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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, 1998
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 executive (Zip Code) including area code)
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 American and Pacific
4.08% Series 4.78% Series
4.24% Series 5.80% Series
4.32% Series
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
As of March 19, 1999 there 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 $355,326,761 on or about March 19, 1999 based upon prices reported
by the American Stock Exchange. The market values of the various classes of
voting stock held by non-affiliates, as of March 19, 1999, were as follows:
CUMULATIVE PREFERRED STOCK $99,626,761; $100 CUMULATIVE PREFERRED STOCK
$255,700,000.
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, 1998................................... Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 1999 Annual Meeting
of Shareholders..................................... Part III
TABLE OF CONTENTS
Item Page
Part I
1. Business......................................................... 1
Competitive Environment..................................... 1
California Electric Utility Restructuring................... 1
Regulation ................................................. 4
Rate Matters................................................ 5
Fuel Supply and Purchased Power Costs....................... 10
Environmental Matters....................................... 11
Year 2000 Issue............................................. 14
2. Properties....................................................... 14
Existing Generating Facilities.............................. 14
Construction Program and Capital Expenditures............... 16
Nuclear Power Matters....................................... 16
3. Legal Proceedings................................................ 19
Wind Generators' Litigation................................. 19
Geothermal Generators' Litigation........................... 19
Electric and Magnetic Fields (EMF) Litigation............... 20
San Onofre Personal Injury Litigation....................... 21
Mohave Generating Station Environmental Litigation.......... 21
4. Submission of Matters to a Vote of Security Holders.............. 22
Executive Officers of the Registrant............................. 22
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters.............................................. 25
6. Selected Financial Data.......................................... 25
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition............................... 25
7a. Quantitative and Qualitative Disclosures About Market Risk....... 25
8. Financial Statements and Supplementary Data...................... 25
9. Changes in and Disagreements with Accountants
Accounting and Financial Disclosure.............................. 25
Part III
10. Directors and Executive Officers of the Registrant............... 25
11. Executive Compensation........................................... 26
12. Security Ownership of Certain Beneficial
Owners and Management............................................ 26
13. Certain Relationships and Related Transactions................... 26
Part IV
14. Exhibits, Financial Statement Schedules, and
Financial Reports........................................... 26
Reports on Form 8-K......................................... 27
Report of Independent Public Accountants on
Supplemental Schedules...................................... 28
Supplemental Schedules...................................... 29
Signatures.................................................. 32
Exhibit Index............................................... 33
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
that sets rates and implement 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; the effects of the
Year 2000 on computers; and other unforeseen events.
Item 1. Business
SCE was incorporated in 1909 under the laws of the State of California. 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 approximately 800
cities and communities and a population of more than 11 million people. SCE had
13,177 full-time employees at year-end 1998. During 1998, 31% of SCE's total
operating revenue was derived from residential customers, 33% from commercial
customers, 15% from sales to the power exchange (PX), 9% from industrial
customers, 6% from public authorities, 5% from agricultural and other customers
and 1% from resale customers. SCE comprises the major portion of the assets and
revenue of its parent holding company, Edison International.
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.
In the generation sector, SCE has experienced competition from nonutility power
producers; and regulators are restructuring California's electric utility
industry to facilitate additional competition. (See "Business of SCE --
California Electric Restructuring" below for a description of these changes.)
California Electric Utility Restructuring
Restructuring Decision -- The CPUC's December 1995 decision on restructuring
California's electric utility industry started the transition to a new market
structure; competition and customer choice began on April 1, 1998. Key elements
of the CPUC's restructuring decision included: creation of the PX and
Independent System Operator (ISO); availability of customer choice for
electricity supply and certain billing and metering services; 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 Statute -- In September 1996, the State of California enacted
legislation, Assembly Bill 1890 (AB 1890), to provide a transition to a
competitive market structure. The statute substantially adopted the CPUC's
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. The statute mandated
the implementation of the CTC that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring. Transition costs
related to power-purchase contracts are being recovered through the terms of
their contracts while most of the remaining transition costs will be recovered
through 2001. SCE expects to be able to recover its revenue requirement during
the 1998-2001 transition period. The statute also contained provisions for
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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 December 1997, after receiving approval from both the
CPUC and the California Infrastructure and Economic Development Bank, a limited
liability company created by SCE issued approximately $2.5 billion of rate
reduction notes. Residential and small commercial customers, whose 10% rate
reduction began January 1, 1998, are repaying the notes over the expected
ten-year term through non-bypassable charges based on electricity consumption.
There were originally seven classes of Notes. The first class, in the amount of
$246.3 million, matured in December 1998. The remaining notes consist of six
classes with maturities ranging from one to nine years, and bear interest
ranging from 6.14% to 6.42%.
On November 3, 1998, California voters rejected the voter initiative designated
as Proposition 9. Approximately 73% of the total votes cast were voted against
the proposition. Proposition 9 would have prohibited the collection of the
non-bypassable charges for the payment of the rate reduction notes and would
have severely restructured SCE's recovery of transition costs.
1998 Activities -- During 1998, SCE implemented changes to comply with the
restructuring elements required by the CPUC and with the restructuring statute.
Beginning January 1, 1998:
o SCE's rates were unbundled into separate charges for energy, transmission,
distribution, the CTC, public benefit programs, and nuclear
decommissioning. The transmission component is being collected through
FERC-approved rates, subject to refund.
o SCE's costs associated with hydroelectric plants are being recovered
through a performance-based mechanism. The mechanism sets the hydroelectric
revenue requirements and establishes a formula for 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 of transition to a competitive market environment.
o SCE's transition costs are being recovered 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 1995 restructuring decision date.
SCE has estimated transition costs to be approximately $10.6 billion (1998
net present value) from 1998 through 2030. This estimate is based on
incurred costs, forecasts of future costs, and assumed market prices.
Changes in the assumed market prices could materially affect these
estimates. Potential transition costs are comprised of $6.4 billion from
SCE's qualifying facilities contracts, which resulted from prior
legislative and regulatory mandates, and $4.2 billion (including the
effects of the sale of SCE's gas- and oil- fueled generation plants) from
costs pertaining to certain generating assets and regulatory commitments
consisting of costs incurred (whose recovery has been deferred by the CPUC)
from providing 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
Units 2 and 3 and the Palo Verde units, and certain other costs. The issue
was separated into two phases; Phase 1 addressed the rate-making issues and
Phase 2 addressed the quantification issues.
o Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the
establishment of a transition cost balancing account and annual transition
cost proceedings; the setting of a market rate forecast for 1998 transition
costs; the requirement that generation-related regulatory assets be
amortized ratably over a 48-month period; the establishment of calculation
methodologies and procedures for SCE to collect its transition costs from
1998 through the end of the rate freeze; and the reduction of 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. SCE has filed an
application for
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rehearing on the 1997 rate of return issue. The CPUC recently issued a
decision agreeing in part with SCE. Although a lower rate of return was
applied to the hydro and fossil assets for the period July 28, 1997
through November 21, 1997, the return was set at 7.35% rather than the
7.22% that was adopted in the earlier decision. This increase will result
in an additional $425,000 in earnings compared to the original decision.
o Residential and small commercial customers who have begun receiving a 10%
rate reduction are repaying the rate reduction notes issued in December
1997 through non-bypassable charges based on electricity consumption. (See
"California Electric Utility Restructuring-Rate Reduction Notes" above for
additional discussion.)
Effective April 1, 1998:
o The ISO assumed operational control of the transmission system on March 31,
1998, after the ISO and PX began accepting bids and schedules for
electricity purchases. The restructuring implementation costs related to
the start-up and development of the PX, which are paid by the utilities,
will be recovered from all retail customers over the four-year transition
period. SCE's share of the charge is $45 million, plus interest and fees.
SCE's share of the ISO's start-up and development costs (approximately $16
million per year) will be paid over a ten-year period.
o Customers can choose to purchase energy from new retailers called Electric
Service Providers (ESPs). As of December 31, 1998, approximately 47,000
customers are purchasing their energy from ESPs. All other customers are
purchasing energy from SCE, and SCE is in turn purchasing the energy it
supplies to them from the PX. Regardless of whom the customers choose to
supply their energy, SCE provides transmission and distribution services to
all customers within its service territory. All customers of SCE
transmission and distribution services also are paying the CTC, regardless
of their choice of energy supplier.
o Customers have options regarding metering, billing, and related services
(referred to as revenue cycle services) provided by California's
investor-owned utilities. ESPs can provide their customers with one
consolidated bill for their services and the utility's services, request
the utility to provide such a consolidated bill to the customer, or elect
to have both the ESP and the utility bill for respective charges. Customers
with maximum demand above 20 kWh (primarily industrial and medium and large
commercial) can choose SCE or any other supplier to provide their metering
service. Beginning in January 1999, all customers may make these choices.
SCE may experience a reduction in revenue security as a result of this
unbundling.
o In September 1998, the CPUC issued a decision requiring SCE to provide
credits beginning on January 1, 1999, to customers who elect to obtain
revenue cycle services from an ESP. The credits are based on the net cost
savings to SCE as a result of no longer providing these services. The CPUC,
however, has also begun a proceeding to consider whether the RCS credits
should be increased to reflect the prices likely to prevail in a
competitive market for RCS services. If the CPUC adopts credits based on
this premise, SCE has advocated that the resulting difference between
payments for the credits and costs actually avoided be recovered from all
customers in a competitively neutral manner.
During 1998, SCE sold all of its gas- and oil- fueled generation plants. The
total sales price of the 12 plants was $1.2 billion, over $500 million more than
the combined book value. Net proceeds of the sales were used to reduce stranded
costs, which otherwise were expected to be collected through the CTC mechanism.
Accounting for Generation-Related Assets -- If the CPUC's electric industry
restructuring plan continues as described above, SCE would be allowed to recover
its transition costs 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). In 1997, SCE discontinued application of
accounting principles for rate-regulated enterprises for its investment in
generation facilities based on new
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accounting guidance. The financial reporting effect of this discontinuance was
to segregate these assets on the balance sheet; the new guidance did not require
SCE to write off any of its generation-related assets, including related
regulatory assets. However, the new guidance did not specifically address the
application of asset impairment standards to these assets. SCE has retained
these assets on its balance sheet because AB 1890 and the restructuring plan
referred to above make probable their recovery through a non-bypassable CTC to
distribution customers. The regulatory assets relate primarily to the recovery
of accelerated income tax benefits previously flowed through to customers,
purchased power contract termination payments, and unamortized losses on
reacquired debt. The new accounting guidance also permits the recording of new
generation-related regulatory assets during the transition period that are
probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to
the application of asset impairment standards to these assets. Using this
guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6
billion (as of June 30, 1998) and recording a regulatory asset on its balance
sheet for the same amount. For this impairment assessment, the fair value of the
investment was calculated by discounting future net cash flows. This
reclassification had no effect on SCE's results of operations.
If during the transition period events were to occur that make the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.4
billion, after tax, at December 31, 1998) as a one-time, non-cash charge against
earnings.
If events occur during the restructuring process that result in all or a portion
of the transition costs 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
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 filed a transmission owners tariff with the FERC, 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.
The transmission owners tariff also sets forth SCE's proposed transmission
access charge. Additionally, on March 31, 1997, SCE filed a wholesale
distribution access tariff. The FERC accepted the tariffs for filing, subject to
refund, effective April 1, 1998.
Regulation
SCE's retail operations are subject to regulation by the CPUC. The CPUC has the
authority to regulate, among other things, retail rates, issuances of
securities, and accounting practices. SCE's wholesale operations are subject to
regulation by the FERC. The FERC has the authority to regulate wholesale rates
as well as other matters, including transmission service pricing, accounting
practices, and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC)
with respect to its nuclear power plants. NRC regulations govern the granting of
licenses for the construction and operation of nuclear power plants and subject
those power plants to continuing review and regulation.
The construction, planning, and siting of SCE's power plants within California
are subject to the jurisdiction of the California Energy Commission and the
CPUC. SCE is subject to the 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
4
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. In September 1998, the CPUC issued a
Resolution accepting certain portions of SCE's compliance plan and rejecting
others. SCE filed a revised compliance plan in October 1998 as ordered. No party
protested that revised plan.
The new affiliate transaction rules apply to all utility transactions, including
electric utilities, with affiliates engaging in the production of products that
use electricity or the providing of services that relate to the use of
electricity. Edison International is not subject to these new affiliate
transaction rules and continues to be subject to the prior rules. The new
affiliate transaction rules are structured to address CPUC concerns regarding
market power and cross-subsidization arising out of the new competitive
electricity market in California. The new rules are categorized into
nondiscrimination standards, disclosure and information standards, and
separation standards. The new rules also set forth requirements and restrictions
on the utility's offering of certain products and services.
The CPUC has modified certain of the rules in response to petitions from various
parties. SCE is still awaiting CPUC decisions on its compliance plan (which
includes SCE's interpretation of the rule governing affiliate use of the
utility's name and logo, on a petition for limited exemptions from that rule,
and on SCE's filing relating to utility products and services that produce other
operating revenue. The CPUC decision concerning the name and logo rule may
affect the disposition of a pending complaint against SCE filed by the CPUC's
Office of Ratepayer Advocates (ORA) and The Utility Reform Network with the
CPUC, which complaint alleges a violation of that rule by Edison Source in a
bulk mailing in 1998.
SCE has not yet been materially affected by the new affiliate transaction rules,
and it projects that the rules will not materially affect its results of
operation or its financial position in the future.
Rate Matters
CPUC Retail Ratemaking
The CPUC regulates the charges for services provided by SCE to its retail
customers. As discussed above in the section on California Electric Utility
Restructuring, 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. In 1998,
these decisions affected cost recovery and rate regulation, and authorized new
ratemaking mechanisms which were implemented,
5
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 have received a 10% reduction from
the June 10, 1996 rate levels beginning on 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. Beginning for rates
effective in 1999, the consolidation of the individual rate component changes
and the calculation of the residual generation rate are set forth for CPUC
approval as part of the Revenue Adjustment Proceeding (RAP). On June 1, 1998,
SCE filed its first annual RAP Report in compliance with Commission directives
to: 1) consolidate authorized rates and revenue requirements associated with
various proceedings and mechanisms; 2) verify the residual CTC revenue
calculation in the Transition Revenue Account; 3) verify the regulatory account
balances which were transferred to the TCBA on January 1, 1998; 4) streamline
certain balancing and memorandum accounts; and 5) review the PX charge/credit
calculation. SCE anticipates a final 1998 RAP decision in the second quarter of
1999.
The CPUC is considering unbundling SCE's cost of capital based on major utility
functions. In May 1998, SCE filed an application on this issue and hearings were
completed in October 1998. A CPUC decision is expected in early to mid 1999.
Distribution Rates
Distribution cost recovery is made 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-1998 Activities" above for additional discussion.)
Transmission Rates
With the commencement of the ISO and PX on March 31, 1998, transmission cost
recovery is now under FERC authority. Prior to such commencement, transmission
cost recovery was combined with distribution cost recovery through a
transmission and distribution PBR mechanism.
Nuclear Decommissioning and Public Purpose Program Rates
Recovery of SCE's nuclear decommissioning costs and legislatively mandated
public purpose program funding is made 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 the ISO and PX operations, generation costs
are 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 the
total rates. This residual revenue will first be 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 (Qualifying Facilities) and interutility contracts and the acceleration of
sunk cost recovery will be subject to annual reasonableness review by the CPUC.
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Transition cost recovery for most utility generation assets will terminate on
the earlier of March 31, 2002, or when these costs are fully collected. (See
"California Electric Utility Restructuring-1998 Activities" above for additional
discussion.)
Annual Transition Cost Proceeding (ATCP)
In 1997, the CPUC established the ATCP as the proceeding to determine whether
SCE's Transition Cost Balancing Account (TCBA) entries are recorded pursuant to
applicable CPUC decisions and AB 1890, and that certain expenses are justified.
This proceeding includes matters that for periods prior to July 1, 1998, were
considered by the CPUC pursuant to ECAC proceedings. (See "Annual Energy Cost
Adjustment Clause Proceedings" below for additional discussion.)
On September 1, 1998, SCE filed its first ATCP Report with the CPUC and
requested that entries made to the TCBA and applicable generation-related
memorandum accounts during the record period of January 1, 1998 through June 30,
1998 be found to be justified and in compliance with applicable Commission
decisions and AB 1890. In addition, SCE requested the Commission to find for the
record period that SCE's: 1) purchased power contract administration is
justified; 2) coal contract costs are justified; 3) gas fuel procurement and
management activities are justified; 4) recorded employee-related costs are
justified; 5) proposal for retaining or eliminating generation-related balancing
and memorandum accounts is justified; and 6) jurisdictional allocation of
transition costs and other generation-related costs should be based upon
recorded kWh. SCE anticipates a final 1998 ATCP decision in December, 1999.
Recovery of Restructuring Implementation Costs
The legislature, recognizing that costs accommodating the implementation of
direct access, the ISO, and the PX would have to be recovered from within the
rates that were frozen at June 1996 levels by other provisions of AB 1890,
provided a mechanism to insure that such recovery could occur without impairing
the utilities' ability to recover their stranded costs from within frozen rates.
This mechanism is contained in Section 376 of the Public Utilities Code. In May
1998, Edison filed an application with the CPUC to identify the categories of
costs which satisfy the conditions of Section 376, and to establish the
reasonableness of those costs incurred in 1997. The CPUC split the application
into two phases. Evidentiary hearings on Phase 1, which addressed the
eligibility of cost categories for recovery pursuant to Section 376, concluded
in November 1998. A proposed decision on Phase 1 was issued by the
administrative law judge (ALJ) on March 11, 1999, accompanied by an alternate
decision drafted by the assigned commissioner in the proceeding. The alternate
decision differs in only minor respects from that of the ALJ. Neither of these
decisions is binding on any party until acted upon by the full CPUC, which may
adopt one or the other of these proposed decisions, modify them, or issue an
entirely new decision. Both of these proposed decisions reject SCE's request for
a determination of eligibility under Section 376 for several major categories of
costs. These proposed decisions further state that even for the cost categories
they approve for Section 376 eligibility, costs incurred in those categories
after December 31, 1998 would not be eligible. Instead, these proposed decisions
would have SCE recover many of the costs identified in its application from
"market revenues," although the decisions fail to identify that market and no
specific mechanism or authority to recover such costs from any market has yet
been established. SCE disagrees with much of the conclusions reached in these
proposed decisions and will file comments to that effect. A final decision from
the CPUC is currently scheduled for April 22, 1999, but may be delayed beyond
that date. Under both of the proposed decisions, the reasonableness of 1997 and
1998 expenditures for eligible costs under Section 376 would be addressed in a
separate application later this year.
Annual Energy Cost Adjustment Clause Proceedings
Ending in 1998, SCE filed ECAC applications each year with the CPUC regarding
its fuel and purchased power expenses, seeking the CPUC's determination that
SCE's fuel and purchased power costs, including payments to QFs, were
reasonable. These matters are respectively referred to herein as "non-QF
matters" and "QF matters."
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QF MATTERS
In a decision issued in September 1998, the CPUC found SCE's administration of
QF contracts and payments to QF projects (hereinafter referred to as "SCE's QF
activities") for the 1992 ECAC to be reasonable. Review of purchases from three
QF projects were deferred because of a pending civil proceeding. The 1992 ECAC
was closed, subject to a petition to reopen or modify the decision regarding the
deferred QF projects.
The 1993 through 1997 ECAC applications were consolidated for purposes of
reviewing QF activities for these years. ORA issued its review in two different
reports in 1998. ORA contested only the reasonableness of SCE's administration
of one QF contract known as the Arbutus project. ORA claimed $3.6 million should
be disallowed from recovery. On January 21, 1999 an administrative law judge
(ALJ) issued a decision finding SCE's actions with respect to the administration
of the Arbutus contract to be reasonable. The ALJ also confirmed a disallowance
of $16.3 million related to the Mojave Cogeneration Company project for the
years 1992 through 1997. On March 4, 1999, the CPUC issued its decision,
upholding the recommendations of the ALJ. Accordingly, SCE will credit its
Electric Deferred Refund Account in the amount of $16.3 million, plus applicable
interest, within 30 calendar days after the effective date of the decision. Any
recovery SCE receives from the Arbutus bankruptcy proceeding will be credited to
SCE's TCBA. This decision closes the 1993, 1994, 1995, 1996, and 1997
Applications, subject to being reopened for the limited purpose of considering
issues related to the three projects deferred from the 1992 ECAC proceeding.
ORA issued its report on the 1998 ECAC period on February 19, 1999. ORA did not
identify any reasonableness issues associated with SCE's QF activities during
the 1998 period.
NON-QF MATTERS
1994 Annual ECAC Record Period
SCE filed its non-QF Reasonableness of Operations Report on May 27, 1994 for the
period April 1, 1993 through March 31, 1994. This report addresses power
purchases and exchanges, and the operation of hydroelectric, coal, gas, and
nuclear resources. The non-QF issues were bifurcated, with the gas procurement
issues being separated from 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.
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 ORA's motion to consolidate the 1994 and
1995 record periods for the limited purpose of addressing the gas reasonableness
issues.
On July 11, 1997, 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.
8
On December 3, 1997, the CPUC issued a decision approving the settlement between
SCE and ORA. On March 12, 1998, the CPUC approved an advice letter ordering SCE
to refund $65 million covering all settlement costs for the 1994, 1995, 1996,
and 1997 ECAC record periods. The settlement has been fully reflected in SCE's
financial statements.
1995 Annual ECAC Record Period
SCE filed its reasonableness of operations testimony on May 26, 1996 for the
period April 1, 1994 through March 31, 1995 addressing 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, 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 for nuclear fuel expenses that were later withdrawn by ORA. SCE and
ORA executed a stipulation on December 18, 1997, subsequently approved by the
CPUC on February 19, 1998, 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.
1997 Annual ECAC Record Period
On May 30, 1997, SCE filed its annual reasonableness report requesting that the
CPUC find reasonable its fuel and purchased-power costs recorded during the
period of April 1, 1996, through March 31, 1997.
ORA's review of the non-QF operations and costs has been consolidated with its
review of the non-QF operations and costs for the 1996 ECAC record period. ORA
filed its report on August 18, 1997. In its report, ORA recommended, among other
things: 1) a disallowance of $360,000 associated with an outage at the
coal-fired Four Corners Generating Station; 2) a $200,000 adjustment to the
costs recorded in SCE's Catastrophic Events Memorandum Account, and 3) a
recommendation that SCE's execution of its natural gas transportation contract
with Southwest Gas Corporation be found unreasonable for purposes of CTC
eligibility. The January 1998 hearings resulted in a CPUC decision issued on
October 22, 1998, adopting the proposed disallowances. The decision found the
execution of the Southwest Gas contract reasonable and therefore, any uneconomic
costs associated with the contract will be subject to CTC recovery. The
remainder of SCE's non-QF costs and expenses were also found reasonable.
On December 21, 1998, SCE filed a petition for modification of the above
decision alleging that it erroneously stated that SCE may seek recovery of its
Nuclear Unit Incentive Procedure (NUIP) rewards in the Revenue Allocation
Proceeding. The CPUC found that SCE's calculation of the NUIP reward was
reasonable and it was an error for the Commission to order another
reasonableness review of these rewards which totaled $15,238,778 plus interest.
The February 18, 1999, CPUC decision granted SCE's petition to modify the 1998
decision and authorized the booking of the NUIP rewards into the TCBA.
1998 Annual ECAC Record Period
On February 19, 1999, ORA issued its Reasonableness Report and made the
following recommendations. ORA found that SCE's costs ($239.1 million) recorded
in the ISO/PX Implementation Delay Memorandum Account (IPDMA) properly reflected
the ISO/PX expenses that accrued during the three month delay in the
commencement of ISO/PX operations. ORA also required SCE to include a showing
that it undertook all practicable steps to minimize the delay with its request
for the recovery of IPDMA costs. ORA found no evidence to show that SCE caused a
delay in the ISO/PX implementation. ORA found that SCE had correctly calculated
its NUIP rewards for Palo Verde Units 2 and 3. The NUIP rewards calculated for
Unit 2 and 3 were $2.5 million and $1.6 million, respectively. ORA recommended
two coal generation related disallowances seeking replacement fuel costs based
on December 1997 outages of Mojave Units 1 and 2 in the amount of $2.4 million,
and a $1.6 million disallowance related to an outage at Four Corners Unit 5. ORA
also recommended disallowances totaling $5.6 million plus interest, to correct
for audit errors. SCE is investigating the facts behind these recommended
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disallowances recommendations and expects to file rebuttal testimony on April
26, 1999. Hearings are scheduled in May 1999.
Palo Verde
In January 1997, the CPUC authorized a further acceleration of the recovery of
SCE's 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 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 the net benefits received from the
operation of Palo Verde equally with ratepayers.
San Onofre Nuclear Generating Station Units 2 and 3
In April 1996, the CPUC authorized a further acceleration of the recovery of
SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The
accelerated recovery will continue through December 2001, earning a 7.35% fixed
rate of return. San Onofre's operating costs, including nuclear fuel, nuclear
fuel financing costs, and incremental capital expenditures, are recovered
through an incentive pricing plan which allows SCE to receive about 4.0(cent)
per kWh through December 31, 2003. Beginning January 1, 1998, the accelerated
plant recovery and incremental cost incentive pricing became part of the CTC
mechanism. Beginning in 2004, SCE will be required to share the net benefits
received from operation of San Onofre Units 2 and 3 equally with ratepayers.
New Accounting Rules
A recently issued accounting rule requires that costs related to start-up
activities be expensed as incurred, effective January 1, 1999. SCE does not
expect this new accounting rule to materially affect its results of operations
or its financial position.
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2000, requires all derivatives to be recognized on the balance sheet at fair
value. Gains or losses from changes in fair value would be recognized in
earnings in the period of change unless the derivative is designated as a
hedging instrument. Gains or losses from hedges of a forecasted transaction or
foreign currency exposure would be reflected in other comprehensive income.
Gains or losses from hedges of a recognized asset or liability, or a firm
commitment would be reflected in earnings for the ineffective portion of the
hedge. SCE anticipates that most of its derivatives under the new standard would
qualify for hedge accounting. SCE expects to recover in rates any market price
changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect
earnings.
Fuel Supply and Purchased Power Costs
Since April 1, 1998, SCE has been required to purchase all power for
distribution to retail customers from the PX. In 1998, fuel and purchased-power
costs, excluding that purchased from the PX, were approximately $3.1 billion,
which was a 20% decrease from the costs in 1997.
SCE's sources of energy during 1998 were as follows: 54% purchased power; 4%
natural gas; 22% nuclear; 13% coal; and 7% hydro.
Average fuel costs, expressed in (cent) per kWh, for the year ended December 31,
1998, were: oil, 6.03(cent); natural gas, 3.06(cent); nuclear, 0.48(cent); and
coal, 1.23(cent).
10
Natural Gas Supply
As a result of the sale of all of its 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 an 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:
Uranium concentrates(*)....................................... 2003
Conversion............................................... 2003
Enrichment............................................... 2003
Fabrication.............................................. 2005
- ---------------
(*) Assumes the San Onofre participants meet their supply obligations in a
timely manner.
Assuming normal operation and full utilization of existing on-site storage
capacity, San Onofre Units 2 and 3 will maintain full-core offload reserve
through 2005. 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 has defaulted on its obligation to begin acceptance of spent nuclear fuel
from the commercial nuclear industry by that date. Additional spent fuel storage
either on-site or at another location will be required to permit continued
operations beyond 2005.
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 1999 from existing contracts. Contracts covering
100% requirements are in place for conversion through 1998, enrichment through
2002, and fabrication through 2016.
Assuming normal operation and regulatory approval for more condensed on-site
spent fuel storage, Palo Verde Units 1, 2, and 3 will maintain full-core offload
reserve until the spring of 2002, fall of 2002, and spring of 2003,
respectively. Arizona Public Service, operating agent for Palo Verde, has
commenced construction of an interim fuel storage facility that it projects will
be completed in 2002.
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.
The CAA as amended in 1990, and as implemented within the South Coast Air
Quality Management District (SCAQMD) and other California districts, required
SCE to reduce emissions of oxides of nitrogen from its generating stations.
During 1998, SCE sold all of its oil- and gas-fueled generating stations
11
within the Mohave Desert Air Quality Management District, Ventura County Air
Pollution Control District, and in the Santa Barbara County Air Pollution
Control District. SCE has sold all but one of its oil- and gas-fired generating
stations within the SCAQMD. The remaining plant, the Pebbly Beach Generating
Station, supplies power to Santa Catalina Island. After the sale of its oil- and
gas-fueled generating stations, SCE commenced operation of the facilities under
operation and maintenance contracts with the individual owners except for two
plants that ceased operation during 1998. SCE will continue to operate or, where
applicable, commence operating those divested facilities as active generating
stations for the required two-year period specified by California's
restructuring statute implementing deregulation of electric utilities in the
state. SCE's operation of the stations under these operation and maintenance
contracts is at the direction and expense of the new owners. SCE is responsible
for maintaining the environmental permits for the plants. The new owners, not
SCE, are responsible for the purchase and installation of emissions control
equipment, and for obtaining trading credits required for the plants under the
Regional Clean Air Incentives Market within the SCAQMD.
The CAA does not require any other significant 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
mid-1999. The EPA and SCE are also expected to conclude a cooperative tracer
study of sulfur dioxide emissions from the Mohave Generating Station (Mohave) in
early 1999. The study is currently evaluating potential impact from Mohave
emissions on haze within the Grand Canyon National Park. On February 19, 1998,
the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court
of Nevada against SCE and the other co-owners of Mohave 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. (See, "Southern California Edison Company-Mohave Generating Station
Environmental Litigation" below for additional discussion.) SCE has asked
Business for Social Responsibility and Environment Now, two well respected
organizations, to convene a collaborative of interested stakeholders to discuss
the best way to resolve this issue. In anticipation of this dialogue, SCE has
proposed to install a dry scrubber, baghouse, and low-NOx burners at Mohave by
2008. This proposal, however, is subject to discussion and modification as part
of the collaborative. 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 required for its projected
operations. Until the collaborative process is completed and a firm requirement
adopted, SCE expects to meet all of the present regulations through improved
operations at Mohave.
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 if required. The study's final
report to Congress concluded that mercury from coal-fired utilities is the
hazardous air pollutant of greatest potential concern and merits additional
research and monitoring to better understand the risks of mercury exposure.
Other pollutants that may potentially need further study are dioxins and arsenic
from coal-fired plants, and nickel from oil-fired plants. The EPA concluded that
the impacts from emissions from gas-fired utilities are negligible and that
there is no need for further evaluation of the risks of hazardous air
pollutants.
Regulations under the Clean Water Act require permits for the discharge of
certain pollutants into U.S waters. 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
more stringent limitations. SCE incurs additional expenses and capital
expenditures in order to comply with guidelines and standards applicable to
steam electric power plants. 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.
12
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. An unresolved
issue remains regarding the degree to which coal wastes should be regulated
under the RCRA. Increased regulation may result in increased expenses relating
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. Current costs for disposal of this substance 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).
SCE's recorded estimated minimum liability to remediate its 49 identified sites
is $171 million. 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 $247 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. SCE has sold all of its gas- and oil-fueled
generation plants and has retained some liability associated with the divested
properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites,
representing $88 million of its recorded liability, through an incentive
mechanism (SCE may ask 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 $141 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of
currently available information, including the nature and magnitude of
contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no
reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$4 million to $10 million. Recorded costs for 1998 were $7 million.
Based on currently available information, SCE believes that 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 its financial position. There is 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.
13
SCE's projected environmental capital expenditures are $900 million for the
1999-2003 period. These expenditures are mainly for aesthetic treatment,
including undergrounding certain transmission and distribution lines.
Year 2000 Issue
Many of SCE's existing computer systems identify a date by using only six digits
instead of eight. If not appropriately addressed, these programs could fail or
create erroneous results when attempting to process information containing dates
after December 31, 1999. This situation has been referred to generally as the
Year 2000 Issue.
SCE has a comprehensive program in place to address potential Year 2000 impacts.
SCE divides Year 2000 activities into five phases: inventory, impact assessment,
remediation, testing, and implementation. Edison International provides overall
coordination of this effort, working with SCE and their business units.
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. Year 2000 readiness
preparations for SCE's mainframe financial systems were completed in the fourth
quarter of 1997, and preparations for SCE's material management system were
completed in the second quarter of 1998. SCE's customer information and billing
system is in the process of being replaced with a system designed to be Year
2000-ready and final conversion activities are expected to be completed by the
first quarter of 1999. SCE's distributed computing assets include operations and
business information systems. SCE's critical operations information systems
include outage management, power management, and plant monitoring and access
retrieval systems. SCE's business information systems include a data acquisition
system for billing, the computer call center support system, credit support, and
maintenance management. SCE's current estimate of the costs to complete these
modifications, including the cost of new hardware and software application
modification, is $72 million, about 40% of which is expected to be capital
costs. SCE's Year 2000 costs expended through December 31, 1998, were $35
million. SCE expects current rate levels for providing electric service to be
sufficient to provide funding for utility-related modifications. 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.
Another aspect of SCE's program involves developing contingency plans. Final
drafts of such plans are expected to be completed by March 1999, with management
approval thereof scheduled for May 1, 1999. These plans will continue to be
revised and enhanced as the year 2000 approaches.
SCE's objectives for the Year 2000 readiness of critical systems was to be 75%
complete by year-end 1998, and to be 100% complete by July 1999. SCE was 80%
complete at year-end 1998 and is on track to meet its July 1999 goal.
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. (See item 7, Management's Discussion and Analysis of Results of
Operations and Financial Condition -- "Year 2000 Issue" below for additional
discussion.)
Item 2. Properties
Existing Generating Facilities
SCE owns and operates one diesel-fueled generating plant located on Santa
Catalina island, 36 hydroelectric plants, and an undivided 75.05% interest
(1,614 MW net) in Units 2 and 3 at San Onofre.
14
These plants are located in Central and Southern California. By the end of 1998,
SCE had sold all 12 of its gas-fueled generating plants.
SCE also owns a 15.8% share of the Palo Verde (579 MW net) Nuclear Generating
Station which is located near Phoenix, Arizona. SCE owns a 48% undivided
interest (754 MW) in Units 4 and 5 at the Four Corners Generating Station, which
is a coal-fueled steam electric generating plant located in New Mexico. Palo
Verde and Four Corners are operated by other utilities. SCE operates and owns a
56% undivided interest (885 MW) in the Mohave Generating Station, which consists
of two coal-fueled steam electric generating units in Clark County, Nevada. At
year-end 1998, the existing SCE-owned generating capacity (summer effective
rating) was divided approximately as follows: 43.9% nuclear, 32.8% coal, 23.1%
hydroelectric, and 0.2% 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
U. S. 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.
The 36 hydroelectric plants, some with related reservoirs, currently having an
effective operating capacity of 1,156 MW, and are, with five exceptions, located
in whole or in part on lands of the U.S. pursuant to, 30 to 50 year governmental
licenses that expire at various times between 1998 and 2026. Such licenses
impose numerous restrictions and obligations on SCE, including the right of the
United States to acquire projects 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 with an aggregate effective operating capacity of 115.57
MW are pending. The SCE hydroelectric projects that are undergoing relicensing
and whose long-term licenses have expired, have been issued annual licenses,
which will be renewed until the new licenses are issued.
In 1998, SCE's peak demand was 19,935 MW, set on August 31, 1998. 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
$2.5 billion in principal amount was outstanding on December 31, 1998. 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, affect 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.
SCE's rights in the Four Corners Project, which is located on land of The Navajo
Nation of Indians under an easement from the U. S. 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.
15
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $861 million in 1998,
and $685 million in 1997 and $616 million in 1996. Construction expenditures for
the 1999-2003 period are forecasted at $3.9 billion.
In addition to cash required for construction expenditures for the next five
years as discussed above, $2.4 billion is needed to meet requirements for
long-term debt maturities and sinking fund redemption requirements.
SCE's estimates of cash available for operations for the five years through 2003
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.
In 1996, the CPUC adopted SCE's San Onofre Unit 2 and 3 proposal under which SCE
would have recovered its remaining investment in these San Onofre Units 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. AB
1890, however, requires the recovery of the San Onofre investment to 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 pay a preset price for each kWh of energy
generated at San Onofre during the eight-year period. AB 1890 allows for the
continuation of the incentive pricing plan through December 31, 2003. SCE was
compensated for the incremental costs required for the continued operation of
San Onofre Units 2 and 3 with revenue earned through the incentive pricing plan.
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 will not
generate power through ECAC filings and, beginning in 1998, as part of ATCP. AB
1890 also allows SCE to 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 San Diego Gas & Electric's (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 1996, SCE filed its Palo Verde Proposal Application requesting adoption of a
new rate mechanism for Palo Verde consistent with that of San Onofre Units 2 and
3. On November 15, 1996, SCE, ORA, and TURN entered into a settlement agreement,
which was approved by the CPUC on December 20, 1996, regarding SCE's Palo Verde
Proposal Application which now allows SCE 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. The settling parties agreed that SCE would recover its
share of Palo Verde
16
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 which
case, SCE must demonstrate that the aggregate amount of the costs exceeding the
forecast in that year are reasonable. 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.
Beginning in 2002, the benefits of future operation of Palo Verde Units 1, 2,
and 3 will be shared equally between shareholders and customers. Likewise,
beginning in 2004, the benefits of future operation of San Onofre Units 2 and 3
will be shared equally between shareholders and 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. On December 21, 1998, SCE filed an application with the CPUC requesting
authorization to access its Nuclear Decommissioning Trust Funds for Unit 1 for
the purpose of commencing decommissioning of Unit 1 in 2000.
The Units 2 and 3 steam generators have performed relatively well through the
first 15 years of operation, with low rates of ongoing steam generator tube
degradation. During the Unit 2 scheduled refueling and inspection outage, which
was completed in 1997, an increased rate of degradation was identified, which
resulted in the removal of more tubes from service than had been expected. The
present design analysis, which is being reviewed for a potential increase,
allows for the removal of up to 10% of the steam generator tubes before the
unit's capacity must be re-evaluated. As a result of the increased degradation,
a mid-cycle outage was conducted in early 1998 for Unit 2. Continued degradation
was found during this inspection. A favorable (decreasing) trend in degradation
was observed during inspection in the scheduled refueling outage in January
1999. The results of the January 1999 inspection are being analyzed to determine
if there is a need for a mid-cycle inspection outage in early 2000. With the
results from the January 1999 outage, 7.5% of the tubes have now been removed
from service. In September 1998, San Onofre Unit 2 experienced a small amount of
leakage from a steam generator tube plug, which required an 11-day outage to
repair.
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. A follow-up mid-cycle inspection indicated that the
erosion had been stabilized. Additional monitoring inspections are planned
during the next scheduled refueling outage in 1999. To date, 5% of Unit 3's
tubes have been removed from service.
During Unit 2's February 1998 mid-cycle outage, similar tube supports showed no
significant levels of such erosion.
Palo Verde Nuclear Generating Station
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 that it will be economically desirable to replace the Unit 2 steam
generators, which have been most affected by tube cracking, in four to nine
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
17
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.
During 1998, Palo Verde Nuclear Generating Station generated 30 billion kWh of
electricity. It was the first time an American power plant of any kind crossed
the 30-billion-kilowatt-hour threshold in a single year. Palo Verde broke its
own record of 29.5 billion kWh that it set in 1997 and was the nation's top
power producer for the fourth consecutive year. The year-end station capacity
factor was 92.5%. Units 1 and 3 were each refueled in 36-day outages - a site
record. Unit 2 operated on-line the entire year and at year's end had operated
continuously for 430 days.
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. On December 21, 1998, SCE filed an
application with the CPUC requesting the authority to access its decommissioning
trust funds for San Onofre Unit 1 for the purpose of decommissioning commencing
in 2000. Decommissioning is estimated to cost $1.9 billion in current-year
dollars based on site-specific studies performed in 1998 for San Onofre and 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 2000 at San Onofre Unit
1. SCE expects decommissioning San Onofre Units 2 and 3 and Palo Verde to occur
after its generating licenses expire in 2013 and 2024 respectively.
Decommissioning expense was $164 million in 1998 and $154 million in 1997. The
accumulated provision for decommissioning was $1.2 billion at December 31, 1998,
and $1.1 billion at December 31, 1997. The estimated costs to decommission San
Onofre Unit 1 ($368 million in 1998 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 $9.8
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
$88 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 $175 million per nuclear incident. SCE,
however, 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
18
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 $22 million per year.
Insurance premiums are charged to operating expense.
Item 3. Legal Proceedings
Wind Generators' Litigation
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 alleged that SCE incorrectly interpreted contracts with the
plaintiffs by limiting fixed energy payments to a single ten-year period rather
than beginning a new ten-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 sought declaratory relief
regarding the proper interpretation of the contracts. Plaintiffs alleged a
combined total of approximately $189 million in damages, which included
consequential damages claimed in seven of the eight lawsuits. A ninth lawsuit
was subsequently filed in Los Angeles County raising claims similar to those
alleged in the first eight. SCE responded to the complaint in the new lawsuit by
denying its material allegations.
After receiving a favorable decision in the liability phase of the lead case,
SCE agreed to settle with the plaintiffs in seven of the lawsuits on terms
whereby SCE waived its rights to recover costs against such plaintiffs in
exchange for their agreement that there is only one fixed price period under
each of their power purchase contracts with SCE and a mutual dismissal with
prejudice of claims. SCE also entered into a settlement agreement with the
plaintiff in another of the lawsuits which resolved the issue of multiple fixed
price periods on the same terms and which also resolved a related issue unique
to that plaintiff in exchange for a nominal payment by SCE. This settlement was
approved by the bankruptcy court in proceedings involving the plaintiff. On
January 28, 1999, SCE finalized a settlement with the remaining plaintiffs on
terms effectively the same as those in the initial group of settlements except
that the settlement agreement also resolved, on terms favorable to SCE, certain
claims which SCE had asserted in the lead case by way of cross-complaint.
Geothermal Generators' Litigation
On June 9, 1997, SCE filed a complaint in Los Angeles County Superior Court
against an independent power producer of geothermal generation and six of its
affiliated entities (Coso parties). SCE alleges that in order to avoid power
production plant shutdowns caused by excessive noncondensable gas in the
geothermal field brine, the Coso parties 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 Coso parties of their obligations under their contracts with SCE
and applicable law. The complaint sought termination of the contracts and
damages for excess power purchase payments made to the Coso parties. The Coso
parties' motion to transfer venue to Inyo County Superior Court was granted on
August 31, 1997. On June 1, 1998, the court struck SCE's request for termination
of the contracts, leaving SCE with its claim for damages and other relief. On
February 16, 1999, the court denied the Coso Parties' motion for judgment on the
pleadings directed to SCE's first amended complaint.
The Coso parties have also asserted various claims against SCE, The Mission
Group, and Mission Power Engineering Company (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 Coso parties in Inyo County Superior Court. In
November 1997, the court struck all but two causes of action asserted in the
separate action on the grounds that they should have been raised as part of the
Coso parties' cross-complaint, and ordered the remaining two causes of action
consolidated for all purposes with the action filed by SCE.
19
The Coso parties subsequently filed second and third amended cross-complaints.
The third amended cross-complaint names SCE, the Mission parties, and Edison
International. As against SCE, the third amended cross-complaint purports causes
of action for declaratory relief, breach of the covenant of good faith and fair
dealing; inducing breach of agreements between the Coso parties and their former
employees; breach of an earlier settlement agreement between the Mission parties
and the Coso parties; slander and disparagement, injunctive relief and
restitution for unfair business practices; anticipatory breach of the contracts;
and violations of Public Utilities Code ss.ss. 453, 702 and 2106. As against the
Mission parties, the third amended cross-complaint seeks damages for breach of
warranty of authority with respect to the settlement agreement, and for
equitable indemnity. The Coso parties voluntarily dismissed Edison International
from the third amended cross-complaint on December 4, 1998. As against SCE, the
third amended cross-complaint seeks restitution, compensatory damages in excess
of $115 million, punitive damages in an amount not less than $400 million,
interest, attorney's fees, declaratory relief, and injunctive relief.
On September 21, 1998, SCE filed an answer to the third amended cross-complaint
generally denying the allegations contained therein and asserting affirmative
defenses. In addition, SCE filed a cross-complaint for reformation of the
contracts alleging that if they are not susceptible to SCE's interpretation,
they should be reformed to reflect the parties' true intention. The Coso
defendants demurred to SCE's cross-complaint and, in January 1999, their
demurrer was sustained with leave to amend. In light of this new ruling, SCE
recently filed an amended cross-complaint for reformation.
Following various pre-trial motions filed by the Mission parties and Edison
International, the Coso Parties, on December 23, 1998, purported to file a
fourth amended cross-complaint against the Mission Parties only. The Mission
Parties' demurrer to and motion to strike directed to the fourth amended
cross-complaint was heard and taken under submission on March 10, 1999.
On December 15, 1998, the Court granted the Coso parties leave to file a second
amended complaint in the separately filed (now consolidated) action. The second
amended complaint which names SCE and Edison International, alleges that SCE
engaged in anti-competitive conduct, false advertising, and conduct proscribed
by Public Utilities Code ss. 2106, and seeks injunctive relief, restitution, and
punitive damages. On January 20, 1999, SCE filed three motions to strike several
portions of the second amended complaint on the grounds, among others, that the
CPUC or FERC have either exclusive or primary jurisdiction over the matters
asserted therein, and that SCE's alleged conduct was in furtherance of
constitutionally protected rights of free speech and petition and therefore not
actionable. These matters were heard on February 22, 1999, and taken under
submission at that time.
Discovery and motion practice related to discovery is active. The Court has set
a trial date of March 1, 2000. 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 lawsuits alleging that various plaintiffs developed cancer as
a result of exposure to EMF from SCE facilities.
In December 1995, the court granted SCE's motion for summary judgment in the
first lawsuit and dismissed the case. Plaintiffs filed a notice of appeal.
Following a settlement conference ordered by the Court of Appeal, the case was
dismissed in January 1999.
Following dismissal of the second lawsuit by the plaintiffs, a wrongful death
action was filed by the husband and children of one of the original plaintiffs
who had subsequently died. This wrongful death action was dismissed by the court
without leave to amend on September 16, 1998. Plaintiffs' appeal in the wrongful
death action was dismissed following a settlement conference in the Court of
Appeal in January 1999.
20
San Onofre Personal Injury Litigation
SCE is actively involved in three lawsuits claiming personal injuries allegedly
resulting from exposure to radiation at San Onofre. 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 and the Institute of Nuclear Power Operations as
defendants. All trial court proceedings have been stayed pending ruling of the
Ninth Circuit Court of Appeal, on an appeal of a lower court's judgment in favor
of SCE in two earlier cases raising similar allegations. On May 28, 1998, the
Court of Appeal affirmed these judgments. A trial date has not yet been set.
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 trial in this case resulted in a jury verdict for both
defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed
an appeal of the trial court's judgment to the Ninth Circuit Court of Appeal.
Briefing on the appeal was completed in January 1999 and the parties are
awaiting a date for oral argument to be set by the court. A decision is not
expected until early 2000.
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. On August 12, 1996,
the Court dismissed the claims of the former worker and her husband with
prejudice. This case, with only the son as plaintiff, is expected to go to trial
in late 1999.
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 case was
removed to the U.S. District Court for the Southern District of California. On
May 11, 1998, the plaintiffs filed a first amended complaint. On May 22, 1998,
SCE filed an answer denying the material allegations of the first amended
complaint. Pursuant to a stipulation of the parties, the court, on January 4,
1999, dismissed the plaintiffs' complaint in this matter with prejudice.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the
cases at the U.S. District Court level to stay trial pending the results of the
case currently before the Ninth Circuit Court of Appeal. The parties agreed that
if the plaintiffs/petitioners do not receive a favorable determination on appeal
then the two cases at the District Court level will be dismissed. If, however,
the plaintiffs/petitioners receive a favorable determination on appeal, then the
two District Court cases will be set for trial.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although, as indicated
above, SCE was successful in removing itself from those actions, the impact on
SCE, if any, from further proceedings in these cases against the remaining
defendants can not be determined at this time.
Mohave Generating Station Environmental Litigation
On February 19, 1997, the Sierra Club and the Grand Canyon Trust filed suit in
the U.S. District Court of Nevada against SCE and the other three co-owners of
Mohave Generating Station. The lawsuit alleges that Mohave has been violating
various provisions of the CAA, the Nevada state implementation plan, certain EPA
orders, and applicable pollution permits relating to opacity and sulfur dioxide
emission limits over the last five years. The plaintiffs seek declaratory and
injunctive relief as well as civil penalties. Under the CAA, the maximum civil
penalty obtainable is $25,000 per day per violation. SCE and the co-owners
obtained an extension to respond to the complaint pending the court's ruling on
a motion to dismiss filed by the defendants.
On June 4, 1998, the plaintiffs served SCE and its co-owners with a 60-day
supplemental notice of intent to sue. This supplemental notice identified
additional causes of action as well as an additional plaintiff (National Parks
and Conservation Association) to be added to the proceedings. On November 12,
1998, the court bifurcated the liability and damage phases of the case.
21
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
Executive Officer December 31, 1998 Company Position
- ------------------------------------ ------------------------- -------------------------------------------------------
John E. Bryson 55 Chairman of the Board, Chief Executive Officer and
Director
Stephen E. Frank 57 President, Chief Operating Officer and Director
Bryant C. Danner 61 Executive Vice President and General Counsel
Alan J. Fohrer 48 Executive Vice President and Chief Financial Officer
Harold B. Ray 58 Executive Vice President, Generation Business Unit
Pamela A. Bass 51 Senior Vice President, Customer Service Business Unit
Theodore F. Craver, Jr. 47 Senior Vice President and Treasurer
John R. Fielder 53 Senior Vice President, Regulatory Policy and Affairs
Robert G. Foster 51 Senior Vice President, Public Affairs
Lillian R. Gorman 45 Senior Vice President, Human Resources
Richard M. Rosenblum 48 Senior Vice President, T&D Business Unit
Bruce C. Foster 46 Vice President, San Francisco Regulatory Affairs
Thomas J. Higgins 53 Vice President, Corporate Communications
Thomas M. Noonan(2) 47 Vice President and Controller
Anthony L. Smith 50 Vice President, Tax
- --------------
(1) Executive Officers are defined by Rule 3b-7 of the General Rules and
Regulations under the Securities Exchange Act of 1934, as amended.
Executive Officers, Bryson, Danner, Fohrer, Craver, Robert Foster, Gorman,
Higgins, Noonan and Smith hold the same positions with Edison
International. Edison International is the parent holding company of SCE.
(2) Richard K. Bushey resigned as Vice President and Controller of SCE
effective March 1, 1999.
None of SCE's executive officers are related to each other by blood or
marriage. As set forth in Article IV of SCE's Bylaws, the officers of SCE
are chosen annually by and serve at the pleasure of SCE's Board of
Directors and hold their respective offices until their resignation,
removal, other disqualification from service, or until their respective
successors are elected. All of the executive officers have been actively
engaged in the business of SCE for more than five years except for
Stephen E. Frank, Theodore F. Craver, Jr., Lillian R. Gorman, and Thomas
J. Higgins. Those
22
officers who have not held their present position for the past five years
had the following business experience.
Executive Officer Company Position Effective Dates
- -------------------------------- ---------------------------------------------- ----------------------------------------
Stephen E. Frank President, Chief Operating Officer and June 1995 to present
Director
President and Chief Operating Officer, August 1990 to January 1995
Florida Power and Light Company(1)
Bryant C. Danner Executive Vice President and General Counsel June 1995 to present
Senior Vice President and General Counsel July 1992 to May 1995
Alan J. Fohrer Executive Vice President and Chief Financial September 1996 to present
Officer
Executive Vice President, Chief Financial February 1996 to August 1996
Officer and Treasurer
Executive Vice President and Chief Financial May 1995 to January 1996
Officer
Senior Vice President and Chief Financial January 1993 to April 1995
Officer
Harold B. Ray Executive Vice President, Generation June 1, 1995 to present
Business Unit
Senior Vice President, Power Systems June 1990 to May 1995
Pamela A. Bass Senior Vice President, Customer Service March 1999 to present
Business Unit
Vice President, Customer Solutions Business June 1996 to February 1999
Unit
Vice President, Shared Services January 1996 to May 1996
Division Vice President, ENvest August 1993 to December 1995
Theodore F. Craver, Jr. Senior Vice President and Treasurer February 1998 to present
Vice President and Treasurer September 1996 to February 1998
Executive Vice President and Corporate September 1990 to August 1996
Treasurer, First Interstate Bancorp(1)
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present
Affairs
Vice President, Regulatory Policy and Public February 1992 to January 1998
Affairs
Robert G. Foster Senior Vice President, Public Affairs November 1996 to present
Vice President, Public Affairs November 1993 to October 1996
Lillian R. Gorman Senior Vice President, Human Resources March 1999 to present
Vice President, Human Resources July 1996 to February 1999
Executive Vice President and Human Resources October 1990 to May 1996
Director, First Interstate Bancorp(1)
Richard M. Rosenblum Senior Vice President, T&D Business Unit February 1998 to present
Vice President, Distribution Business Unit January 1996 to January 1998
Vice President, Nuclear Engineering and June 1993 to December 1995
Technical Services
23
Bruce C. Foster Vice President, San Francisco January 1995 to present
Regulatory Affairs
Regional Vice President, San Francisco Office January 1992 to December 1994
Thomas J. Higgins Vice President, Corporate Communications April 1995 to present
Vice President, Corporate Communications April 1995 to January 1996
President, The Laurel Company(1)(2) January 1994 to December 1994
Thomas M. Noonan Vice President and Controller March 1999 to present
Assistant Controller September 1993 to February 1999
Anthony L. Smith Vice President, Tax March 1999 to present
Assistant Controller January 1998 to February 1999
(1) This entity is not a parent, subsidiary or other affiliate of SCE.
(2) As President of The Laurel Company, Thomas J. Higgins provided advice on
planning and financing for mergers and acquisitions for clients in the
managed health care business.
24
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Certain information responding to Item 5 with respect to frequency and amount of
cash dividends is included in SCE's Annual Report to Shareholders for the year
ended December 31, 1998, (Annual Report) under "Quarterly Financial Data" on
page 35 and is incorporated by reference pursuant to General Instruction G(2).
As a result of the formation of a holding company described above in Item 1, all
of the issued and outstanding common stock of SCE is owned by Edison
International and there is no market for such stock.
Item 6. Selected Financial Data
Information responding to Item 6 is included in the Annual Report under
"Selected Financial and Operating Data: 1994-1998 on page 38 and is incorporated
herein by reference pursuant to General Instruction G(2).
Item 7. Management's Discussion and Analysis of Results of Operations and
Financial Condition
Information responding to Item 7 is included in the Annual Report under
"Management's Discussion and Analysis of Results of Operations and Financial
Condition" on pages 1 through 12 and is incorporated herein by reference
pursuant to General Instruction G(2).
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 7A is included in the Annual Report under
"Management's Discussion and Analysis of Results of Operations and Financial
Condition" on pages 4 through 5 and is incorporated herein by reference to
General Instruction G(2).
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in Part IV.
Other information responding to Item 8 is included in the Annual Report on pages
13 through 35, and is incorporated herein by reference pursuant to General
Instruction G(2).
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information concerning executive officers of SCE is set forth in Part I in
accordance with General Instruction G(3), pursuant to Instruction 3 to Item
401(b) of Regulation S-K. Other information responding to Item 10 is included in
the Joint Proxy Statement (Proxy Statement) filed with the Commission in
connection with SCE's Annual Meeting to be held on April 15, 1999, under the
heading, "Election of Directors of Edison International and SCE" on pages 4
through 7 and "Section 16(a) Beneficial Ownership Reporting Compliance" on page
23, and is incorporated herein by reference pursuant to General Instruction
G(3).
25
Item 11. Executive Compensation
Information responding to Item 11 is included in the Proxy Statement beginning
with the section under the heading "Executive Compensation Table - Edison
International and SCE" on pages 10 through 22, and is incorporated herein by
reference pursuant to General Instruction G(3).
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information responding to Item 12 is included in the Proxy Statement under the
headings "Stock Ownership of Directors and Executive Officers of Edison
International and SCE" on pages 8 through 9 and "Stock Ownership of Certain
Shareholders" on page 26, and is incorporated herein by reference pursuant to
General Instruction G(3).
Item 13. Certain Relationships and Related Transactions
Information responding to Item 13 is included in the Proxy Statement under the
heading "Certain Relationships and Transactions of Nominees and Executive
Officers" on page 23 and is incorporated herein by reference pursuant to General
Instruction G(3).
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) (1) Financial Statements
The following items contained in the 1998 Annual Report to Shareholders are
incorporated by reference in this report.
Management's Discussion and Analysis of Results of Operations and
Financial Condition
Consolidated Statements of Income -- Years Ended December 31, 1998,
1997 and 1996
Consolidated Statements of Retained Earnings -- Years Ended December 31,
1998, 1997 and 1996
Consolidated Balance Sheets -- December 31, 1998, and 1997
Consolidated Statements of Cash Flows -- Years Ended December 31, 1998,
1997 and 1996
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(2) Report of Independent Public Accountants and Schedules
Supplementing Financial Statements
The following documents may be found in this report at the indicated page
numbers.
Page
Report of Independent Public Accountants on Supplemental
Schedules 30
Schedule II--Valuation and Qualifying Accounts for the Years
Ended December 31, 1997, 1996 and 1995 31
26
Schedules I through V, inclusive, except those referred to above, are omitted as
not required or not applicable.
(3) Exhibits
See Exhibit Index on page 35 of this report.
(b) Reports on Form 8-K
November 13, 1998
Item 5: Other Events Proposition 9
27
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited in accordance with generally accepted auditing standards, the
consolidated financial statements included in the 1998 Annual Report to
Shareholders of Southern California Edison Company (SCE) incorporated by
reference in this Form 10-K, and have issued our report thereon dated February
4, 1999. Our audits of the consolidated financial statements were made for the
purpose of forming an opinion on those basic consolidated financial statements
taken as a whole. The supplemental schedules listed in Part IV of this Form
10-K, which are the responsibility of SCE's management, are presented for
purposes of complying with the Securities and Exchange Commission's rules and
regulations, and are not part of the basic consolidated financial statements.
These supplemental schedules have been subjected to the auditing procedures
applied in the audits of the basic consolidated financial statements and, in our
opinion, fairly state in all material respects the financial data required to be
set forth therein in relation to the basic consolidated financial statements
taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
February 4, 1999
28
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1998
Additions
---------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
(In thousands)
- ---------------------------------------------------------------------------------------------------------------
Group A:
Uncollectible accounts--
Customers $ 24,245 $ 19,808 -- $ 24,457 $ 19,596
All other 2,208 2,273 -- 1,847 2,634
----------- ----------- --------- ----------- -----------
Total $ 26,453 $ 22,081 -- $ 26,304 (a) $ 22,230
======= ======= ====== ======= =======
Group B:
DOE Decontamination
and Decommissioning $ 44,336 -- $ (89) (b) $ 4,828 (c) $ 39,419
Purchased-power settlements 145,640 -- - 15,943 (d) 129,697
Pension and benefits 211,200 $170,743 18,988 (e) 161,263 (f) 239,668
Insurance, casualty and
other 78,461 69,275 -- 74,487 (g) 73,249
----------- ---------- ----------- ----------- -----------
Total $479,637 $240,018 $ 18,899 $256,521 $482,033
======= ======= ======= ======== =======
- -----------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(e) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(f) Includes pension payments to retired employees, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(g) Amounts charged to operations that were not covered by insurance.
29
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1997
Additions
---------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
(In thousands)
- ---------------------------------------------------------------------------------------------------------------
Group A:
Uncollectible accounts--
Customers $ 24,390 $ 20,597 -- $ 20,742 $ 24,245
All other 1,689 1,180 -- 661 2,208
----------- ----------- --------- ----------- -----------
Total $ 26,079 $ 21,777 -- $ 21,403(a) $ 26,453
======= ======= ====== ======= =======
Group B:
DOE Decontamination
and Decommissioning $ 48,789 -- $ 1,089(b) $ 5,542(c) $ 44,336
Purchased-power settlements 107,700 -- 67,320(d) 29,380(e) 145,640
Pension and benefits 180,927 $102,193 17,624(f) 89,544(g) 211,200
Insurance, casualty and
other 86,509 57,749 -- 65,797(h) 78,461
----------- ---------- ----------- ----------- -----------
Total $423,925 $159,942 $ 86,033 $190,263 $479,637
======= ======= ======= ======== =======
- -----------
(a) Accounts written off, net.
(b) Represents revision to estimate based on actual billings.
(c) Represents amounts paid.
(d) Represents additional payments to be made under agreements to
terminate purchased-power contract.
(e) Represents the amortization of the liability established for
purchased-power contract settlement agreements.
(f) Primarily represents transfers from the accrued paid absence allowance
account for required additions to the comprehensive disability plan
accounts.
(g) Includes pension payments to retired employees, amou