address of principal (Zip Code) Including area code)
executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Capital Stock
Cumulative Preferred $100 Cumulative Preferred American and
4.08% Series 4.78% Series 6.05% Series Pacific
4.24% Series 5.80% Series 6.45% Series
4.32% 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 23, 1998 there were 434,888,104 shares of Common Stock
outstanding, all of which are held by the registrant's parent holding
company. The aggregate market value of registrant's voting stock held by
non-affiliates was approximately $426,452,116 on or about March 23, 1998
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 $151,452,116; $100 CUMULATIVE
PREFERRED STOCK $275,000,000.
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, 1997. . . . . . . . . . . . . . . . Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 1998 Annual Meeting
of Shareholders. . . . . . . . . . . . . . . . . Part III
PAGE
TABLE OF CONTENTS
Item Page
- ---- ----
Part I
1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Competitive Environment. . . . . . . . . . . . . . . . . . 1
Regulation . . . . . . . . . . . . . . . . . . . . . . . . 7
Rate Matters . . . . . . . . . . . . . . . . . . . . . . . 9
Fuel Supply and Purchased Power Costs . . . . . . . . . . . 13
Environmental Matters . . . . . . . . . . . . . . . . . . . 14
Year 2000 Issue . . . . . . . . . . . . . . . . . . . . . . 17
2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Existing Generating Facilities . . . . . . . . . . . . . . 17
Construction Program and Capital Expenditures . . . . . . . 19
Nuclear Power Matters . . . . . . . . . . . . . . . . . . . 19
3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 22
Qualifying Facilities Litigation . . . . . . . . . . . . . 22
Wind Generators' Litigation . . . . . . . . . . . . . . . . 23
Geothermal Generators' Litigation . . . . . . . . . . . . . 24
Electric and Magnetic Fields (EMF) Litigation . . . . . . . 25
San Onofre Personal Injury Litigation . . . . . . . . . . . 26
Oil Pipeline Litigation . . . . . . . . . . . . . . . . . . 28
False Claims Act Litigation . . . . . . . . . . . . . . . . 28
Mohave Generating Station Environmental Litigation . . . . 28
4. Submission of Matters to a Vote of Security Holders . . . . . . 29
Executive Officers of the Registrant . . . . . . . . . . . . . . 29
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . 31
6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . 31
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . . . . 31
8. Financial Statements and Supplementary Data . . . . . . . . . . 31
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . . . . . . . 31
Part III
10. Directors and Executive Officers of the Registrant . . . . . . . 31
11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . 31
12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . . . . . . . . 32
13. Certain Relationships and Related Transactions . . . . . . . . . 32
Part IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . 32
Report of Independent Public Accountants on
Supplemental Schedules . . . . . . . . . . . . . . . . . . 33
Supplemental Schedules . . . . . . . . . . . . . . . . . . 34
Signatures . . . . . . . . . . . . . . . . . . . . . . . . 37
Exhibit Index. . . . . . . . . . . . . . . . . . . . . . . 38
PAGE
PART I
In this form 10-K, Southern California Edison Company (SCE) uses the words
estimates, expects, anticipates, believes, and other similar expressions
that are intended to identify forward-looking information that involves
risks and uncertainties. Actual results or outcomes could differ
materially as a result of such important factors as further actions by
state and federal regulatory bodies setting rates and implementing the
restructuring of the electric utility industry; the effects of new laws
and regulations relating to restructuring and other matters; the effects
of increased competition in the electric utility business, including the
beginning of direct customer access to retail energy suppliers and the
unbundling of revenue cycle services such as metering and billing; changes
in prices of electricity and fuel costs; changes in market interest rates;
new or increased environmental liabilities; and other unforeseen events.
Item 1. Business
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 12,642 full-time employees at year-end 1997. During
1997, 38% of SCE's total operating revenue was derived from residential
customers, 38% 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 deliver 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.
California Electric Utility Restructuring
Restructuring Decision - The California Public Utilities Commission's
(CPUC) December 1995 decision on restructuring California's electric
utility industry started the transition to a new market structure, which
is expected to provide competition and customer choice and is scheduled to
begin March 31, 1998. Key elements of the CPUC's restructuring decision
included: creation of an independent power exchange (PX) and independent
system operator (ISO); availability of direct customer access and customer
choice; performance-based ratemaking (PBR) for those utility services not
subject to competition; voluntary divestiture of at least 50% of
utilities' gas-fueled generation, and implementation of the competition
transition charge (CTC).
Restructuring Legislation - In September 1996, the State of California
enacted legislation to provide a transition to a competitive market
structure. The legislation substantially adopted the CPUC December 1995
restructuring decision by addressing stranded-cost recovery for utilities
and 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 included provisions to
finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which would
allow SCE to reduce rates by at least 10% to these customers, beginning
January 1, 1998. The financing would occur with securities issued by the
page 1
California Infrastructure and Economic Development Bank (Bank), or an
entity approved by the Bank. The legislation included 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 during the 1998-2001
transition period. In addition, the legislation mandated the
implementation of the CTC that provides utilities the opportunity to
recover costs made uneconomic by electric utility restructuring. Finally,
the legislation contained provisions for the recovery (through 2006) of
reasonable employee-related transition costs, incurred and projected, for
retraining, severance, early retirement, outplacement and related
expenses.
Rate Reduction Notes - In May 1997, SCE filed an application with the CPUC
requesting approval of the issuance of an aggregate amount of up to $3
billion of rate reduction notes in one or more series or classes and a 10%
rate reduction for the period from January 1, 1998, through March 31,
2002. At the same time, SCE filed an application with the Bank for
approval to issue the notes. Residential and small commercial customers
will repay the notes over the expected 10-year term through non-bypassable
charges based on electricity consumption. In December 1997, after
receiving approval from both the CPUC and the Bank, a limited liability
company created by SCE issued approximately $2.5 billion
of these notes.
Rate-setting - In December 1996, SCE filed a more comprehensive plan
(elaborating on its July 1996 filing related to the conceptual aspects of
separating costs as requested by CPUC and Federal Energy Regulatory
Commission (FERC) directives) for the functional unbundling of its rates
for electric service, beginning 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 into separate charges for energy, transmission, distribution, the
CTC, public benefit programs and nuclear decommissioning. The
transmission component of this rate unbundling process was addressed at
the FERC through a March 1997 filing. In December 1997, the FERC approved
these rates, subject to refund, to be effective on the date the ISO begins
operation. (See "Transmission Owners Tariff and Wholesale Distribution
Access Tariff" below for further discussion.) CPUC hearings on SCE's rate
unbundling (also known as rate-setting) plan were concluded in April 1997.
In August 1997, the CPUC issued a decision which adopted the methodology
for determining CTC residually (see "CTC" discussion) and adopted SCE's
revenue requirement components for public benefit programs and nuclear
decommissioning. The decision also adjusted SCE's proposed distribution
revenue requirement by reallocating $76 million of it annually to other
functions such as generation and transmission. Under the decision, SCE
will be able to recover most of the reallocated amount through market
revenue, other rate-making mechanisms after petitioning the CPUC to modify
its prior decisions, or another review process later in its divestiture
proceeding.
PX and ISO - In April 1996, SCE, Pacific Gas and Electric Company (PG&E)
and San Diego Gas & Electric Company (SDG&E) filed a proposal with the
FERC regarding the creation of the PX and the ISO. In November 1996, the
FERC conditionally accepted the proposal and directed the three utilities,
the ISO, and the PX to file more specific information. The filing was
made in March 1997, and included SCE's proposed transmission revenue
requirement. On October 29, 1997, the FERC gave conditional, interim
authorization for operation of the PX and ISO, which are new independent
non-profit California corporations, to begin on January 1, 1998. Prior to
the start of the ISO and PX, the chief executive officers of the PX, ISO
and the three utilities are required to certify that all the conditions
were in place to ensure reliable electric power operations. In addition,
the FERC stated it would closely monitor the PX and ISO, require further
page 2
studies and make modifications, where necessary. A comprehensive review
will be performed by the FERC after three years of operation of the PX and
ISO. On December 22, 1997, the PX and ISO governing boards announced a
delay in the planned start-up of the PX and ISO due to insufficient
testing of operational, settlement and billing systems. The PX and ISO
are now expected to begin operation by March 31, 1998.
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 are backed by utility guarantees;
SCE's share was 45%, or $113 million. In August 1996, the CPUC issued an
interim order establishing the restructuring trust and the funding level
of $250 million, which has been used to build the hardware and software
systems for the ISO and PX. The ISO and PX will repay the trust's loans
and recover funds from future ISO and PX customers. In November 1997,
the CPUC approved a petition jointly filed by the three utilities which
requested an increase in the loan guarantees from $250 million to $300
million; SCE's share of this new total is $135 million. In December 1997,
the CPUC approved a remaining issue with respect to the petition which
requested that the one-time restructuring implementation charge, to be
paid to the PX by the utilities, be deemed a non-bypassable charge to be
recovered from all retail customers. The amount of the PX charge is
approximately $101 million, plus interest; SCE's share is 45%, or $45.5
million.
Direct Customer Access - In May 1997, the CPUC issued a decision
describing how all California investor-owned-utility customers will be
able to choose who will provide them with electric generation service
beginning January 1, 1998. On December 30, 1997, the CPUC issued a
decision delaying direct access until March 31, 1998, due to operational
delays in the startup of the PX and ISO. When the PX and ISO become
operational, customers will be able to choose to remain utility customers
with bundled electric service from SCE (which will purchase its power
through the PX), or choose direct access, which means the customer can
contract directly with either independent power producers or retail
electric service providers such as power brokers, marketers and
aggregators. Additionally, all investor-owned utility customers must pay
the CTC whether or not they choose to buy power through SCE. Electric
utilities will continue to provide the core distribution service of
delivering energy through their distribution systems regardless of a
customer's choice of electricity supplier. The CPUC will continue to
regulate the prices and service obligations related to distribution
services. If the new competitive market cannot accommodate the volume of
direct access transactions, the CPUC could implement a contingency plan.
However, the CPUC indicated that it believes it is likely that interest in
and migration to direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997,
introduces customer choice to metering, billing and related services
(revenue cycle services) that are now provided by California's investor-
owned utilities. Under this revenue cycle services unbundling decision,
beginning in January 1998, direct access customers may choose to have
either SCE or their electric generation service provider render
consolidated (energy and distribution) bills, or they may choose to have
separate billings from each service provider. However, not all electric
generation service providers will necessarily offer each billing option.
In addition, beginning in January 1998, customers with maximum demand
above 20 kW (primarily industrial and large commercial) can choose SCE or
any other supplier to provide their metering service. All other customers
will have this option beginning in January 1999. Since direct access was
delayed, options described in the CPUC decision as becoming available
January 1, 1998, will not be available until the PX and ISO become
operational. In determining whether any credit should be provided by the
utility to firms providing customers with revenue cycle services, and
the amount of any such credit, the CPUC has indicated that it is
page 3
appropriate to net the cost incurred by the utility and the cost avoided
by the utility as a result of such services being provided by the other
firm rather than by the utility. The unbundling of revenue cycle services
will expose SCE to the possible loss of revenue, higher stranded costs and
a reduction in revenue security.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its
revenue (excluding fuel). The filing was subsequently divided between
transmission and distribution (T&D) and power generation.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism
for SCE which began on January 1, 1997. According to the CPUC, beginning
in 1998 (coincident with the initiation of the competitive market), the
transmission portion is to be separated from non-generation PBR and
subject to ratemaking under the rules of the FERC. The distribution-only
PBR will extend through December 2001. Key elements of the non-generation
PBR include: T&D rates indexed for inflation based on the Consumer Price
Index less a productivity factor; elimination of the kilowatt-hour sales
adjustment; adjustments for cost changes that are not within SCE's
control; a cost of capital trigger mechanism based on changes in a bond
index; standards for service reliability and safety; and a net revenue-
sharing mechanism that determines how customers and shareholders will
share gains and losses from T&D operations.
With the CPUC's 1995 restructuring decision and the passage of
restructuring legislation in 1996, the majority of power generation
ratemaking (primarily fossil-fueled and nuclear) was assigned to other
mechanisms. In April 1997, a CPUC interim order determined that the
proposed structure of the fossil-fueled plants' must-run contracts were
under the FERC's jurisdiction. On October 31, 1997, SCE filed must-run
tariff schedules with the FERC covering its six ISO-designated must-run
plants. In the meantime, SCE is pursuing the divestiture of these plants
(see "Divestiture" discussion) and might not ever itself provide service
under these FERC tariff schedules.
In December 1997, the CPUC adopted a PBR-type rate-making mechanism for
SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue
requirement in 1998 and establishes a formula for extending it through the
duration of the electric industry restructuring transition period, or
until market valuation of the hydroelectric facilities, whichever occurs
first. The mechanism provides that power sales revenue from hydroelectric
facilities in excess of the hydroelectric revenue requirement be credited
against the costs to transition to a competitive market (see "CTC"
discussion).
The CPUC has announced its intention to unbundle SCE's cost of capital by
major utility function and has directed SCE to file an application by May
8, 1998. This proceeding could result in a change in late 1998 or early
1999 to the cost of capital included within the PBR cost of capital
trigger mechanism.
Divestiture - In November 1996, SCE filed an application with the CPUC to
voluntarily divest, by auction, all 12 of its oil- and gas-fueled
generating plants. This application built upon SCE's March 1996 plan
which outlined how SCE proposed to divest 50% of these assets. SCE would
continue to operate and maintain the divested plants for at least two
years following their sale, as mandated by the restructuring legislation
enacted in September 1996. In addition, SCE would offer workforce
transition programs to those employees who may be impacted by divestiture-
related job reductions. In September 1997, the CPUC approved SCE's
proposal to auction the 12 plants.
On December 1, 1997, SCE filed a compliance filing with the CPUC stating
that it agreed to sell ten plants. On December 16, 1997, the CPUC
approved the sale of the ten plants. On February 6, 1998, SCE filed a
page 4
compliance filing with the CPUC for the sale of an eleventh plant. CPUC
approval of the sale is expected before March 31, 1998. The total sales
price of the eleven plants is $1.1 billion or 2.16 times their combined
book value of $531 million. Net proceeds of the sales will be used to
reduce stranded costs, which otherwise were expected to be collected
through the CTC mechanism. The transfer of ownership of the eleven plants
is expected to occur concurrently with the start of the new competitive
market, which the PX and ISO expect to occur on March 31, 1998. The
process of selling the single remaining plant is still underway.
CTC - Recovery of costs to transition to a competitive market is being
implemented through a non-bypassable CTC. This charge applies to all
customers who were using or began using utility services on or after the
CPUC's 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 energy from PX, 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, forecasts of future costs and assumed market
prices. However, changes in the assumed market prices could materially
affect these estimates. The potential transition costs are composed of:
$7.5 billion from SCE's qualifying facility (QF) contracts, which are the
direct result of prior legislative and regulatory mandates; and $5.6
billion to $6.3 billion from costs pertaining to certain generating plants
(successful completion of the sale of SCE's gas-fired generating plants
would reduce this estimate of transition costs for SCE-owned generation to
less than $5 billion) and regulatory commitments consisting of costs
incurred (whose recovery has been deferred by the CPUC) to provide service
to customers. Such commitments include the recovery of income tax
benefits previously flowed through to customers, postretirement benefit
transition costs, accelerated recovery of San Onofre Nuclear Generating
Station Units 2 and 3 and the Palo Verde Nuclear Generating Station units,
and certain other costs. In February 1997, SCE filed an update to the CTC
filing to reflect approval by the CPUC of settlements regarding ratemaking
for SCE's share of Palo Verde and the buyout of a power purchase
agreement, as well as other minor data updates. No substantive changes in
the total CTC estimates were included. This issue has been separated into
two phases; Phase 1 addresses the rate-making issues and Phase 2 the
quantification issues.
A decision on Phase 1 was issued in June 1997, which, among other things,
required the establishment of a transition cost balancing account and
annual transition cost proceedings, set a market rate forecast for 1998
transition costs, and required that generation-related regulatory assets
be amortized ratably over a 48-month period. Hearings on Phase 2 were
held in May and June 1997 and a final decision was issued on November 19,
1997. The Phase 2 decision established the calculation methodologies and
procedures for SCE to collect its transition costs from 1998 through the
end of the rate freeze. The Phase 2 decision also reduced SCE's authorized
rate of return on certain assets eligible for transition cost recovery
(primarily fossil- and hydroelectric- generation related assets) beginning
July 1997, five months earlier than anticipated. The decision, excluding
the effects of other rate actions, had a negative impact on 1997 earnings
of approximately $14 million. SCE has filed an application for rehearing
on the 1997 rate of return issue.
page 5
Utility Rate Reduction and Reform Act Initiative - On November 24, 1997,
individuals representing The Utility Reform Network (TURN), Public Media
Center and the Coalition Against Utility Taxes filed a voter initiative
with the California Attorney General. The proposed initiative, which was
amended by the proponents on December 9, 1997, seeks among other things
to: (i) impose an additional 10 percent rate reduction; (ii) block
stranded cost recovery of nuclear investments; (iii) restrict stranded
cost recovery of non-nuclear investments unless the CPUC finds that the
utility would be deprived of the opportunity to earn a fair rate of
return; and (iv) prohibit the collection of any charges pursuant to a
financing order for the purpose of making payments on rate reduction
notes, or if the financing order is found enforceable by a court, require
the utility to offset such charges with an equal credit to customers. On
February 11, 1998, the California Secretary of State circulated a copy of
the title and summary prepared for the proposed initiative by the
California Attorney General's Office, which included a summary of estimate
of the fiscal impacts on state and local governments if the initiative
were to pass. That estimate concluded that the net impact on state
government revenue would be annual revenue reductions of approximately
$100 million per fiscal year from 1998-2002. The estimate also referred
to potential state liability for debt service on the rate reduction notes.
The earliest that the initiative could be placed on a statewide ballot is
November 3, 1998. SCE is unable to predict the outcome of this matter,
but if the initiative were to qualify for the ballot, be voted into law
and upheld by courts, it could have a material effect on its results of
operations.
Accounting for Generation-Related Assets - If the CPUC's electric industry
restructuring plan is implemented as outlined above, SCE would be allowed
to recover its CTC through non-bypassable charges to its distribution
customers (although its investment in certain generation assets would be
subject to a lower authorized rate of return).
From November 1996 to July 1997, SCE and the other major California
electric utilities were engaged in discussions with the Securities and
Exchange Commission (SEC) staff regarding the proper application of
regulatory accounting standards in light of the electric industry
restructuring legislation enacted by the State of California in September
1996 and the CPUC's electric industry restructuring plan. This issue was
placed on the agenda of the Financial Accounting Standards Board's
Emerging Issues Task Force (EITF) during April 1997 and a final consensus
was reached at the July EITF meeting. During the third quarter of 1997,
SCE implemented the EITF consensus and discontinued application of
accounting principles for rate-regulated enterprises for its investment in
generation facilities.
However, implementation of the EITF consensus did not require SCE to write
off any of its generation-related assets, including regulatory assets of
approximately $600 million at December 31, 1997. SCE has retained these
assets on its balance sheet because the legislation and restructuring plan
referred to above make probable their recovery through a non-bypassable
CTC to distribution customers. These regulatory assets relate primarily
to the recovery of accelerated income tax benefits previously flowed
through to customers, purchased power contract termination payments,
unamortized losses on reacquired debt, and the recovery of amounts
deferred under the Palo Verde rate phase-in plan. The consensus reached
by the EITF also permits the recording of new generation-related
regulatory assets during the transition period that are probable of
recovery through the CTC mechanism.
If during the transition period events were to occur that made the
recovery of these generation-related regulatory assets no longer probable,
SCE would be required to write off the remaining balance of such assets as
a one-time, non-cash charge against earnings. If such a write-off were to
be required, SCE believes that it should not affect the recovery of
stranded costs provided for in the legislation and restructuring plan.
page 6
Although depreciation-related differences could result from applying a
regulatory prescribed depreciation method (straight-line, remaining-life
method) rather than a method that would have been applied absent the
regulatory process, SCE believes that the depreciable lives of its
generation-related assets would not vary significantly from that of an
unregulated enterprise, as the CPUC bases depreciable lives on periodic
studies that reflect the physical useful lives of the assets. SCE also
believes that any depreciation-related differences would be recovered
through the CTC.
If events occur during the restructuring process that result in all or a
portion of the CTC being improbable of recovery, SCE could have additional
write-offs associated with these costs if they are not recovered through
another regulatory mechanism. At this time, SCE cannot predict what other
revisions will ultimately be made during the restructuring process in
subsequent proceedings or implementation phases, or the effect, after the
transition period, that competition will have on its results of operations
or financial position.
Transmission Owners Tariff and Wholesale Distribution Access Tariff - On
March 31, 1997, SCE, PG&E and SDG&E jointly filed with the FERC a pro
forma Transmission Owners Tariff (T.O. Tariff). The pro forma T.O. Tariff
was filed in conjunction with the ISO and PX tariffs, also filed on that
date. Together, these tariffs set forth the rate design and terms and
conditions for transmission service provided over SCE's facilities over
which the ISO will have operational control. Additionally, on March 31,
1997, SCE filed an individual T.O. Tariff, its proposed revenue
requirement for the facilities being turned over to the operational
control of the ISO, and a Wholesale Distribution Access Tariff (WDAT).
The SCE T.O. Tariff, excluding appendices, is identical to the pro forma
T.O. Tariff, and also contains appendices setting forth SCE's proposed
Transmission Access Charges. FERC accepted the SCE T.O. Tariff rates and
WDAT for filing, subject to refund, on December 17, 1997.
FERC Restructuring Decision - In April 1996, the FERC issued its decision
on stranded-cost recovery and open access transmission, effective July
1996. The decision, reaffirmed by the FERC in its March and November 1997
orders, requires all electric utilities subject to the FERC's jurisdiction
to file transmission tariffs which provide competitors with increased
access to transmission facilities for wholesale transactions and also
establishes information requirements for the transmission utility. The
decision also provides utilities with the opportunity to recover stranded
costs associated with existing wholesale customers, retail-turned-
wholesale customers and retail wheeling when the state regulatory body
does not have authority to address retail stranded costs. Even though the
CPUC is currently addressing stranded-cost recovery through the CTC
proceedings, the FERC has also asserted primary jurisdiction over the
recovery of stranded costs associated with retial-turned-wholesale
customers, such as a new municipal electric system or a municipal
annexation. However, FERC did clarify that it does not intend to prevent
or interfere with a state's authority and that it has discretion to defer
to a state stranded-cost-calculation method. In January 1997, the FERC
accepted the open access transmission tariff SCE filed in compliance with
the April 1996 decision. The rates included in the tariff are being
collected subject to refund. In May 1997, SCE filed a revised open access
tariff to reflect the few revisions set forth in the March 1997 order.
The open access transmission tariff will be terminated on the date the ISO
begins operation.
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
page 7
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
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 (DOE) 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.
On December 16, 1997, the CPUC adopted a decision which established new
rules governing the relationship between California's natural gas local
distribution companies, electric utilities and certain of their
affiliates. While SCE and its affiliates have been subject to affiliate
transaction rules since the establishment of its holding company structure
in 1988, these new rules are more detailed and restrictive. On December
31, 1997, SCE filed a preliminary Compliance Plan which set forth SCE's
implementation of the new affiliate transaction rules. This preliminary
Compliance Plan was supplemented by an additional filing made on January
30, 1998. A CPUC resolution is expected on SCE's Compliance Plan during
the second quarter of 1998.
For purposes of an electric utility, such as SCE, these new rules apply to
all utility transactions with affiliates engaging in the provision of a
product that uses electricity or the provision of services that relate to
the use of electricity. Edison International is not subject to these new
affiliate transaction rules and will continue to be subject to the prior
rules. The new affiliate transaction rules are structured to address what
the CPUC perceives market power and cross subsidization concerns arising
out of the new competitive electricity market in California. These new
rules are categorized into nondiscrimination standards, disclosure and
information standards, and separation standards. In addition, the new
rules set forth requirements and restrictions on the utility's offering of
certain products and services.
SCE believes that the implementation of these new affiliate transaction
rules will not materially affect its results of operation or financial
position.
page 8
Rate Matters
CPUC Retail Ratemaking
The CPUC regulates the charges for services provided by SCE to its retail
customers. As discussed in the section on Competitive Environment, the
nature in which the CPUC regulates SCE is changing. The CPUC has issued
final decisions regarding direct access, transition cost recovery and rate
unbundling in the restructuring of the electric industry. These decisions
impact cost recovery and rate regulation beginning in January 1998, and
implement new ratemaking mechanisms replacing the Electric Revenue
Adjustment Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates
mechanism (collectively, the "pre-restructuring ratemaking mechanisms")
described in prior annual and quarterly reports filed with the SEC.
Total rates for all customers are frozen at June 10, 1996, levels,
although residential and small commercial customers received a 10%
reduction from their June 10, 1996, rate levels beginning January 1, 1998.
These rate levels will remain in effect for the remainder of the
transition period. Under these frozen rates, individual rate components
(distribution, transmission, nuclear decommissioning and public purpose
programs) are determined according to CPUC or FERC authorized mechanisms,
with the generation rate determined residually by subtracting these other
components from the total rate.
Distribution Rates
Distribution cost recovery is through a distribution PBR mechanism
currently authorized through December 2001. Key elements of the
distribution PBR include: distribution rates indexed for inflation based
on the Consumer Price Index less a productivity factor; 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
distribution operations. (See "California Electric Utility Restructuring-
- -PBR" section for additional discussion.)
Transmission Rates
Upon the commencement of the ISO and PX, transmission cost recovery will
be under FERC authority. Until commencement of the ISO and PX,
transmission cost recovery will be combined with distribution cost
recovery through a T&D PBR. (See "California Electric Utility
Restructuring--Rate-setting" and "FERC Restructuring Decision" above for
additional discussion.)
Nuclear Decommissioning and Public Purpose Program Rates
Recovery of SCE's nuclear decommissioning costs and legislatively mandated
public purpose program funding is through rates set to recover 100% of
these costs. Public purpose programs include cost effective energy
efficiency, research, renewable technology development, and low income
programs.
Generation Rates
Effective with the commencement of ISO and PX operations, generation costs
will be subject to recovery through the market price and the CTC.
Revenue available to recover the uneconomic generation costs subject to
recovery through the CTC will be determined residually by subtracting the
other rate components from total rates. This residual revenue will be
first allocated to recovery of FERC-authorized ISO charges for
transmission support and for purchases from the PX, and then to recovery
of transition costs. Transition costs associated with QF and interutility
contracts and the acceleration of sunk cost recovery will be subject to
annual reasonableness review by the CPUC.
page 9
Transition cost recovery for most utility generation assets will terminate
by March 31, 2002, or when these costs are fully collected. (See "CTC"
above for additional discussion.)
1991 Annual ECAC Application
In 1991, SCE issued its QF reasonableness testimony for the period April
1, 1990, through March 31, 1991. The Office of Ratepayer Advocates' (ORA)
report on QF reasonableness issues was issued in 1993. In its report, the
ORA recommended that the CPUC disallow $1.5 million in power purchase
expenses incurred as a result of purchases during the record period under
a QF contract with Mojave Cogeneration Company, a nonutility generator.
The ORA further alleged that ratepayers may be harmed in the amount of
$31.6 million (1993 net present value) over the contract's 20-year life.
SCE filed its rebuttal testimony on the contract in 1994. SCE and the ORA
subsequently reached a settlement where SCE agreed to a one-time reduction
to its ECAC balancing account of $14 million plus interest from January 1,
1996, to resolve the unreasonable action allegations by the ORA for 1991
and all subsequent record periods through the contract's 20-year life. On
October 30, 1996, the CPUC issued a decision which would approve the
settlement, subject to SCE and the ORA accepting certain conditions
concerning the manner in which the $14 million payment would be reflected
in rates. After reviewing the decision, SCE declined to accept the
condition proposed by the CPUC. Hearings on the ORA's disallowance
recommendations regarding the Mojave Cogeneration contract were held in
June 1997. During the hearings, the ORA presented testimony to update its
assessment of ratepayer harm, which it now assesses to be $45 million
(1997 net present value) over the contract's life. On November 26, 1997,
the assigned Administrative Law Judge (ALJ) issued a proposed decision
(which is not binding on the CPUC) which would adopt the ORA's imprudence
allegations. On January 13, 1998, the assigned ALJ issued an order
setting aside the proposed decision in order to accommodate SCE's request
for an oral argument to a quorum of the Commissioners. Oral arguments
were heard on February 4, 1998, at which time SCE requested an alternate
proposed decision be issued. On March 11, 1998, the Assigned Commissioner
issued an alternate proposed decision which recommends a disallowance of
$46,000 for the record period and expected disallowances of $16.3 million
over the life of the Mojave Cogeneration contract. The matter is
currently scheduled for consideration at the CPUC's March 26, 1998
meeting.
1992 Annual ECAC Application
SCE filed its QF reasonableness testimony in September 1992. In January
1996, the ORA released its report on QF reasonableness for the 1992 record
period as well as for that portion of the 1991 record period concerning
capacity truncation and energy deliveries at forecast rates. On February
17, 1998, the ORA submitted surrebuttal testimony. Hearings on the matter
began on March 9 and concluded March 17, 1998 subject to SCE's right to
recall certain witnesses in rebuttal to ORA's witnesses. If SCE elects to
recall such witnesses, the hearing will resume on April 1, 1998. An
adverse decision for SCE on either or both issues could, under certain
circumstances, have a material impact on SCE's financial position if the
decision were extended to subsequent record periods. The ORA's
surrebuttal testimony recommends a disallowance of $17.5 million
associated with firm capacity truncation, $17.4 million for forecasted
energy payments at forecast rates, and $43,000 for as-available capacity
payments at forecast rates. These amounts encompass the 1991 and 1992
periods, and exclude certain projects which have been deferred in this
proceeding.
1993 Annual ECAC Application
SCE filed its QF reasonableness testimony on September 1, 1993. On March
2, 1998, the ORA filed a combined report covering the QF reasonableness
phases of SCE's ECAC applications for 1993-1995. In the report, the ORA
page 10
recommends a disallowance of $5.6 million related to SCE's administration
of a contract with the Arbutus wind project. No other reasonableness
issues were identified in the report. SCE's rebuttal testimony is due on
June 4, 1998, and hearings are scheduled for early August 1998.
1994 Annual ECAC Application
SCE filed its QF reasonableness testimony and non-QF Reasonableness of
Operations Report on May 27, 1994. The QF testimony reflects the
reasonableness of execution of two new QF contracts and the reasonableness
of SCE's administration of 393 QF contracts. The non-QF report addresses
power purchases and exchanges, and the operation of hydroelectric, coal,
gas and nuclear resources for the period April 1, 1993, through March 31,
1994. The 1993, 1994 and 1995 QF issues will be joined for hearing.
The non-QF issues were bifurcated with the gas procurement issues being
separated from the other non-QF issues. On August 2, 1996, the CPUC
issued a decision finding that SCE's non-QF, non-gas procurement
activities were reasonable.
The ORA recommended a $13.3 million disallowance for costs incurred from
November 1993 through March 1994 associated with SCE's Canadian gas supply
and transportation contracts.
On October 17, 1996, the ALJ granted the ORA's motion to consolidate the
1994 and 1995 record periods for the limited purpose of addressing the gas
reasonableness issues. Hearings on these issues began January 21, 1997,
and were concluded on February 20, 1997.
However, briefing was suspended by the ALJ at the request of the parties
to facilitate settlement discussions. On July 11, 1997, the ORA and SCE
executed a Settlement Agreement.
The basic elements of the Settlement include: (1) a $39 million
disallowance for Canadian gas costs incurred through December 31, 1996;
(2) a disallowance of $257,000 per month, per contract, for each of SCE's
four supply contracts for Canadian gas costs beginning after January 1,
1997, and continuing until each of the commodity contracts are terminated
(one supply agreement was terminated on May 1, 1997, and the remaining
three supply agreements were terminated on July 1, 1997); (3) a cost
sharing mechanism in lieu of reasonableness review, whereby shareholders
would absorb at least 20% of the termination or restructuring costs
associated with the Canadian supply and transportation contracts and at
least 5% of the termination or restructuring costs associated with the El
Paso transportation contract which the CPUC has already found reasonable
(a portion of these termination or restructuring costs associated with the
cost sharing mechanisms would be flowed through to ratepayers through the
Energy Deferred Refund Account); and (4) agreement that all other costs
incurred under these contracts, including the termination, buy-down and/or
buy-out costs are reasonable and should be determined to be reasonable by
the CPUC.
On December 3, 1997, the CPUC issued a decision approving the Settlement
between SCE and the ORA. On March 12, 1998, the CPUC issued a decision
ordering SCE to refund $65 million. The Settlement has been fully
reflected in SCE's financial statements.
A discussion of the ORA's report in the QF reasonableness phase of this
ECAC is set forth above in the discussion of the 1993 ECAC Application.
page 11
1995 Annual ECAC Application
SCE filed its reasonableness of operations testimony on May 26, 1996. The
QF reasonableness testimony reflects the reasonableness of settlement
agreements with six QFs, the reasonableness of the Biogen Power I
termination agreement, and the reasonableness of the SCE's administration
of 414 QF contracts for the period April 1, 1994, through March 31, 1995.
The 1993, 1994 and 1995 QF issues will be joined for hearing.
The non-QF report addresses power purchases and exchanges, and the
operation of hydroelectric, 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 non-QF reasonableness issues. The report
recommended a $6.6 million disallowance for replacement fuel expenses
associated with 64 outage days due to the Palo Verde Unit 2 steam
generator tube rupture in 1993, and that the issue of $5.2 million of
nuclear fuel expenses associated with the NUEXCO Trading Corp. bankruptcy
be held open for review. In written response to data requests, the ORA
indicated it has withdrawn its concerns over the nuclear fuel expenses.
Additionally, SCE and the ORA executed a stipulation on December 18, 1997,
resolving the Palo Verde issue by agreeing to a disallowance of $318,540
plus interest which is the replacement fuel expense associated with six
outage days. A motion requesting approval of the SCE/ORA stipulation was
filed with the CPUC in December 1997. The CPUC issued its decision
approving the stipulation on February 19, 1998.
On October 4, 1996, the ORA issued its report on SCE's Canadian gas
procurement contracts discussed above. The report recommended 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. The reasonableness of the Canadian gas
procurement and transportation costs for the record period was resolved by
the ORA/SCE settlement discussed above in the 1994 Annual ECAC
Application. The Settlement has been fully reflected in SCE's financial
statements.
A discussion of the ORA's report in the QF reasonableness phase of this
ECAC is set forth above in the discussion of the 1993 ECAC Application.
1996 Annual ECAC Application
SCE filed its testimony on May 3, 1996, requesting a finding that its fuel
and purchased power costs, including purchases from QFs recorded during
the period April 1, 1995, through March 31, 1996, were reasonable. The QF
reasonableness testimony supports the reasonableness of SCE's
administration of 396 QF contracts, including the restructuring or buyout
of certain contracts. The non-QF testimony supports the reasonableness of
other power purchases and exchanges, and the operation of hydroelectric,
coal, gas and nuclear resources.
SCE requested and obtained an expedited finding of reasonableness by the
CPUC for an agreement it signed with Portland General Electric (PGE),
terminating a long-term power purchase contract. On December 9, 1996, the
CPUC issued a decision finding the termination of the agreement
reasonable. Additionally, as the final part in the approval process, PGE
and SCE filed notices of cancellation of the agreement with the FERC to be
effective December 31, 1996. The FERC has accepted the notices of
cancellation.
Review by the ORA of the non-QF operations has been consolidated with its
review in the 1997 Annual ECAC Application. The ORA's report was issued
on August 18, 1997. (See "1997 Annual ECAC Application.") No date has
been scheduled for the ORA's report on QF reasonableness.
page 12
1997 Annual ECAC Application
On May 30, 1997, SCE filed its annual reasonableness report requesting
that the CPUC find reasonable its fuel and purchased-power costs,
including purchases from QFs recorded during the period of April 1, 1996,
through March 31, 1997. The QF testimony supports the reasonableness of
the SCE's administration of its QF contracts, including two QF
settlements. The non-QF testimony supports the reasonableness of other
power purchases and exchanges, fuel costs and the operation of
hydroelectric, coal, gas and nuclear resources.
The ORA's review of the non-QF operations and costs has been consolidated
with its review of the non-QF operations and costs in the 1996 ECAC
Application. The ORA filed its report on August 18, 1997. In its report,
the ORA recommended, among other things, (1) a disallowance of $360,000
associated with an outage at the coal-fired Four Corners Generating
Station and (2) a $200,000 adjustment to the costs recorded in SCE's
Catastrophic Events Memorandum Account. Hearings took place in January
1998. A CPUC decision is expected by July 1998. No date has been
scheduled for the ORA's report on QF reasonableness.
Palo Verde
In January 1997, the CPUC authorized a further acceleration of the
recovery of its remaining investment of $1.2 billion in Palo Verde Units
1, 2 and 3. The accelerated recovery will continue through December 2001,
earning a 7.35% fixed rate of return. The accelerated plant recovery, as
well as future operating costs, including nuclear fuel and nuclear fuel
financing costs, and incremental capital expenditures, are subject to
balancing account treatment through 2001. Beginning January 1, 1998, the
balancing account became part of the CTC mechanism. The existing nuclear
unit incentive procedure will continue only for purposes of calculating a
reward for performance of any unit above an 80% capacity factor for a fuel
cycle. Beginning in 2002, SCE will be required to share equally with
ratepayers the net benefits received from operation of Palo Verde.
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 $3.7 billion in 1997, an
11.9% increase over 1996.
SCE's sources of energy during 1997 were: purchased power 49%; natural gas
16%; nuclear 17%; coal 12%; and hydro 6%.
Average fuel costs, expressed in cents per kilowatt-hour, for the year
ended December 31, 1997, were: oil, 8.53 cents; natural gas, 3.39 cents;
nuclear, 0.48 cents; and coal, 1.32 cents.
page 13
Natural Gas Supply
As a result of the sale of 11 of its 12 gas-fired generating stations, SCE
has terminated four long-term natural gas supply and three long-term gas
transportation contracts which had been used to import gas from Canada.
In addition, SCE has exercised the option under its 15-year gas
transportation commitment with El Paso Natural Gas Company to reduce its
capacity obligation from 200 million to 130 million cubic feet per day.
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. The Nuclear Waste Policy Act of
1982 requires that the DOE provide for the disposal of utility
spent nuclear fuel beginning January 31, 1998. The DOE defaulted
on its obligation to begin acceptance of spent nuclear fuel from
San Onofre. Dry cask storage either on-site or at another location
will be required to permit continued operations beyond the date
indicated above.
Participants at Palo Verde have contractual agreements for uranium
concentrates to meet projected requirements through 2000. Independent of
arrangements made by other participants, SCE will furnish its share of
uranium concentrates requirement through at least 1998 from existing
contracts. Contracts cover requirements to provide conversion through
2000, enrichment through 2002, and fabrication through 2016.
Palo Verde on-site spent fuel storage capacity will accommodate needs
through 2002 for Units 1 and 2, and through 2003 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 (CAA) 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.
page 14
The CAA as amended in 1990, and as implemented within the South Coast Air
Quality Management District (SCAQMD) and other districts within California
required SCE to reduce emissions of oxides of nitrogen from its generating
stations. SCE is selling all of its oil- and gas-fueled generating
stations within the SCAQMD, the Mohave Desert Air Quality Management
District, Ventura County Air Pollution Control District, and the Santa
Barbara County Air Pollution Control District, with an expected sale
closure date for 11 of the 12 generating stations being sold by March 31,
1998 (the twelfth plant is expected to be sold in 1998). It is expected
that after the generating stations' sale closure dates, under operations
and maintenance contracts with the individual owners, SCE will operate
those facilities that are kept in operation as active generating stations.
SCE operations of the stations it gains contracts for, will be under the
direction and expense of the new owners. SCE will be responsible for
maintaining the environmental permits of the plants. However, the new
owners, not SCE, will be responsible for the purchase and installation of
emissions control equipment, and sufficient trading credits required for
the plants under the Regional Clean Air Incentives Market within the
SCAQMD.
The CAA does not require any significant additional emissions control
expenditures that are identifiable at this time. The Environmental
Protection Agency (EPA) plans to issue its final rulemaking regarding
regional haze regulations in late 1998. Also, the EPA and SCE will
conclude a cooperative tracer study of sulfur dioxide emissions from the
Mohave Generating Station in mid- to late-1998. The study is evaluating
potential impact from Mohave emissions on haze within the Grand Canyon
National Park. The extent to which these two activities may require
sulfur dioxide or particulate emissions reductions at the Mohave plant is
not known. The acid rain provisions of the amended CAA 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. Until more definite information on tracer study results are
available, SCE expects to meet all the present regulations through
improved operations at the plant.
On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed
suit against SCE and the other co-owners of Mohave in the U.S. District
Court of Nevada alleging violations over the last five years of the CAA,
the Nevada State Implementation Plan, and applicable air quality permits
relating to opacity and sulfur dioxide emission limits. SCE, on behalf of
the co-owners, will provide a timely response in defense of the suit.
The CAA also requires the EPA to carry out a three-year study of risk to
public health from the emissions of toxic air contaminants from electric
utility steam generating plants, and to regulate such emissions only if
required. The study has not been finalized by the 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.
page 15
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 the 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 discounted 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.
In connection with the issuance of the San Onofre Units 2 and 3 operating
permits, SCE reached an agreement with the California Coastal Commission
in 1991 to restore certain marine mitigation sites. The restorations
include two sites: designated wetlands and the construction of an
artificial reef for kelp off the California coast. After SCE requested
certain modifications to the agreement, the California Coastal Commission
issued a final ruling in April 1997 to reduce the scope of remediations.
SCE elected to pay for the costs of marine mitigation in lieu of placing
the funds into a trust. Recovery of these costs is occurring through the
San Onofre incentive pricing plan.
SCE's recorded estimated minimum liability to remediate its 50 identified
sites is $178 million, which includes $75 million for the two sites
discussed above. The ultimate costs to clean up SCE's identified sites
may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as the extent and nature of
contamination; the scarcity of reliable data for identified sites; the
varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites;
and the time periods over which site remediation is expected to occur.
SCE believes that, due to these uncertainties, it is reasonably possible
that cleanup costs could exceed its recorded liability by up to $246
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 41 of its
sites, representing $91 million of its recorded liability, through an
incentive mechanism (SCE may request to include additional sites). Under
this mechanism, SCE will recover 90% of cleanup costs through customer
rates; shareholders fund the remaining 10%, with the opportunity to
recover these costs from insurance carriers and other third parties. SCE
has successfully settled insurance claims with all responsible carriers.
Costs incurred at SCE's remaining sites are expected to be recovered
through customer rates. SCE has recorded a regulatory asset of $153
page 16
million for its estimated minimum environmental-cleanup costs expected to
be recovered through customer rates. This amount includes $60 million of
marine mitigation costs remaining to be recovered through the San Onofre
incentive pricing plan.
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 now be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30
years. Remediation costs in each of the next several years are expected
to range from $4 million to $10 million. Recorded costs for 1997 were $10
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 materially
affect 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 projected capital expenditures to protect the environment are $820
million for the 1998-2002 period, mainly for aesthetics treatment,
including undergrounding certain transmission and distribution lines.
Year 2000 Issue
Many of SCE's existing computer systems identify a year by using only two
digits instead of four. If not corrected, these programs could fail or
create erroneous results when encountering dates in 2000 or later. This
situation has been referred to generally as the Year 2000 Issue.
SCE has developed plans and is addressing the programming changes that it
has determined are necessary in order for its computer systems to function
properly beginning in 2000. Remediation of SCE's key financial systems
for the Year 2000 Issue was completed in 1997. SCE's informational and
operational systems have been assessed, and detailed plans have been
developed to address modifications required to be completed, tested and
operational by December 31, 1999. Preliminary estimates of the costs to
complete these modifications, including the cost of new hardware and
software application modifications, range from $55 million to $80 million,
about half of which are expected to be capital costs. Current rate levels
for providing electric service should be sufficient to provide funding for
these modifications. Remediation of existing critical systems is expected
to be 75% complete by the end of 1998. SCE expects its Year 2000 date
conversion project to be completed on a timely basis, with no material
adverse impact to its results of operations or financial position.
SCE's Year 2000 date conversion project includes an assessment of critical
interfaces with the computer systems of others and it does not expect a
material adverse effect on its operating and business functions from the
Year 2000 Issue.
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.
page 17
SCE has signed agreements to sell 11 of its 12 oil- and gas-fueled
generating plants, and expects those sales to close by March 31, 1998.
SCE is also seeking to sell the twelfth plant. Any of the sold plants
which remain in operation will continue to be operated by SCE for at least
two years following the sale.
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 Four Corners, a
coal-fueled steam electric generating plant in New Mexico. Palo Verde
and Four Corners 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 1997, the existing SCE-owned generating capacity (summer
effective rating) was comprised of approximately 65% gas, 15% nuclear, 11%
coal, 8% hydroelectric and 1% oil.
San Onofre, Four Corners, 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 1997, SCE's peak demand was 19,118 MW, set on September 4, 1997. Total
area system operating capacity of 21,511 MW was available to SCE at the
time of the 1997 peak.
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 $2.8 billion principal amount was outstanding at
December 31, 1997. 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 Four Corners and the related easement and lease referred to
below may be so considered.
page 18
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.
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $685 million in
1997, $616 million in 1996 and $773 million in 1995. Construction
expenditures for the 1998-2002 period are forecasted at $3.9 billion.
In addition to cash required for construction expenditures for the next
five years as discussed above, $2.8 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 2002 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 General
Rate Case (GRC) rejected a settlement agreement proposed by SCE, SDG&E and
the 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 SCE's 1995 GRC 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 of 7.35%, but on an accelerated basis during the eight-year period
from the effective date in 1996 through December 31, 2003. Under Assembly
Bill 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
an incentive pricing plan, 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. Assembly Bill 1890 allowed continuation of the
incentive pricing plan through December 31, 2003, the end of the
page 19
eight-year period. SCE was compensated for the incremental costs required
for the continued operation of San Onofre Units 2 and 3 only with revenue
earned through the incentive pricing plan. 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.
On July 16, 1997, the CPUC approved SCE's request to transfer the recorded
net investment in San Onofre Units 2 and 3 step-up transformers to San
Onofre Units 2 and 3 sunk costs for recovery by December 31, 2001, at a
reduced rate of return of 7.35%.
On August 21, 1997, the CPUC approved SDG&E and SCE's Joint Petition to
Modify, requesting continued recovery of certain corporate administrative
and general costs allocable to San Onofre Units 2 and 3, at rates of 0.28 cent
and 0.21 cent per kWh, respectively, for the period January 1, 1998, through
December 31, 2003.
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
of 7.35% consistent with AB 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 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 1992, the CPUC approved a settlement agreement between SCE and the ORA
to discontinue operation of Unit 1 at the end of its then-current fuel
cycle. In November 1992, SCE discontinued operation of Unit 1. As part
of the agreement, SCE recovered its remaining investment over a four-year
period ending August 1996.
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. However, during the Unit 2 scheduled refueling and
inspection outage, which was completed in Spring 1997, an increased rate
of degradation was identified, which resulted in the removal of more tubes
from service than had been expected. The steam generator design allows
for the removal of up to 10% of the tubes before the rating capacity
page 20
of the unit must be reduced. As a result of the increased degradation, a
mid-cycle outage was conducted in February 1998 for Unit 2. The results
of that outage are still being evaluated.
During Unit 3's refueling outage, which was completed in July 1997,
inspections of structural supports for steam generator tubes identified
several areas where the thickness of the supports had been reduced,
apparently by erosion during normal plant operation. As a result, a mid-
cycle outage is planned for early 1998. However, during Unit 2's Spring
1997 outage and the February 1998 mid-cycle outage, similar tube supports
showed no signs of such erosion.
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
of the Palo Verde participants is required for capital improvements,
including steam generator replacement. In December 1997, the Palo Verde
participants unanimously agreed to purchase two spare steam generators at
a cost of approximately $82 million; however, SCE has not yet decided
whether it supports replacement of the Unit 2 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 $2.1 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 accrued and recovered through non-
bypassable customer rates over the terms of each nuclear facility's
operating license, are recorded as a component of depreciation expense.
Decommissioning expense was $154 million in 1997, $148 million in 1996 and
$151 million in 1995. The accumulated provision for decommissioning was
page 21
$1.1 billion at December 31, 1997, and $949 million at December 31,
1996. The estimated costs to decommission San Onofre Unit 1 ($280 million
in 1993 dollars) 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 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 NRC 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.
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 $28 million per year.
Insurance premiums are charged to operating expense.
Item 3. Legal Proceedings
Qualifying Facilities 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
(EME) (a subsidiary of Edison International) at the time of filing. In
April 1996, EME'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.
page 22
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. SCE intends to seek recovery of this payment
through rates. SCE 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, SCE 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, SCE 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 start on April 23, 1997.
This hearing date was subsequently vacated by the assigned administrative
law judge due to ongoing discussions to resolve issues raised by the ORA's
protest. As a result of those discussions, SCE and the ORA entered into
a stipulation and agreement (Stipulation) effective July 11, 1997. In the
Stipulation, the ORA agrees to withdraw its protest and support SCE's
application in return for SCE's agreement that the cost recovery issues
presented in the application may be transferred for a decision in SCE's
1992 ECAC proceeding, where related issues are currently pending. The
Stipulation further provides for SCE and the ORA to file a joint motion
for approval of the Stipulation. The motion was filed on September 25,
1997. In light of the Stipulation, plaintiffs and SCE have entered into
two amendments to the May 1, 1996, settlement agreement. The first
amendment provides for the post-1995 portion of the settlement to become
effective through 1997 upon CPUC approval consistent with the Stipulation.
The second amendment resulted in plaintiffs dismissing the lawsuit without
prejudice pending final CPUC resolution of the issues raised by SCE's
application. On December 16, 1997, the CPUC issued a decision which
approves the application subject to the terms of the Stipulation. In
light of this decision, SCE has supplemented its testimony in the 1992
ECAC proceeding to support its request to recover its costs of settlement.
Hearings in the 1992 ECAC began on March 9, 1998, and are scheduled to
conclude on approximately March 20, 1998.
Wind Generators' Litigation
Between January 1994 and October 1994, SCE was named as a defendant in a
series of eight lawsuits brought by independent power producers of wind
generation. Seven of the lawsuits were filed in Los Angeles County
Superior Court and one was filed in Kern County Superior Court. The
lawsuits allege SCE incorrectly interpreted contracts with the plaintiffs
by limiting fixed energy payments to a single 10-year period rather than
beginning a new 10-year period of fixed energy payments for each stage of
development. In its responses to the complaints, SCE denied the
plaintiffs' allegations. In each of the lawsuits, the plaintiffs seek
declaratory relief regarding the proper interpretation of the contracts.
Plaintiffs allege a combined total of approximately $189 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
page 23
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.
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.
Shortly thereafter, on April 3, 1996, pursuant to stipulation of the
parties, the Kern County case was ordered to be coordinated with the Los
Angeles cases so that it too will be tried in Los Angeles. Trial of the
consolidated cases, beginning with the lead case, commenced on March 10,
1997. The consolidated cases are to be tried one after another in
bifurcated fashion with the liability phase of each and all of the cases
to be tried before commencement of the damages phase, if applicable.
Testimony and arguments in the liability phase of the lead case concluded
on May 20, 1997. On July 7, 1997, the court issued a tentative decision
which effectively would resolve all liability issues in the lead case in
SCE's favor. A proposed Statement of Decision consistent with the
conclusions in the tentative decision was submitted by SCE and argument on
the same took place at a hearing on October 31, 1997. The hearing was not
concluded at that time and further argument took place on November 17,
1997. On December 22, 1997, the judge ruled on the objections raised at
the two hearings and ordered SCE to prepare a proposed Statement of
Decision incorporating her ruling. SCE submitted this document to the
court on January 13, 1998. At a hearing on February 4, 1998, the court,
after considering additional objections to parts of the proposed order,
directed SCE to prepare a further, revised order which would not
materially change the court's previous, tentative rulings. This final
statement of decision was filed on February 6, 1998. In addition, on
February 20, 1998, the court entered a judgment against the lead
Plaintiff. The court also scheduled another status and trial setting
conference for April 2, 1998.
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles Superior Court
against another independent power producer of geothermal generation and
five of its affiliated entities (collectively the "Defendants"). SCE
alleges that in order to avoid power production plant shutdowns caused by
excessive noncondensable gas in the geothermal field brine, the Defendants
routinely vented highly toxic hydrogen sulfide gas from unmonitored
release points beginning in 1990 and continuing through at least 1994, in
violation of applicable federal, state and local environmental law.
According to SCE, these violations constituted material breaches by the
Defendants of their obligations under their contracts and applicable law.
The complaint seeks termination of the contracts and damages for excess
power purchase payments made to the Defendants. The Defendants' motion to
transfer venue to Inyo County Superior Court was granted on August 31,
1997.
On December 19, 1997, SCE filed a second amended complaint in response to
which the Defendants filed a motion to strike, which was argued and taken
under submission by the court on March 13, 1998. The Defendants also
filed a motion for summary judgment, set for hearing on March 19, 1998,
asserting that SCE's claims are time-barred or were released in connection
with the settlement of prior litigation among some of the Defendants and
two of SCE's affiliates, Mission Power Engineering Company, and The
Mission Group (the Mission Parties). SCE asserts that the earlier
settlement does not bar the claims it is prosecuting in this matter and
page 24
that these claims are not time-barred. SCE has filed its opposition
to the motion for summary judgment and will shortly file a supplemental
opposition to address certain additional matters raised by the Defendants.
SCE has also filed a cross motion for summary adjudication with respect to
the issues raised in Defendants' summary judgment motion. No hearing date
has been scheduled for SCE's motion for summary adjudication. In
addition, the Defendants have filed a motion to stay SCE's case pending
resolution of certain technical issues by the Great Basin Air Quality
Management District under the doctrine of primary jurisdiction. The
motion was heard for hearing on March 13, 1998, and the matter was taken
under submission at that time.
The Defendants have also asserted various claims against SCE and the
Mission Parties in a cross-complaint filed in the action commenced by SCE
as well as in a separate action filed against SCE by three of the
Defendants in Inyo County Superior Court. Following a hearing on November
20, 1997, the court consolidated these actions for all purposes and
ordered the Defendants to file a second amended cross-complaint.
The second amended cross-complaint asserts nineteen causes of action
against SCE, three of which are also asserted against the Mission Parties.
Included are claims for declaratory relief; breach of the implied covenant
of good faith and fair dealing; inducing breach of employee agreements;
breach of contract; disparagement, and slander per se; injunctive relief
and restitution for unfair business practices; anticipatory breach of
contract; violation of Public Utilities Code Sections 453, 707 and 2106;
and negligent and intentional misrepresentation. Several of these claims
are premised on the theory that SCE has incorrectly interpreted the cross-
complainants' contracts as providing for only a single "fixed price"
period in view of the fact that the cross-complainants developed their
projects in phases. This theory has also been asserted by other
independent power producers in litigation pending in Los Angeles Superior
Court. (See, "Wind Generation Litigation" above.) SCE filed a demurrer
to, and a motion to strike, in response to the second amended cross-
complaint, both of which were argued on March 13, 1998, and taken under
submission by the court.
Based on the common issues asserted in the Wind Generation Litigation and
the Defendants' second amended cross-complaint, SCE filed a petition to
coordinate the consolidated actions pending in Inyo County Superior Court
with the Wind Generation Litigation pending in Los Angeles Superior Court.
In connection with the petition to coordinate, SCE has also applied for a
stay of all proceedings in Inyo County. Both the petition to coordinate
and the application for stay will be decided by the judge presiding in the
Wind Generation Litigation. A hearing has been scheduled with respect to
both SCE's petition to coordinate and the application for stay on March
30, 1998.
Discovery is at a very preliminary stage, and it is reasonable to
anticipate that there will be further amendments to the pleadings. The
materiality of net final judgments against SCE in these actions would be
largely dependent on the extent to which any damages or additional
payments which might result therefrom are recoverable through rates.
Electric and Magnetic Fields (EMF) Litigation
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
page 25
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. In April 1995, Grubb & Ellis filed a cross-
complaint against the other co-defendants, requesting indemnification and
declaratory relief concerning the rights and responsibilities of the
parties. Although stayed for a time pending appellate review of sanctions
imposed against plaintiffs' attorneys by the trial court, the case has
been remanded back to the trial court following the Court of Appeal's
decision modifying the sanctions order. To date, no further proceedings
have been scheduled.
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' 15 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. Oral argument on the appeal took
place on December 4, 1997, and the matter is now under submission. All
trial court proceedings have been stayed pending the ruling of the Court
of Appeals. The impact on SCE, if any, from further proceedings in this
case against the remaining defendants cannot be determined at this time.
page 26
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. Oral
argument on the appeal took place on December 4, 1997, and the matter is
now under submission. 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 on 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),
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. SCE's motion for
summary judgment was denied on April 9, 1997. The trial in this case took
place over approximately 22 days between January and March 1998 and
resulted in a jury verdict for both defendants. It is not known whether
plaintiffs will move for a new trial and/or appeal.
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
page 27
claims of the former worker and her husband with prejudice. This case is
expected to go to trial in mid-1998, after completion of the trial court
proceedings in the case described in the preceding paragraph.
On November 20, 1997, a former contract worker at San Onofre and his wife
sued SCE in the Superior Court of California, County of San Diego. The
contract worker was an ironworker at San Onofre during a portion of 1995.
The suit alleges that SCE allowed dangerous conditions to exist at San
Onofre, causing him to sustain unspecified personal injuries. His wife
alleges loss of consortium and other general damages. The case has been
removed to the U.S. District Court for the Southern District of
California. SCE filed a motion on January 6, 1998, asking that the case
be converted to a Price-Anderson cause of action.
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.
On June 30, 1997, SCE filed an answer to the complaint denying the
substantive allegations and raising appropriate defenses. Plaintiff and
SCE reached a settlement of this dispute for nonmonetary compensation. An
agreement to dismiss the lawsuit was filed with the court on February 8,
1998.
False Claims Act Litigation
In September 1997, SCE became aware of a complaint filed in the Southern
District of the U.S. District Court of California by a San Onofre
employee, acting at his own initiative on behalf of the United States
under the False Claims Act, against SCE and SDG&E. The complaint alleges
that SCE and SDG&E have submitted fraudulent claims to the United States
government, the State of California and their customers resulting in $491
million in overpayments ($383 million of which is attributed to SCE). The
employee alleges that SCE and SDG&E provided the CPUC with data which
inflated projected costs at San Onofre while minimizing projected revenue,
resulting in the CPUC setting inflated rates. The amount sought in this
complaint is subject to trebling, plus civil penalties of $10,000 per
false claim submitted for payment (for an unspecified number of claims).
SCE and SDG&E filed separate motions to dismiss this lawsuit on November
6, 1997. The employee responded to both motions on December 20, 1997.
SCE and SDG&E replied to the employee's response on January 13, 1998.
Oral argument on the motion to dismiss was heard on January 20, 1998, and
the court has the matter under submission.
Mohave Generating Station Environmental Litigation
On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed
suit against SCE. Mohave is operated by SCE, and SCE is one of several
co-owners. The lawsuit alleges that Mohave has been violating various
provisions of the Clean Air Act, the Nevada state implementation plan,
and applicable pollution permits relating to opacity and sulfur dioxide
page 28>
emission limits over the last five years. The plaintiffs seek declaratory
and injunctive relief as well as civil penalties. Under the Clean Air
Act, the maximum civil penalty obtainable is $25,000 per day of violation.
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, 1997 Company Position Date
- ----------------- -------- ---------------- ----------
John E. Bryson 54 Chairman of the Board, October 1, 1990
Chief Executive Officer
and Director
Stephen E. Frank 56 President, Chief Operating June 19, 1995
Officer and Director
Bryant C. Danner 60 Executive Vice President June 1, 1995
and General Counsel
Alan J. Fohrer