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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, 1999
------------------------------------------------------
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 no,
(Address of principal executive offices) (Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Capital Stock
Cumulative Preferred American and Pacific
4.08% Series 4.32% Series
4.24% Series 4.78% Series
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of March 27, 2000, there were 434,888,104 shares of Common Stock outstanding,
all of which are held by the registrant's parent holding company. The aggregate
market value of registrant's voting stock held by non-affiliates was
approximately $330,110,425.50 on or about March 27, 2000, 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 27, 2000, were as
follows: CUMULATIVE PREFERRED STOCK $74,410,425.50; $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, 1999.................................... Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 2000 Annual Meeting
of Shareholders...................................... Part III
TABLE OF CONTENTS
Item Page
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Part I
1. Business............................................................................................. 1
Forward-Looking Statements...................................................................... 1
Competitive Environment......................................................................... 2
Regulation ..................................................................................... 2
Changing Regulatory Environment................................................................. 4
Other Rate Matters.............................................................................. 7
Fuel Supply and Purchased Power Costs........................................................... 12
Environmental Matters........................................................................... 12
Year 2000 Issue................................................................................. 15
2. Properties........................................................................................... 15
Existing Generating Facilities.................................................................. 15
Construction Program and Capital Expenditures................................................... 17
Nuclear Power Matters........................................................................... 17
3. Legal Proceedings.................................................................................... 20
Geothermal Generators' Litigation............................................................... 20
San Onofre Personal Injury Litigation........................................................... 20
Mohave Generating Station Environmental Litigation.............................................. 21
Navajo Nation Litigation........................................................................ 22
Claims Arising from Oil Spill Incidents......................................................... 22
4. Submission of Matters to a Vote of Security Holders.................................................. 23
Executive Officers of the Registrant................................................................. 23
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 Reports on Form 8-K
Financial Statements............................................................................ 26
Report of Independent Public Accountants and Schedules Supplementing Financial Statements....... 26
Exhibits ....................................................................................... 27
Reports on Form 8-K............................................................................. 27
Signatures...................................................................................... 32
PART I
Item 1. Business
Southern California Edison Company (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. The SCE service territory includes approximately 800 cities and
communities and a population of more than 11 million people. Beginning in April
1998, pursuant to the restructuring of the California electric utility industry
mandated by a 1996 state law, other entities have had the ability to sell
electricity in SCE's service territory, utilizing SCE's transmission and
distribution lines at tariffed rates. As a part of this utility industry
restructuring, SCE sold some of its electric generating plants in 1998. SCE
currently retains other electric generating plants, however, and it retains its
transmission and distribution lines over which it transmits and distributes the
electricity generated by SCE and other generators to the customers in SCE's
service territory. As a further part of the industry restructuring, SCE is
required for an interim transitional period (ending no later than year-end 2001)
to sell all SCE-generated electricity to the California Power Exchange (PX) at
prices determined by periodic public auctions, and SCE is required to buy any
electricity needed to serve SCE's retail customers from the PX at similarly
determined prices. In 1999, SCE's total operating revenue was derived from:
37.1% residential customers, 38.5% commercial customers, 9.8% industrial
customers, 7.1% public authorities, 1.5% agricultural and other customers, and
6.0% other electric revenue. SCE had 13,040 full-time employees at year-end
1999. SCE comprises the largest portion of the assets and revenue of its parent
holding company, Edison International.
Forward-Looking Statements
This annual report contains forward-looking statements that reflect SCE's
current expectations and projections about future events based on SCE's
knowledge of present facts and circumstances and assumptions about future
events. Other information distributed by SCE that is incorporated herein or
refers to or incorporates this annual report may also contain forward-looking
statements. In this annual report and elsewhere, the words "expects,"
"believes," "anticipates," "estimates," "intends," "plans," and variations of
such words and similar expressions are intended to identify forward-looking
statements. Such statements necessarily involve risks and uncertainties that
could cause actual results to differ materially from those anticipated. Some of
the risks, uncertainties and other important factors that could cause results to
differ are:
o Actions of federal and state regulatory bodies setting rates and
implementing the restructuring of the electric utility industry, including,
for example, regulatory actions in California that could affect SCE's
ability to recover its past investments in utility plant and earn
competitive returns.
o The effects of new laws and regulations relating to restructuring and other
matters, such as pending federal legislation that would repeal or amend key
statutes governing the electric industry.
o The effects of increased competition in the electric utility business and
other energy-related businesses, including among other things the ability
of customers to purchase energy and metering and billing services from
nonutility energy service providers.
o Unpredictable weather conditions that may affect seasonal patterns of
revenue collection, cause changes in demand (and prices) for electricity
for heating and cooling purposes, and result in higher costs for repair or
maintenance of assets.
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o The values and other terms under which SCE is able either to sell or retain
electric generation assets, and the associated ratemaking treatment.
o Financial market conditions such as inflation and changes in interest
rates, which could affect the availability and cost of external financing.
o Power plant operation risks, including strikes, equipment failures and
other issues.
o The effects of changes in tax laws, or unfavorable interpretation and
application of the laws by tax authorities.
o New or increased environmental liabilities associated with power plants and
other facilities or operations, resulting from changes in laws, accidents
or other events.
o The ability of SCE to create and expand new businesses, such as
telecommunications and other energy-related consumer products and services,
and to operate such businesses profitably.
o Legal proceedings arising out of commercial disputes, property rights,
personal injuries, and other circumstances.
Additional information about the risk factors listed above is contained
throughout this annual report. Readers are urged to read this entire report and
carefully consider the risks, uncertainties and other factors that affect SCE's
business. The information contained in this report is subject to change without
notice. Readers should review future reports filed by SCE with the Securities
and Exchange Commission (SEC).
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 -- Changing
Regulatory Environment" below for a description of these changes.)
Regulation
SCE's retail operations are subject to regulation by the California Public
Utilities Commission (CPUC). The CPUC has the authority to regulate, among other
things, retail rates, issuance of securities, and accounting practices. SCE's
wholesale operations are subject to regulation by the Federal Energy Regulatory
Commission (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's transmission operations, including other generators' rights of access to
SCE's transmission lines, also are subject to regulation by the California
Independent System Operator (ISO), an entity that was created by the California
restructuring legislation in 1996 and went into operation in 1998. The 1996
restructuring legislation also created the PX, a non-profit entity that conducts
frequent electronic auctions of electricity. During an interim transitional
period (ending no later than year-end 2001), SCE is required by CPUC order to
sell all SCE-generated electricity to the PX and to purchase power needed for
retail customers from the PX.
2
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 handling
and disposal of hazardous materials and wastes. SCE is also subject to
regulation by the Environmental Protection Agency (EPA), which administers
certain federal statutes relating to environmental matters. Other federal,
state, and local laws and regulations relating to environmental protection, land
use, and water rights also affect SCE.
The California Coastal Commission has continuing jurisdiction over the coastal
permit for San Onofre Nuclear Generating Station Units 2 and 3. Although the
units are operating, the permit's mitigation requirements have not yet been
completed. California Coastal Commission jurisdiction may continue for several
years due to implementation and oversight of permit mitigation conditions,
including restoration of wetlands and construction of an artificial reef for
kelp.
The Department of Energy has regulatory authority over certain aspects of SCE's
operations and business relating to energy conservation, power plant fuel use
and disposal, 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). 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 (TURN)
with the CPUC, which 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 expects that the rules will not materially affect its results of
operation or its financial position in the future.
3
Changing Regulatory Environment
SCE's regulatory environment is changing as a result of a 1995 CPUC decision on
restructuring and state legislation enacted in 1996. The state legislation,
California Assembly Bill 1890 as amended by California Senate Bill 477 (the
restructuring legislation) 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
generation-related assets. The restructuring legislation also included
provisions to finance a portion of the stranded costs that residential and small
commercial customers would have paid between 1998 and 2001, which allowed SCE to
reduce rates by at least 10% to these customers, effective January 1, 1998. The
restructuring legislation mandated other rates to remain frozen at June 1996
levels (system average of 10.1(cent) per kilowatt-hour), including those for
large commercial and industrial customers, and included provisions for continued
funding for energy conservation, low-income programs and renewable resources.
Despite the rate freeze, SCE expects to be able to recover its revenue
requirement during the 1998--2001 transition period. In addition, the
restructuring legislation mandated the implementation of the competition
transition charge (CTC) (see the detailed discussion in "Revenue and
Cost-Recovery Mechanisms" below) that provides utilities the opportunity to
recover costs made uneconomic by electric utility restructuring.
Rate Reduction Notes
In December 1997, after receiving approval from 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
scheduled maturities ranging from less than one year to eight years, with
interest rates ranging from 6.14% to 6.42%.
Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation.
Revenue related to distribution operations is being determined through a
performance-based rate-making mechanism (PBR) and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend 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 customer satisfaction; service reliability and safety; and a net
revenue-sharing mechanism that determines how customers and shareholders will
share gains and losses from distribution operations. Transmission revenue is
being determined through the FERC-authorized rates that are subject to refund.
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. At the
beginning of the transition period, SCE estimated its transition costs to be
approximately $10.6 billion (1998 net present value) from 1998 through 2030.
This estimate was based on incurred costs, forecasts of future costs and assumed
market prices. However, changes in the assumed market prices could materially
affect these estimates. 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. The potential transition costs
are comprised of $6.4 billion from SCE's qualifying facilities (QF) contracts,
which are the direct result of prior legislative and regulatory mandates, and
$4.2 billion from costs pertaining to certain generating assets (including the
1998 sale of SCE's generating plants) and regulatory commitments consisting of
costs incurred (whose recovery has been deferred by the CPUC) to provide service
to customers. Such commitments include the recovery of income tax benefits
previously flowed through to customers, post-retirement benefit transition
costs, accelerated recovery of San Onofre Units 2 and 3 and the Palo Verde
Nuclear Generating Station units,
4
and certain other costs. During 1998, SCE sold all of its gas- and oil-fueled
generation plants (except the small diesel-fueled Pebbly Beach Generating
Station) for $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. 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 write-offs associated with
these costs if they are not recovered through another regulatory mechanism.
Effective with the commencement of the ISO and PX operations on March 31, 1998,
generation costs are subject to recovery through the competitive market and the
CTC mechanism, which now includes the nuclear rate-making agreements. Transition
cost recovery for most utility generation assets will terminate on the earlier
of December 31, 2001, or when these costs are fully collected. The portion of
revenue related to fossil and hydroelectric generation operations that are
economic is recovered through the market. SCE's operational costs associated
with its fossil and hydroelectric plants are being recovered through market
revenue. The power sales revenue from fossil and hydroelectric facilities in
excess of fossil operational costs and the hydroelectric revenue requirement are
credited against transition costs. In 1999, fossil and hydroelectric generation
assets had the opportunity to earn a 7.22% return. SCE has filed an application
with the CPUC regarding the market valuation of its hydroelectric facilities.
(See further discussion below.)
The portion of revenue related to fossil and hydroelectric generation operations
that are made uneconomic by electric industry restructuring is recovered through
the CTC mechanism. The revenue available to recover such uneconomic generation
costs 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 and interutility contracts and the acceleration of sunk cost recovery
will be subject to annual reasonableness review by the CPUC.
SCE is recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return. SCE's nuclear assets
are earning an annual rate of return of 7.35%. In addition, San Onofre's
operating costs, including operations and maintenance costs, administrative and
general costs, nuclear fuel and nuclear fuel financing costs, and incremental
capital costs, are recovered through an incremental cost incentive pricing plan
which allows SCE to receive about 4(cent) per kilowatt hour through 2003. The
San Onofre plan commenced in April 1996, and ends in December 2001 for the
accelerated recovery portion, and in December 2003 for the incentive-pricing
portion. Palo Verde's operating costs, including incremental capital costs, and
nuclear fuel and nuclear fuel financing costs, are subject to balancing account
treatment. The Palo Verde plan for accelerated plant recovery, as well as
operating cost recovery through balancing account treatment, commenced in
January 1997 and ends in December 2001. Beginning January 1, 1998, both the San
Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
In March 1997, SCE filed a transmission owners tariff with the FERC, in
conjunction with tariffs filed by the ISO and PX with the FERC in March 1997.
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, in March 1997, SCE filed a
wholesale distribution access tariff. The FERC accepted the tariffs for filing,
subject to refund, effective April 1, 1998.
With the commencement of the ISO and PX, transmission cost recovery is now under
FERC authority. An administrative law judge (ALJ) decision was issued in March
1999 recommending a 9.68% return on equity for transmission assets, compared to
the current CPUC return on equity for distribution facilities of 11.6%. In
addition, the ALJ proposed a $23 million reduction in the proposed transmission
revenue requirement relating to overhead costs, despite the fact that before
implementation of the ISO, SCE had been authorized full recovery of these
overhead costs in rates at the CPUC. In total, the ALJ decision would result in
about a $50 million reduction annually in transmission revenue from the level
proposed by SCE of $211 million. Transmission rates have reflected SCE's
proposed $211 million transmission revenue requirement since they were
implemented in April 1998. As a result of the retail rate freeze
5
contained in the restructuring legislation, instead of being ordered to refund
excess payments back to retail customers, SCE expects to be able to credit the
amount of these payments against remaining transition costs.
SCE has opposed the ALJ decision and expects that the final FERC decision,
expected in early to mid-2000, will be more favorable. In the event that SCE
does not prevail on the overhead cost issue at the FERC, SCE does have the
opportunity to seek recovery in distribution rates at the CPUC of any overhead
costs not allowed in rates by the FERC.
As a part of compliance with the restructuring legislation, in October 1999, SCE
filed an application with the CPUC to approve an auction process for its 56%
interest in the Mohave Generating Station (Mohave Station). A CPUC decision on
the auction process is expected in early to mid-2000.
In order to comply with the restructuring legislation, on December 15, 1999, SCE
filed an application with the CPUC establishing a market value for its
hydroelectric generation-related assets at approximately $1.0 billion (almost
twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based and revenue-sharing mechanism.
The application had broad-based support from labor, ratepayer and environmental
groups. If approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-index operations and maintenance allowance, as well as a reasonable
return on capital investment. A revenue-sharing arrangement would be activated
if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue
to ratepayers or recover 90% of any shortfalls from ratepayers. A final CPUC
decision is expected by the end of 2000.
On January 7, 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of CTC recovery. The proposal seeks CPUC approval
of a rate redesign that will result in reduced rates for most customers when SCE
completes the first phase of recovery of its transition costs. The proposed new
rates are expected to reduce SCE's system average rates by about 17% from
current frozen rate levels, based on certain assumptions about competitive
energy prices. In addition, SCE's filing proposes to redesign and establish
separate transmission and distribution rates to better reflect the actual costs
to deliver electricity and serve customers. This pricing approach is consistent
with CPUC policies requiring California's major utilities to move toward
cost-based transmission and distribution rates.
Restructuring Implementation Costs
In May 1998, SCE filed an application with the CPUC to identify the categories
of restructuring implementation costs (including costs related to the start-up
and development of both the PX and ISO, and related to the implementation of
direct access) and to establish the reasonableness of those costs incurred in
1997. In September 1999, the CPUC approved a settlement agreement between SCE,
the ORA and several other parties allowing SCE to recover substantially all
(approximately $300 million) of its restructuring implementation costs (incurred
and estimated) for the period 1997-2001. In addition, the settlement provides
that up to $210 million of generation-related costs (transition costs) that are
displaced by recovery of the restructuring implementation costs during the rate
freeze may be recovered after December 31, 2001, the date SCE would cease to
recover these transition costs under restructuring legislation.
Market Risk Exposures
In July 1999, the PX introduced a block forward energy product. Participants can
purchase power up to 12 months in advance in monthly blocks for six days a week
and sixteen hours a day. Purchasing these blocks hedges against the risk of
price spikes in the spot energy markets. SCE has been using the PX's block
forward market since it received approval from the CPUC to do so in July 1999.
The CPUC set purchasing limits on utility purchases of approximately 2,000 MW.
In March 2000 the PX introduced additional forward block products covering
different hours. The CPUC granted SCE authority to purchase
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these new products on March 16, 2000. Furthermore, the CPUC allowed SCE to
purchase up to significantly increased limits, reaching 5,200 MW during summer
when SCE's demand is at its peak. SCE thus has an increased ability to hedge
against high price spikes in the energy markets. Purchases within these
authorized limits will be deemed reasonable by the CPUC. The CPUC granted this
authority for the duration of the rate freeze.
The PX recently requested authority from the FERC to offer additional products
including block forward ancillary services. SCE has filed an Advice Letter to
the CPUC requesting authority to participate in these new markets to hedge
against price spikes in the ISO's ancillary service spot market. SCE expects a
CPUC Decision in the first or second quarter of 2000.
Accounting for Generation-Related Assets
If the CPUC's electric industry restructuring plan continues as described above,
SCE will be allowed to recover its transition costs through non-bypassable
charges to its distribution customers (although its investment in certain
generation assets is subject to a lower authorized rate of return). In 1997, SCE
discontinued application of accounting principles for rate-regulated enterprises
for its generation assets based on new accounting guidance. The new guidance did
not require SCE to write off any of its generation-related assets, including
related regulatory assets. SCE has retained these assets on its balance sheet
because the restructuring legislation and restructuring plan referred to above
make probable their recovery through a non-bypassable charge 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, SCE reduced its remaining nuclear plant investment by $2.6 billion (as
of June 30, 1998) and recorded 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 made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at December 31, 1999) as a one-time, non-cash charge against
earnings. 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.
Other 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 "Changing Regulatory
Environment", the nature in which the CPUC regulates SCE is changing. The CPUC
has issued final decisions regarding direct access, transition cost recovery,
and rate unbundling in the restructuring of the electric industry. These
decisions affected cost recovery and rate regulation, and authorized new
ratemaking mechanisms which were implemented, replacing the Electric Revenue
Adjustment Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates
mechanism (pre-restructuring ratemaking mechanisms) as of January 1, 1998.
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
7
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 CPUC 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 (TRA); (3) verify the regulatory account balances which were
transferred to the Transition Cost Balancing Account (TCBA) on January 1, 1998
(See "Annual Transition Cost Proceedings" below for further discussion of the
TCBA); (4) streamline certain balancing and memorandum accounts; and (5) review
the PX charge/credit calculation. On June 6, 1999, the CPUC issued its final
1998 RAP decision. In compliance with that decision, SCE updated its
nongeneration rate components in October 1999. To maintain overall frozen rate
levels, to the extent nongeneration rate components are authorized to change,
the generation rate component changes equal and opposite from the nongeneration
rate component changes. The decision also instructed SCE to include in the 1999
RAP Report a PX credit calculation that reflects the long run marginal costs of
customer account managers, customer service representatives, self-provision of
ancillary services, and financing costs for purchasing power from the PX.
In June 1999, the CPUC issued a decision regarding unbundling SCE's cost of
capital based on major utility functions. The decision was in response to SCE's
May 1998 application on this issue. The CPUC found no unbundling adjustment was
required in setting 1999 cost of capital for the California electric utilities.
Furthermore, the CPUC ruled that SCE's rate of return should continue to be
governed by the cost of capital trigger mechanism authorized as part of SCE's
performance based ratemaking mechanism. (See discussion under "Revenue and
Cost-Recovery Mechanisms") As a result, SCE's return on equity for 1999 was
unchanged at 11.6%.
On August 9, 1999, SCE filed its 1999 RAP Report requesting CPUC approval of the
following: (1) consolidation of the 2000 nongeneration revenue requirements; (2)
rate levels for 2000, including the residually determined generation rates; (3)
2000 kWh sales forecast; (4) entries to the TRA for the period June 1, 1998,
through May 31, 1999; (5) proposed retention, elimination, and modification of
balancing and memorandum accounts; (6) implementation and costs of electric
vehicle programs during the record period; (7) administration of SCE's
self-generation deferral rate contracts during the record period; and (8) the
proposed additional 2 cents/MWh credit to direct access customers associated
with SCE's procurement of PX energy for bundled service customers. SCE
anticipates a final 1999 RAP decision in the third quarter of 2000.
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.
Annual Transition Cost Proceedings (ATCP)
In 1997, the CPUC established the ATCP as the proceeding to determine whether
SCE's TCBA entries are recorded pursuant to applicable CPUC decisions and the
restructuring legislation, and that certain expenses are justified. The purpose
of the TCBA is to provide and account for the recovery by SCE of certain costs
associated with the transition to a restructured electric industry in
California.
1998 ATCP
On September 1, 1998, SCE filed its first ATCP Report with the CPUC and
requested, among other things, 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
8
with applicable CPUC decisions and the restructuring legislation. On March 31,
1999, the ORA submitted its Report and made the following recommendations
adverse to SCE: (1) $2.37 million in QF shareholder incentive amounts should be
disallowed; (2) $3.2 million in employee-related transition costs should be
disallowed; and (3) $9.67 million in post-retirement benefits other than
pensions (PBOPs) and $5.76 million in long-term disability regulatory assets
should be rejected. On June 14, 1999, the ALJ granted SCE's motion to strike the
ORA's testimony and recommendations on the third item. Prior to hearings, the
ORA and SCE recommended that the CPUC adopt a stipulation and joint
recommendation whereby SCE would not recover $895,000 in retention bonuses, and
$1.19 million of the total QF shareholder incentive amounts. On October 8, 1999,
the matter was submitted to the CPUC.
On January 6, 2000, an ALJ issued a proposed decision adopting the stipulation
and joint recommendation as specified above. In addition, the proposed decision
provided clarification on the following four accounting issues impacting the
operation of the TCBA: (1) It directs SCE and the other utilities to review
their estimates of market value for each divested generating plant and
recalculate the interest accrued on undercollections of the TCBA during the
record period. SCE believes it used the market value accounting directed by the
proposed decision. (2) It clarifies the accounting methodology used to estimate
the market value of retained generating assets. At this time, SCE believes there
will be no negative impact on earnings associated with this issue. (3) It
directs SCE to apply the TCBA overcollection of $350.7 million as of June 30,
1998, to further accelerate the depreciation of those transition cost assets
with the highest rate of return, and in a manner which provides the greater tax
benefits (i.e., to accelerate the recovery of nuclear sunk costs). It also
directs SCE to net a $238 million undercollection in the ISO/PX implementation
delay memorandum account against the TCBA overcollection in the calculation. SCE
estimates a $10 million impact over the entire transition period ending December
31, 2001, if this accounting change is adopted by the CPUC. (4) It disallows the
recovery through the TCBA for the record period of certain telecommunications,
training, mechanical service shop and warehouse equipment that were related to
SCE's divested generating plants but was not purchased by the new owners. The
net book value of these retained assets is in the $8 million to $10 million
range. Comments to the proposed decision were filed in January and a
supplemental brief was filed on February 1, 2000.
On February 17, 2000, the ALJ prepared a revised proposed decision that
addressed these four matters and left intact other provisions of the proposed
decision. The revised proposed decision was approved by the CPUC on the same
day. The decision found that SCE's calculation of the TCBA for the record period
was correct and that SCE appropriately applied the overcollection as of June 30,
1998, to the subsequent undercollection. Therefore, the decision does not
require SCE to accelerate recovery of its nuclear assets. The decision changes
the accounting methodology used to estimate the market value of retained
generating assets and requires that SCE credit the TCBA for the aggregate net
book value of SCE's non-nuclear assets, including the land surrounding such
assets. SCE's share of the Mohave Station and Four Corners Generating Station
(Four Corners) are excluded from this requirement. Ongoing depreciation, taxes,
and return will be recovered through market revenue. The decision disallows the
recovery through the TCBA for the record period of the retained assets but does
not preclude SCE from seeking recovery in future record periods. The
disallowance for the 1998 record period was $55,000.
On February 29, 2000, SCE made a request to the CPUC's Executive Director for an
extension of time to file the compliance advice letter so that the CPUC could
review SCE's soon-to-be filed petition for a stay of the decision, application
for rehearing and/or petition for modification of the decision. In a letter
dated March 3, 2000, the Executive Director granted SCE an extension of time
until May 31, 2000, to file its advice letter compliance filing. At this time,
SCE believes there will be no materially negative impact on earnings.
1999 ATCP
On September 1, 1999, SCE filed its 1999 ATCP setting forth entries made to the
TCBA and other generation-related accounts for the months of July 1998 through
June 1999. The purpose of the ATCP is
9
to ensure the recovery of generation-related transition costs through the TCBA
that complies with the guidelines established by the CPUC. The TCBA tracks the
recovery of transition costs, including the accelerated recovery of plant
balances, QF and purchased power costs, and regulatory assets and obligations.
On February 23, 2000, the ORA issued its report and made the following
recommendations adverse to SCE: (1) approximately $5 million in post record
period adjustments booked after the date of divestiture for capital additions
made in 1996 to divested fossil generating plants; (2) $17.2 million related to
the termination contract with the Sacramento Municipal Utility District; (3)
$147,000 in employee-related transition costs; and (4) an $136,000 adjustment to
the QF subaccount of the TCBA. SCE will serve rebuttal testimony on March 29,
2000, and supplemental testimony on April 3, 2000.
Annual Energy Cost Adjustment Clause Proceedings
Through 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."
QF MATTERS
The ORA issued its report on the 1998 ECAC period on February 19, 1999. The ORA
did not identify any reasonableness issues associated with SCE's QF activities
during the 1998 period. On November 4, 1999, the CPUC issued its decision
approving all of SCE's QF administrative matters in the 1998 ECAC. The 1998 ECAC
is SCE's last ECAC application.
NON-QF MATTERS
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.
The ORA's review of the non-QF operations and costs was consolidated with its
review of the non-QF operations and costs for the 1996 ECAC record period. The
ORA filed its report on August 18, 1997. In its report, the ORA recommended,
among other things: 1) a disallowance of $360,000 associated with an outage at
the coal-fired Four Corners; 2) a $200,000 adjustment to the costs recorded in
SCE's Catastrophic Events Memorandum Account, and 3) a determination 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 are to 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 RAP. The CPUC found that
SCE's calculation of the NUIP reward was reasonable and it was an error for the
CPUC to order another reasonableness review of these rewards which totaled $15.2
million 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, the ORA issued its reasonableness report on the 1998 ECAC
period and made the following recommendations. The 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
10
accrued during the three month delay in the commencement of ISO/PX operations.
The 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.
The ORA found no evidence to show that SCE caused a delay in the ISO/PX
implementation. The ORA recommended two coal generation related disallowances
seeking replacement fuel costs based on December 1997 outages of Mohave Station
Units 1 and 2 in the amount of $2.4 million, and a $15.7 million disallowance
related to an outage at Four Corners Unit 5. The ORA also recommended
disallowances totaling $5.6 million plus interest, to correct for audit errors.
Hearings were held in June 1999 and on September 20, 1999, a CPUC ALJ issued a
proposed decision that rejected the ORA's recommended disallowances for the
outages at Four Corners and the Mohave Station, but adopted the ORA's
recommended balancing account adjustment. A CPUC decision issued on November 4,
1999, adopted the ALJ's proposed decision without change.
Palo Verde Nuclear Generating Station
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 NUIP 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(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 benefits
received from operation of San Onofre Units 2 and 3 equally with ratepayers.
New Accounting Rules
An accounting rule, which requires that costs related to start-up activities be
expensed as incurred, became effective January 1, 1999. This new accounting rule
did not materially affect SCE's 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 as amended will be effective for
SCE beginning January 1, 2001, requires all derivatives to be recognized on the
balance sheet at fair value. Gains or losses from changes in fair value will 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 will be reflected in other
comprehensive income. Gains or losses from hedges of a recognized asset or
liability, or a firm commitment will be reflected in earnings for the
ineffective portion of the hedge. SCE anticipates that most of its derivatives
under the new standard will 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.
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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 1999, fuel and purchased-power
costs, including net PX purchases, were approximately $3.4 billion, which was a
5% decrease from the costs in 1998.
SCE's sources of energy during 1999 were as follows: 58.9% purchased power;
22.0% nuclear; 13.5% coal; and 5.6% hydro.
Average fuel costs, expressed in (cent) per kWh, for the year ended December 31,
1999, were: oil, 7.51(cent); nuclear, 0.41(cent); and coal, 1.23(cent).
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
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(*) 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 United
States Department of Energy provide for the disposal of utility spent nuclear
fuel beginning January 31, 1998. The Department of Energy 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 2000 from existing contracts. Contracts covering
100% requirements are in place for conversion through 2000, enrichment through
2002, and fabrication through 2016.
Assuming normal operation and regulatory approval for more condensed on-site
spent fuel storage, Palo Verde will maintain full-core offload reserve until the
fall of 2003 for Unit 2 and spring and fall of 2004 for Units 1 and 3,
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
12
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.
In California, pursuant to federal, state and regional Clean Air Act programs,
SCE generating stations were required to reduce emissions of oxides of nitrogen
and certain other pollutants. During 1998, SCE sold all of its oil- and
gas-fueled generating stations 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 South Coast Air Quality
Management District. The remaining plant, the small diesel-fired 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 those divested facilities as active generating stations for the required
two-year period specified by California's electric utility restructuring
legislation. 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. Among
other responsibilities, 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 South Coast Air Quality Management District.
SCE also owns a 56% undivided interest in the Mohave Generating Station (Mohave
Station) located in Laughlin, Nevada, which is subject to certain air quality
programs. Several recent developments affect the emission reduction requirements
for this facility. Probably the most significant development is the entry of a
consent decree voluntarily entered into among certain environmental
organizations and the owners of the Mohave facility. This decree resolved a
litigation filed on February 19, 1998, by the Sierra Club and the Grand Canyon
Trust in the U.S. District Court in Nevada against the facility owners alleging
violations of the Nevada State Implementation Plan and applicable air quality
permits related to opacity and sulfur dioxide emission limits. (See, "Mohave
Generating Station Environmental Litigation," under Item 3 below for additional
discussion.) The decree, which was approved by the Court in December 1999, was
designed also to address concerns raised by two EPA programs regarding
visibility and regional haze. The EPA issued its final rulemaking regarding
regional haze regulations on July 1, 1999. The final rule is not expected to
impose any additional emissions control requirements on the Mohave Station
beyond meeting the provisions of the consent decree. The EPA and SCE also
participated in a study to determine the specific impact of air contaminant
emissions from the Mohave Station on visibility in Grand Canyon National Park.
The final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave Station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
Station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. Finally, in
June, 1999, the EPA issued an advanced notice of proposed rulemaking regarding
assessment of visibility impairment at the Grand Canyon. SCE filed comments on
the proposed rulemaking in November 1999. In a letter to SCE, the EPA has
expressed its belief that the controls provided in the consent decree will
likely resolve the potential Clean Air Act visibility concerns. The Agency is
considering incorporating the decree into the visibility provisions of its
Federal Implementation Plan for Nevada.
The Clean Air Act 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 the
Administrator makes certain findings. 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
13
that there is no need for further evaluation of the risks of hazardous air
pollutants emitted from such plants.
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.
The Resource Conservation and Recovery Act provides the statutory authority for
the EPA to implement a regulatory program for the safe treatment, recycling,
storage, and disposal of solid and hazardous waste. An unresolved issue remains
regarding the degree to which coal waste should be regulated under the act.
Increased regulation may result in increased expenses relating to the operation
of the Mohave Station.
The Toxic Substances Control Act and accompanying regulations govern the
manufacturing, processing, distribution in commerce, use, and disposal of listed
compounds, such as 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 45 identified sites
is $163 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: (1) the extent and nature of contamination; (2) the
scarcity of reliable data for identified sites; (3) the varying costs of
alternative cleanup methods; (4) developments resulting from investigatory
studies; (5) the possibility of identifying additional sites; and (6) 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 $284 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 (except the Pebbly Beach Generating Station) and
has retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its sites,
representing $90 million of its recorded liability, through an incentive
mechanism (SCE may seek 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 $126 million for its estimated minimum environmental-cleanup costs
expected to be recovered through customer rates.
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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
$5 million to $15 million. Recorded costs for 1999 were $14 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.
SCE's projected environmental capital expenditures are $850 million for the
2000--2004 period, mainly for undergrounding certain transmission and
distribution lines.
Year 2000 Issue
SCE implemented a comprehensive program to address potential Year 2000 computer
system impacts, consisting of five phases: inventory, impact assessment,
remediation, testing and implementation. Edison International provided overall
coordination of this effort, working with SCE and its business units. SCE met
its goal to have 100% of its critical systems Year 2000-ready by July 1, 1999. A
critical system was defined as those applications and systems, including
embedded processor technology, which if not appropriately remediated, may have
had a significant impact on customers, the health and safety of the public
and/or personnel, the revenue stream, or regulatory compliance. SCE developed
Year 2000-related contingency plans, which were in place at year-end 1999.
None of SCE's critical applications or assets encountered significant problems
on or since January 1, 2000, including on and over February 29, 2000, and they
continue to operate as expected. SCE expects business as usual in 2000, as it
relates to its Year 2000 computer systems issues.
SCE's Year 2000 costs through December 31, 1999, were $65 million, of which 37%
was for capital costs. SCE's current rate levels for providing electric service
were sufficient to provide funding for utility-related modifications.
Item 2. Properties
Existing Generating Facilities
SCE owns and operates one diesel-fueled generating plant located on Santa
Catalina island, 37 hydroelectric plants, and an undivided 75.05% interest
(1,614 MW net) in San Onofre Units 2 and 3. These plants are located in Central
and Southern California.
SCE also owns a 15.8% (590 MW net) share of Palo Verde which is located near
Phoenix, Arizona. SCE owns a 48% undivided interest (754 MW net) in Units 4 and
5 at the Four Corners, 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
Station, which consists of two coal-fueled steam electric generating units in
Clark County, Nevada. At year-end 1999, the existing SCE-owned generating
capacity (summer effective rating) was divided approximately as follows: 44.2%
nuclear, 32.4% coal, 23.2% hydroelectric, and 0.2% diesel. Pursuant to
California's
15
restructuring legislation, SCE filed an application with the CPUC on October 14,
1999, seeking authority to hold an auction to sell SCE's ownership interest in
the Mohave Station. A CPUC decision on the auction process is expected in early
to mid-2000.
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 37 hydroelectric plants (some with related reservoirs) have 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 1999 and 2029. 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, the 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 113.32
MW are pending. Annual licenses have been issued to SCE hydroelectric projects
that are undergoing relicensing and whose long-term licenses have expired. The
annual licenses will be renewed until the long-term licenses are issued. SCE
filed an application with the CPUC on December 15, 1999, seeking authorization
to market value and retain the ownership and operation of the hydroelectric
plants pursuant to the state's electric industry restructuring legislation.
The capacity factors in 1999 for SCE's principal generation resources were:
43.3% for SCE's hydroelectric plants (lower than average due to below-normal
water conditions); 88.4% for San Onofre; 70.8% for the Mohave Station; 79.4% for
Four Corners Units 4 and 5; and 93% for Palo Verde.
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 $2.2 billion in principal amount was outstanding on December
31, 1999. 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 Four Corners, 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 Four
Corners.
16
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $984 million in 1999,
$861 million in 1998 and $685 million in 1997. Construction expenditures for the
2000--2004 period are forecasted at $4.8 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 2004
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 the 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.
California's restructuring legislation, 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. The restructuring legislation 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. The restructuring
legislation 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, the ORA, and TURN entered into a settlement
agreement, which was approved by the CPUC on December 20, 1996. The agreement
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 the
restructuring legislation. The settling parties
17
agreed that SCE would recover its share of Palo Verde incremental operating
costs, except if those costs exceed 95% of the levels forecast by SCE in its
application by more than 30% in any given year. In such cases, 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 is
less than 55% in a calendar year, SCE will bear the burden of proof to
demonstrate that the site's operations causing the gross capacity factor 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% gross capacity factor may be
disallowed.
Beginning in 2002, the net 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. On March 8, 1999,
SCE, SDG&E, the ORA and TURN entered into a settlement agreement that provided
for SCE to access its nuclear decommissioning trust funds for Unit 1
decommissioning. On June 3, 1999, the CPUC adopted the settlement agreement. On
December 6, 1999, SCE applied for a coastal permit to demolish and remove San
Onofre Unit 1 buildings and other structures and to construct a temporary used
fuel storage facility, also referred to as an independent spent fuel storage
installation, as part of the San Onofre Unit 1 decommissioning project. On
February 15, 2000, the California Coastal Commission approved SCE's application.
Decommissioning of Unit 1 is now underway and it is anticipated that
decommissioning will continue through 2008. At that time, San Onofre Unit 1 will
be completely dismantled and only the spent nuclear fuel will remain on-site in
an independent spent fuel storage installation. All of SCE's reasonable San
Onofre Unit 1 decommissioning costs will be paid from its nuclear
decommissioning trust funds.
The San Onofre 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. The steam generator design allows for the removal of
up to 10% of the tubes before the rated capacity of the unit must be reduced. As
a result of the increased degradation found during a 1997 inspection, a
mid-cycle inspection outage was conducted in early 1998 for Unit 2. Continued
degradation was found during this inspection. A favorable or decreasing trend in
degradation was observed during inspection in the scheduled refueling outage in
January 1999 and as a result, a mid-cycle inspection outage in 2000 is expected
to be unnecessary. With the results from the January 1999 outage, 7.5% of the
tubes have now been removed from service.
During Unit 3's refueling outage, which was completed in May 1999, a complete
inspection of the steam generator tubes was performed. Results obtained were
within expectations. To date, 5.4% of Unit 3's tubes have been removed from
service.
Palo Verde Nuclear Generating Station
Based on the latest available data, Arizona Public Service (APS), the operator
of Palo Verde, 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. Installation of new steam generators in Unit
2 has been approved by the participants and is planned for 2003. 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.
18
Nuclear Facility Decommissioning
Decommissioning of San Onofre Unit 1 commenced in 1999 (See "San Onofre Nuclear
Generating Station" above for additional discussion). On March 9, 2000, the NRC
amended the operating licenses for San Onofre Units 2 and 3 to allow both units
to operate through 2022. Prior to this amendment, the NRC operating licenses for
San Onofre allowed both units to operate through 2013. SCE plans to decommission
San Onofre Units 2 and 3 in 2013 and Palo Verde at the end of each unit's
operating license by a removal method authorized by the NRC. The San Onofre
Units 2 and 3 and Palo Verde operating licenses currently expire in 2022 and
2028, respectively. Decommissioning is estimated to cost $2.0 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.
Decommissioning expense was $124 million in 1999 and $164 million in 1998. The
accumulated provision for decommissioning was $1.3 billion at December 31, 1999,
and $1.2 billion at December 31, 1998. The estimated costs to decommission San
Onofre Unit 1 ($360 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 $9.5
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. It
would have to pay, however, no more than $20 million per incident in any one
year. Such amounts include a 5% surcharge if additional funds are needed to
satisfy public liability claims and are subject to adjustment for inflation. If
the public liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible additional
assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million has also been
purchased in amounts greater than federal requirements. Additional insurance
covers part of replacement power expenses during an accident-related nuclear
unit outage. These policies are issued by a mutual insurance company owned by
utilities with nuclear facilities. If losses at any nuclear facility covered by
the arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up to $19
million per year. Insurance premiums are charged to operating expense.
19
Item 3. Legal Proceedings
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. SCE seeks damages for excess power purchase payments made to
the Coso parties and other relief. The Coso parties' motion to transfer venue to
Inyo County Superior Court was granted on August 31, 1997.
The Coso parties filed a cross-complaint against SCE, The Mission Group, and
Mission Power Engineering Company (Mission parties), which contains claims for
breach of contract, unfair competition, interference with contract, defamation,
breach of an earlier settlement agreement between the Mission parties and the
Coso parties, and other claims. As against SCE, the 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. As against the Mission parties, the
cross-complaint seeks damages for breach of warranty of authority with respect
to the settlement agreement, and for equitable indemnity. Edison International
was named as a cross-defendant, allegedly as an alter ego of SCE and the Mission
parties. The Coso parties voluntarily dismissed the claims against Edison
International.
Three of the Coso Parties also filed a separate action in the Inyo County
Superior Court against SCE and Edison International, alleging claims for unfair
competition, false advertising and for violations of Public Utilities Code ss.
2106, and seeking injunctive relief, restitution, and punitive damages. The
Court ordered this action consolidated with the SCE action.
Effective February 8, 2000, the parties entered into confidential agreements
resolving all claims in the consolidated action and calling for dismissals with
prejudice and releases. The settlement is subject to the approval of the CPUC.
On February 10, 2000, the Court approved a stipulation staying all proceedings
during the period required to obtain CPUC approval. SCE is in the process of
preparing an application to obtain such approval. The settlement is not expected
to have a material financial effect on SCE.
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 were 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. Pursuant to an agreement of the parties as
described below, all proceedings in this matter have been stayed.
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
20
completed in January 1999, oral argument took place on February 10, 2000, and
the matter was taken under submission. A decision is not expected until spring
or early summer of 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, leaving only the son as plaintiff. Pursuant to an agreement of the
parties as described below, all proceedings in the matter have been stayed.
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 all proceedings including trial,
pending the results of the case currently before the Ninth Circuit Court of
Appeal. The parties agreed that if the plaintiffs do not receive a favorable
determination on appeal then the two cases at the District Court level will be
dismissed. If, however, those plaintiffs receive a favorable determination on
their appeal, then the two District Court cases will be set for trial. On March
23, 1999, the District Court approved the parties' stay agreement in both cases.
SCE was previously involved, along with other defendants, in two earlier cases
raising allegations similar to those described above. Although SCE is no longer
actively involved in these actions, the impact on SCE, if any, from further
proceedings in those cases against the remaining defendants cannot 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
the Mohave Station. The lawsuit alleged that the Mohave Station has been
violating various provisions of the Clean Air Act, 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 sought declaratory and injunctive relief as well as civil
penalties. The Clean Air Act calls for a maximum civil penalty of $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. The plaintiffs filed an opposition to the defendants' motion to
dismiss as well as a separate motion for partial summary judgment on May 8,
1998.
On June 4, 1998, the plaintiffs served SCE and the other Mohave Station
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 and granted plaintiffs' motion to amend the complaint to add the National
Parks and Conservation Association as a plaintiff.
On December 8, 1998, defendants filed a supplemental memorandum in support of
defendants' opposition to plaintiffs' motion for partial summary judgment. On
February 4, 1999, plaintiffs filed their first amended complaint to add the
National Parks and Conservation Association as a plaintiff in the action. On
March 10, 1999, defendants filed a motion for partial summary judgment. On March
11, 1999, plaintiffs filed a motion for partial summary judgment to establish
emission limit violations as alleged in certain of the causes of action in their
first amended complaint.
On March 8, 1999, the parties filed a stipulated request for a 60-day stay which
was granted and ordered, by the Court on March 9, 1999. A subsequent stay was
granted, which was to expire on July 6, 1999, before being extended to July 20,
1999. On July 6, 1999, each party filed an opposition to the other parties'
motion for summary judgment. On August 2, 1999, defendants filed a reply to
plaintiffs' opposition. On August 5, 1999, plaintiffs filed a reply to
defendant's opposition.
On October 6, 1999, the parties filed a consent decree with the Federal District
Court in Las Vegas, requesting the judge to approve the decree, and
simultaneously dismiss the lawsuit. The decree provides
21
that certain environmental control hardware (lime spray dryers, fabric filter
baghouses and low NOx burners) should be installed on the facility by December
31, 2005, or else the Mohave Station will not be able to operate as a coal-fired
facility after such date. The consent decree was signed by the court on December
15, 1999.
Navajo Nation Litigation
On June 18, 1999, SCE, was served with a complaint filed by the Navajo Nation in
the United States District Court for the District of Columbia against Peabody
Holding Company and certain of its affiliates (Peabody), Salt River Project
Agricultural Improvement and Power District, and SCE. The complaint asserts
claims against the defendants for, among other things, violations of the federal
RICO statute, interference with fiduciary duties and contractual relations,
fraudulent misrepresentation by nondisclosure, and various contract-related
claims. Peabody supplies coal from mines on Navajo Nation lands to the Mohave
Station. The complaint claims that the defendants' actions prevented the Navajo
Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount,
and punitive damages of not less than $1 billion, as well as a declaration that
Peabody's lease and contract rights to mine coal on Navajo Nation lands should
be terminated. SCE joined Peabody's motion to strike the Navajo Nation's
complaint. In addition, SCE and other defendants have filed motions to dismiss.
The Navajo Nation had previously filed suit in the Court of Claims against the
United States Department of Interior, alleging that the Government had breached
its fiduciary duty concerning the above-referenced contract negotiations. On
February 4, 2000 the Court of Claims issued a decision in the Government's
favor, finding that while there had been a breach, there was no available
redress from the Government. In its decision, the Court indicated that it was
making no statements regarding, or findings in, the above federal civil court
action. On February 28, 2000, the Hopi Tribe filed a motion to intervene in the
pending litigation, alleging that the royalty payments set for their interest in
the coal leases with Peabody had been impacted by the events at issue in the
Navajo case. The defendants filed an opposition to the motion, which has not
been calendared for hearing.
Claims Arising from Oil Spill Incidents
In mid 1999, the San Bernardino County Fire Department and the Santa Ana branch
of the Regional Water Quality Control Board initiated an investigation into an
incident occurring on December 9, 1998, involving an oil spill at SCE's Kimberly
Pole Top Station caused by severe windstorms. During the course of this
investigation, the agencies discovered that barrels of mislabeled waste had
remained for several days on the site of a separate oil spill and clean-up
caused by an oil release from a padmount transformer.
In February 2000, SCE entered into a settlement agreement with the agencies for
claims arising out of both of these incidents. SCE paid $300,000 to San
Bernardino County and $100,000 to the Regional Board in civil penalties. The
County also recovered its costs of $5,400 and SCE agreed to provide all
elementary and middle schools in the County with an environmental education
program. The estimated cost of this program is $140,000.
22
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, 1999 Company Position
- ----------------- ----------------- --------------------------------------
Stephen E. Frank 58 Chairman of the Board, President,
Chief Executive Officer and Director
Harold B. Ray 59 Executive Vice President, Generation
Business Unit
Pamela A. Bass 52 Senior Vice President, Customer Service
Business Unit
John R. Fielder 54 Senior Vice President, Regulatory
Policy and Affairs
Richard M. Rosenblum 49 Senior Vice President, T&D Business Unit
Bruce C. Foster 47 Vice President, Regulatory Affairs
Thomas M. Noonan 48 Vice President and Controller
Stephen E. Pickett 49 Vice President and General Counsel
W. James Scilacci 44 Vice President and Chief Financial Officer
Anthony L. Smith 51 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.
23
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 elected
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. Those 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 Chairman of the Board, President, Chief January 2000 to present
Executive Officer and Director
President, Chief Operating Officer and June 1995 to December 1999
Director
President and Chief Operating Officer, August 1990 to January 1995
Florida Power and Light Company(1)
Harold B. Ray Executive Vice President, Generation June 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
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present
Affairs
Vice President, Regulatory Policy and Affairs February 1992 to February 1998
Robert G. Foster Senior Vice President, Public Affairs November 1996 to present
Vice President, Public Affairs November 1993 to October 1996
Richard M. Rosenblum Senior Vice President, T&D Business Unit February 1998 to present
Vice President, Distribution Business Unit January 1996 to February 1998
Vice President, Nuclear Engineering and June 1993 to December 1995
Technical Services
Thomas M. Noonan Vice President and Controller March 1999 to present
Assistant Controller September 1993 to February 1999
Stephen E. Pickett Vice President and General Counsel January 2000 to present
Associate General Counsel November 1993 to December 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.
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, 1999, (Annual Report) under "Quarterly Financial Data" on
page 33 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: 1995-1999" on page 36 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 10 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 page 4 through 5 incorporated herein by reference pursuant to
General Instruction G(2), and in Part I, Item 1 of this report on pages 6
through 7 under "Market Risk Exposures".
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in Part IV.
Other information responding to Item 8 is included in the Annual Report on pages
11 through 33, 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 SEC in connection
with SCE's Annual Meeting to be held on April 20, 2000, under the heading,
"Election of Directors" on pages 6 and 7 and "Section 16(a) Beneficial Ownership
Reporting Compliance" on page 13, 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 Summary Compensation
Table" beginning on page 15 and continuing through page 25, excluding the
"Compensation and Executive Personnel Committees' Report on Executive
Compensation," 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" on pages 12 and
13 and "Stock Ownership of Certain Shareholders" on page 14, 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 30 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 Annual Report are found on pages 1 through
35, and 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, 1999,
1998 and 1997
Consolidated Statements of Comprehensive Income -- Years Ended December
31, 1999, 1998 and 1997
Consolidated Balance Sheets -- December 31, 1999, and 1998
Consolidated Statements of Cash Flows -- Years Ended December 31, 1999,
1998 and 1997
Consolidated Statements of Changes in Common Shareholder's Equity --
Years Ended December 31, 1999, 1998 and 1997
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(2) Report of Independent Public Accountants and Schedules
Supplementing Financial Statements
The following documents may be found in this report at the indicated page
numbers.
Page
----
Report of Independent Public Accountants on Supplemental
Schedules ....................................................... 28
Schedule II--Valuation and Qualifying Accounts for the
Years Ended December 31, 1999, 1998 and 1997..................... 29
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 33 of this report.
(b) Reports on Form 8-K
October 6, 1999
Item 5: Other Events Mohave Generating Station Environmental
Litigation
27
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Southern California Edison Company:
We have audited, in accordance with auditing standards generally accepted in the
United States, the consolidated financial statements included in the 1999 Annual
Report to Shareholders of Southern California Edison Company (SCE) incorporated
by reference in this Form 10-K, and have issued our report thereon dated
February 2, 2000. 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 2, 2000
28
SOUTHERN CALIFORNIA EDISON COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 1999
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 $ 19,596 $ 21,968 -- $ 19,908 $ 21,656
All other 2,634 1,288 -- 913 3,009
-------- --------- -------- --------- -----------
Total $ 22,230 $ 23,256 -- $ 20,821 (a) $ 24,665
======== ========= ======== ======== =======
Group B:
DOE Decontamination
and Decommissioning $ 39,419 -- $ (134) (b) $ 4,695 (c) $ 34,590
Purchased-power settlements 129,697 $466,043 -- 32,281 (d) 563,459
Pension and benefits 239,668 48,894 21,674 (e) 77,335 (f) 232,901
Insurance, casualty and
other 73,249 37,674 -- 42,043 (g) 68,880
-------- -------- -------- -------- --------
Total $482,033 $552,611 $ 21,540 $156,354 $899,830
======== ======== ======== ======== ========
- -----------
(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, 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.
30
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, amounts paid to active
employees during periods of illness and the funding of certain pension
benefits.
(h) Amounts charged to operations that were not covered by insurance.
31
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
By Kenneth S. Stewart
---------------------------
Kenneth S. Stewart
Assistant General Counsel
Date: March 28, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
Principal Executive Officer:
Stephen E. Frank* Chairman of the Board, President, March 28, 2000
Chief Executive Officer
and Director
Principal Financial Officer:
W. James Scilacci* Vice President and Chief March 28, 2000
Financial Officer
Controller or Principal
Accounting Officer:
Thomas M. Noonan* Vice President and March 28, 2000
Controller
Board of Directors:
Winston H. Chen* Director March 28, 2000
Warren Christopher* Director March 28, 2000
Stephen E. Frank* Director March 28, 2000
Joan C. Hanley* Director March 28, 2000
Carl F. Huntsinger* Director March 28, 2000
Charles D. Miller* Director March 28, 2000
Luis G. Nogales* Director March 28, 2000
Ronald L. Olson* Director March 28, 2000
James M. Rosser* Director March 28, 2000
Robert H. Smith* Director March 28, 2000
Thomas C. Sutton* Director March 28, 2000
Daniel M. Tellep* Director March 28, 2000
Edward Zapanta* Director March 28, 2000
*By:
Kenneth S. Stewart
------------------------------------
Kenneth S. Stewart
Assistant General Counsel
32
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE
effective June 1, 1993 (File No. 1-2313, Form 10-K for the year ended
December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE
dated June 23, 1997 (File No. 1-2313, Form 10-Q for the quarter ended
September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the
Board of Directors on February 17, 2000
4.1 SCE First Mortgage Bond Trust Indenture, dated as of October 1, 1923
(Registration No. 2-1369)*
4.2 Supplemental Indenture, dated as of March 1, 1927 (Registration No.
2-1369)*
4.3 Third Supplemental Indenture, dated as of June 24, 1935 (Registration
No. 2-1602)*
4.4 Fourth Supplemental Indenture, dated as of September 1, 1935
(Registration No. 2-4522)*
4.5 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration
No. 2-4522)*
4.6 Sixth Supplemental Indenture, dated as of September 1, 1940
(Registration No. 2-4522)*
4.7 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration
No. 2-7610)*
4.8 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964
(Registration No. 2-22056)*
4.9 Eighty-Eighth Supplemental Indenture, dated as of July 15 1992 (File No.
1-2313, Form 8-K dated July 22, 1992)*
4.10 Indenture dated as of January 15, 1993 (File No. 1-2313, Form 8-K dated
January 28, 1993)*
10.1 1981 Deferred Compensation Agreement (File No. 1-2313, filed as Exhibit
10.2 to Form 10-K for the year ended December 31, 1981)*
10.2 1985 Deferred Compensation Agreement for Executives (File No. 1-2313,
filed as Exhibit 10.3 to Form 10-K for the year ended December 31,
1986)*
10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313,
filed as Exhibit 10.4 to Form 10-K for the year ended December 31,
1986)*
10.4 Director Deferred Compensation Plan (File No. 1-2313, filed as Exhibit
10.3 to Form 10-Q for the quarter ended June 30, 1998)*
10.5 Director Grantor Trust Agreement (File No. 1-2313, filed as Exhibit
10.10 to Form 10-K for the year ended December 31, 1995)*
10.6 Executive Deferred Compensation Plan (File No. 1-2313, filed as Exhibit
10.2 to Form 10-Q for the quarter ended March 31, 1998)*
10.7 Executive Grantor Trust Agreement (File No. 1-2313, filed as Exhibit
10.12 to Form 10-K for the year ended December 31, 1995)*
10.8 Executive Supplemental Benefit Program as amended effective January 30,
1990 (File No. 1-2313, filed as Exhibit 10.2 to Form 10-Q for the
quarter ended September 30, 1999)*
10.9 Executive Retirement Plan as amended effective April 1, 1999 (File No.
1-2313, filed as Exhibit 10.1 to Form 10-Q for the quarter ended
September 30, 1999)*
10.10 Executive Incentive Compensation Plan (File No. 1-2313, filed as Exhibit
10.12 to Form 10-K for the year ended December 31, 1997)*
33
Exhibit
Number Description
- ------- -----------
10.11 Executive Disability and Survivor Benefit Program (File No. 1-2313,
filed as Exhibit 10.22 to Form 10-K for the year ended December 31,
1994)*
10.12 Retirement Plan for Directors (File No. 1-2313, filed as Exhibit 10.2 to
Form 10-Q for the quarter ended June 30, 1998)*
10.13 Officer Long-Term Incentive Compensation Plan as amended effective
January 1, 1998 (File No. 1-2313, filed as Exhibit 10.3 to Form 10-Q for
the quarter ended March 31, 1998)*
10.13.1 Form of Agreement for 1989-1995 Awards under the Officer Long-Term
Incentive Compensation Plan (File No. 1-2313, filed as Exhibit 10.21.1
to Form 10-K for the year ended December 31, 1995)*
10.13.2 Form of Agreement for 1996 Awards under the Officer Long-Term Incentive
Compensation Plan (File No. 1-2313, filed as Exhibit 10.16.2 to Form
10-K for the year ended December 31, 1996)*
10.13.3 Form of Agreement for 1997 Awards under the Officer and Management
Long-Term Incentive Compensation Plans (File No. 1-2313, filed as
Exhibit 10.16.3 to Form 10-K for the year ended December 31, 1997)*
10.14 Equity Compensation Plan (File No. 1-2313, filed as Exhibit 10.1 to Form
10-Q for the quarter ended June 30, 1998)*
10.14.1 Form of Agreement for 1998 Employee Awards under the Equity Compensation
Plan (File No. 1-2313, filed as Exhibit 10.4 to Form 10-Q for the
quarter ended June 30, 1998)*
10.14.2 Form of Agreement for 1998 Director Awards under the Equity Compensation
Plan (File No. 1-2313, filed as Exhibit 10.5 to Form 10-Q for the
quarter ended June 30, 1998)*
10.14.3 Form of Agreement for 1999 Employee Awards (File No. 1-2313, filed as
Exhibit 10 to Form 10-Q for the quarter ended March 31, 1999)*
10.14.4 Form of Agreement for 1999 Director Awards under the Equity Compensation
Plan (File No. 1-2313, filed as Exhibit 10.1 to Form 10-Q for the
quarter ended June 30, 1999)*
10.15 Estate and Financial Planning Program as amended April 1, 1999 (File No.
1-2313, filed as Exhibit 10.2 to Form 10-Q for the quarter ended June
30, 1999)*
10.16 Option Gain Deferral Plan (File No. 1-2313, filed as Exhibit 10.1 to
Form 10-Q for the quarter ended March 31, 1998)*
10.17 Employment Letter Agreement with Bryant C. Danner (File No. 1-2313,
filed as Exhibit 10.27 to Form 10-K for the year ended December 31,
1992)*
10.18 Employment Letter Agreement with Stephen E. Frank (File No. 1-2313,
filed as Exhibit 10.25 to Form 10-K for the year ended December 31,
1995)*
10.19 Election Terms for Warren Christopher (File No. 1-2313, filed as Exhibit
10.21 to Form 10-K for the year ended December 31, 1997)*
10.20 Dispute resolution amendment of 1981 Executive Deferred Compensation
Plan, 1985 Executive and Director Deferred Compensation Plans and
Executive Supplemental Benefit Program (File No. 1-2313, filed as
Exhibit 10.20 to Form 10-K for the year ended December 31, 1998)*
12. Computation of Ratios of Earnings to Fixed Charges
13. Annual Report to Shareholders for year ended December 31, 1999
23. Consent of Independent Public Accountants - Arthur Andersen LLP
24.1 Power of Attorney
24.2 Certified copy of Resolution of Board of Directors Authorizing Signature
27. Financial Data Schedule
- ------------
* Incorporated by reference pursuant to Rule 12b-32.
To Holders of the Company's Bylaws:
Effective February 17, 2000, Article II, Section 2, was amended to
change the time of the annual meeting of shareholders from 10:00 a.m.
to such time as the Chairman of the Board shall designate.
BEVERLY P. RYDER
Corporate Secretary
BYLAWS
OF
SOUTHERN CALIFORNIA EDISON COMPANY
AS AMENDED TO AND INCLUDING
FEBRUARY 17, 2000
INDEX
Page
ARTICLE I -- PRINCIPAL OFFICE
Section 1. Principal Office...............................................1
ARTICLE II -- SHAREHOLDERS
Section 1. Meeting Locations..............................................1
Section 2. Annual Meetings................................................1
Section 3. Special Meetings...............................................2
Section 4. Notice of Annual or Special Meeting............................2
Section 5. Quorum.........................................................4
Section 6. Adjourned Meeting and Notice Thereof...........................4
Section 7. Voting.........................................................4
Section 8. Record Date....................................................6
Section 9. Consent of Absentees...........................................7
Section 10. Action Without Meeting.........................................7
Section 11. Proxies........................................................8
Section 12. Inspectors of Election.........................................8
ARTICLE III -- DIRECTORS
Section 1. Powers.........................................................9
Section 2. Number of Directors...........................................10
Section 3. Election and Term of Office...................................10
Section 4. Vacancies.....................................................10
Section 5. Place of Meeting..............................................11
Section 6. Regular Meetings..............................................11
Section 7. Special Meetings..............................................11
Section 8. Quorum........................................................12
Section 9. Participation in Meetings by Conference Telephone.............12
Section 10. Waiver of Notice..............................................12
Section 11. Adjournment...................................................13
Section 12. Fees and Compensation.........................................13
Section 13. Action Without Meeting........................................13
Section 14. Rights of Inspection..........................................13
Section 15. Committees....................................................13
ARTICLE IV -- OFFICERS
Section 1. Officers......................................................14
Section 2. Election......................................................15
Section 3. Eligibility of Chairman or President..........................15
Section 4. Removal and Resignation.......................................15
Section 5. Appointment of Other Officers.................................15
Section 6. Vacancies.....................................................15
Section 7. Salaries......................................................16
Section 8. Furnish Security for Faithfulness.............................16
Section 9. Chairman's Duties; Succession to
Such Duties in Chairman's Absence or Disability......16
Section 10. President's Duties............................................16
Section 11. Chief Financial Officer.......................................17
Section 12. Vice President's Duties.......................................17
Section 13. General Counsel's Duties......................................17
Section 14. Associate General Counsel's and Assistant General
Counsel's Duties.....................................17
Section 15. Controller's Duties...........................................17
Section 16. Assistant Controllers' Duties.................................17
Section 17. Treasurer's Duties............................................18
Section 18. Assistant Treasurers' Duties..................................18
Section 19. Secretary's Duties............................................18
Section 20. Assistant Secretaries' Duties.................................19
Section 21. Secretary Pro Tempore.........................................19
Section 22. Election of Acting Treasurer or Acting Secretary..............19
Section 23. Performance of Duties.........................................20
ARTICLE V -- OTHER PROVISIONS
Section 1. Inspection of Corporate Records...............................20
Section 2. Inspection of Bylaws..........................................21
Section 3. Contracts and Other Instruments, Loans, Notes
and Deposits of Funds...................................21
Section 4. Certificates of Stock.........................................22
Section 5. Transfer Agent, Transfer Clerk and Registrar..................22
Section 6. Representation of Shares of Other Corporations................22
ARTICLE V -- OTHER PROVISIONS (Cont.)
Section 7. Stock Purchase Plans..........................................23
Section 8. Fiscal Year and Subdivisions..................................23
Section 9. Construction and Definitions..................................23
ARTICLE VI -- INDEMNIFICATION
Section 1. Indemnification of Directors and Officers.....................24
Section 2. Indemnification of Employees and Agents.......................25
Section 3. Right of Directors and Officers to Bring Suit.................26
Section 4. Successful Defense............................................26
Section 5. Non-Exclusivity of Rights.....................................26
Section 6. Insurance.....................................................26
Section 7. Expenses as a Witness.........................................27
Section 8. Indemnity Agreements..........................................27
Section 9. Separability..................................................27
Section 10. Effect of Repeal or Modification..............................27
ARTICLE VII -- EMERGENCY PROVISIONS
Section 1. General.......................................................27
Section 2. Unavailable Directors.........................................28
Section 3. Authorized Number of Directors................................28
Section 4. Quorum........................................................28
Section 5. Creation of Emergency Committee...............................28
Section 6. Constitution of Emergency Committee...........................29
Section 7. Powers of Emergency Committee.................................29
Section 8. Directors Becoming Available..................................29
Section 9. Election of Board of Directors................................29
Section 10. Termination of Emergency Committee............................30
ARTICLE VIII -- AMENDMENTS
Section 1. Amendments...................................................30
BYLAWS
Bylaws for the regulation, except as otherwise provided
by statute or its Articles of Incorporation
of
SOUTHERN CALIFORNIA EDISON COMPANY
AS AMENDED TO AND INCLUDING
FEBRUARY 17, 2000
ARTICLE I -- PRINCIPAL OFFICE
Section 1. Principal Office.
The Edison General Office, situated at 2244 Walnut Grove Avenue, in the
City of Rosemead, County of Los Angeles, State of California, is hereby fixed as
the principal office for the transaction of the business of the corporation.
ARTICLE II -- SHAREHOLDERS
Section 1. Meeting Locations.
All meetings of shareholders shall be held at the principal office of the
corporation or at such other place or places within or without the State of
California as may be designated by the Board of Directors (the "Board"). In the
event such places shall prove inadequate in capacity for any meeting of
shareholders, an adjournment may be taken to and the meeting held at such other
place of adequate capacity as may be designated by the officer of the
corporation presiding at such meeting.
Section 2. Annual Meetings.
The annual meeting of shareholders shall be held on the third Thursday of
the month of April of each year at such time as the Chairman of the Board shall
designate on said day to elect directors to hold office for the year next
ensuing and until their successors shall be elected, and to consider and act
upon such other matters as may lawfully be presented to such meeting; provided,
however, that should said day fall upon a legal holiday, then any such annual
meeting of shareholders shall be held at such designated time and place on the
next day thereafter ensuing which is not a legal holiday.
1
Section 3. Special Meetings.
Special meetings of the shareholders may be called at any time by the
Board, the Chairman of the Board, the President, or upon written request of any
three members of the Board, or by the holders of shares entitled to cast not
less than ten percent of the votes at such meeting. Upon request in writing to
the Chairman of the Board, the President, any Vice President or the Secretary by
any person (other than the Board) entitled to call a special meeting of
shareholders, the officer forthwith shall cause notice to be given to the
shareholders entitled to vote that a meeting will be held at a time requested by
the person or persons calling the meeting, not less than thirty-five nor more
than sixty days after the receipt of the request. If the notice is not given
within twenty days after receipt of the request, the persons entitled to call
the meeting may give the notice.
Section 4. Notice of Annual or Special Meeting.
Written notice of each annual or special meeting of shareholders shall be
given not less than ten (or if sent by third-class mail, thirty) nor more than
sixty days before the date of the meeting to each shareholder entitled to vote
thereat. Such notice shall state the place, date, and hour of the meeting and
(i) in the case of a special meeting, the general nature of the business to be
transacted, and no other business may be transacted, or (ii) in the case of an
annual meeting, those matters which the Board, at the time of the mailing of the
notice, intends to present for action by the shareholders, but, subject to the
provisions of applicable law and these Bylaws, any proper matter may be
presented at an annual meeting for such action. The notice of any special or
annual meeting at which directors are to be elected shall include the names of
nominees intended at the time of the notice to be presented by the Board for
election. For any matter to be presented by a shareholder at an annual meeting
held after December 31, 1993, but on or before December 31, 1999, including the
nomination of any person (other than a person nominated by or at the direction
of the Board) for election to the Board, written notice must be received by the
Secretary of the corporation from the shareholder not less than sixty nor more
than one hundred twenty days prior to the date of the annual meeting specified
in these Bylaws and to which the shareholder's notice relates; provided however,
that in the event the annual meeting to which the shareholder's written notice
relates is to be held on a date which is more than thirty days earlier than the
date of the annual meeting specified in these Bylaws, the notice from a
shareholder must be received by the Secretary not later than the close of
business on the tenth day following the date on which public disclosure of the
date of the annual meeting was made or given to the shareholders. For any matter
to be presented by a shareholder at an annual meeting held after December 31,
1999, including the nomination of any person (other than a person nominated by
or at the direction of the Board) for election to the Board, written notice must
be received
2
by the Secretary of the corporation from the shareholder not more than one
hundred eighty days nor less than one hundred twenty days prior to the date on
which the proxy materials for the prior year's annual meeting were first
released to shareholders by the corporation; provided however, that in the event
the annual meeting to which the shareholder's written notice relates is to be
held on a date which is more than thirty days earlier or later than the date of
the annual meeting specified in these Bylaws, the notice from a shareholder must
be received by the Secretary not earlier than two hundred twenty days prior to
the date of the annual meeting to which the shareholder's notice relates nor
later than one hundred sixty days prior to the date of such annual meeting,
unless less than one hundred seventy days' prior public disclosure of the date
of the meeting is made by the earliest possible quarterly report on Form 10-Q,
or, if impracticable, any means reasonably calculated to inform shareholders
including without limitation a report on Form 8-K, a press release or
publication once in a newspaper of general circulation in the county in which
the principal office is located, in which event notice by the shareholder to be
timely must be received not later than the close of business on the tenth day
following the date of such public disclosure. The shareholder's notice to the
Secretary shall set forth (a) a brief description of each matter to be presented
at the annual meeting by the shareholder; (b) the name and address, as they
appear on the corporation's books, of the shareholder; (c) the class and number
of shares of the corporation which are beneficially owned by the shareholder;
and (d) any material interest of the shareholder in the matters to be presented.
Any shareholder who intends to nominate a candidate for election as a director
shall also set forth in such a notice (i) the name, age, business address and
residence address of each nominee that he or she intends to nominate at the
meeting, (ii) the principal occupation or employment of each nominee, (iii) the
class and number of shares of capital stock of the corporation beneficially
owned by each nominee, and (iv) any other information concerning the nominee
that would be required under the rules of the Securities and Exchange Commission
in a proxy statement soliciting proxies for the election of the nominee. The
notice shall also include a consent, signed by the shareholder's nominees, to
serve as a director of the corporation if elected. Notwithstanding anything in
these Bylaws to the contrary, and subject to the provisions of any applicable
law, no business shall be conducted at a special or annual meeting except in
accordance with the procedures set forth in this Section 4.
Notice of a shareholders' meeting shall be given either personally or by
first-class mail (or, if the outstanding shares of the corporation are held of
record by 500 or more persons on the record date for the meeting, by third-class
mail) or by other means of written communication, addressed to the shareholder
at the address of such shareholder appearing on the books of the corporation or
given by the shareholder to the corporation for the purpose of notice; or, if no
such address appears or is given, at the place where the principal office of the
corporation is located or by publication at least once in a newspaper of general
3
circulation in the county in which the principal office is located. Notice
by mail shall be deemed to have been given at the time a written notice is
deposited in the United States mails, postage prepaid. Any other written notice
shall be deemed to have been given at the time it is personally delivered to the
recipient or is delivered to a common carrier for transmission, or actually
transmitted by the person giving the notice by electronic means, to the
recipient.
Section 5. Quorum.
A majority of the shares entitled to vote, represented in person or by
proxy, shall constitute a quorum at any meeting of shareholders. The affirmative
vote of a majority of the shares represented and voting at a duly held meeting
at which a quorum is present (which shares voting affirmatively also constitute
at least a majority of the required quorum) shall be the act of the
shareholders, unless the vote of a greater number or voting by classes is
required by law or the Articles; provided, however, that the shareholders
present at a duly called or held meeting at which a quorum is present may
continue to do business until adjournment, notwithstanding the withdrawal of
enough shareholders to have less than a quorum, if any action taken (other than
adjournment) is approved by at least a majority of the shares required to
constitute a quorum.
Section 6. Adjourned Meeting and Notice Thereof.
Any shareholders' meeting, whether or not a quorum is present, may be
adjourned from time to time by the vote of a majority of the shares, the holders
of which are either present in person or represented by proxy thereat, but in
the absence of a quorum (except as provided in Section 5 of this Article) no
other business may be transacted at such meeting.
It shall not be necessary to give any notice of the time and place of the
adjourned meeting or of the business to be transacted thereat, other than by
announcement at the meeting at which such adjournment is taken. At the adjourned
meeting, the corporation may transact any business which might have been
transacted at the original meeting. However, when any shareholders' meeting is
adjourned for more than forty-five days or, if after adjournment a new record
date is fixed for the adjourned meeting, notice of the adjourned meeting shall
be given as in the case of an original meeting.
Section 7. Voting.
The shareholders entitled to notice of any meeting or to vote at any such
meeting shall be only persons in whose name shares stand on the stock records of
the corporation on the record date determined in accordance with Section 8 of
this Article.
4
Voting shall in all cases be subject to the provisions of Chapter 7 of the
California General Corporation Law, and to the following provisions:
(a) Subject to clause (g), shares held by an administrator, executor,
guardian, conservator or custodian may be voted by such holder either in person
or by proxy, without a transfer of such shares into the holder's name; and
shares standing in the name of a trustee may be voted by the trustee, either in
person or by proxy, but no trustee shall be entitled to vote shares held by such
trustee without a transfer of such shares into the trustee's name.
(b) Shares standing in the name of a receiver may be voted by such
receiver; and shares held by or under the control of a receiver may be voted by
such receiver without the transfer thereof into the receiver's name if authority
to do so is contained in the order of the court by which such receiver was
appointed.
(c) Subject to the provisions of Section 705 of the California General
Corporation Law and except where otherwise agreed in writing between the
parties, a shareholder whose shares are pledged shall be entitled to vote such
shares until the shares have been transferred into the name of the pledgee, and
thereafter the pledgee shall be entitled to vote the shares so transferred.
(d) Shares standing in the name of a minor may be voted and the corporation
may treat all rights incident thereto as exercisable by the minor, in person or
by proxy, whether or not the corporation has notice, actual or constructive, of
the non-age unless a guardian of the minor's property has been appointed and
written notice of such appointment given to the corporation.
(e) Shares standing in the name of another corporation, domestic or
foreign, may be voted by such officer, agent or proxyholder as the bylaws of
such other corporation may prescribe or, in the absence of such provision, as
the Board of Directors of such other corporation may determine or, in the
absence of such determination, by the chairman of the board, president or any
vice president of such other corporation, or by any other person authorized to
do so by the chairman of the board, president or any vice president of such
other corporation. Shares which are purported to be voted or any proxy purported
to be executed in the name of a corporation (whether or not any title of the
person signing is indicated) shall be presumed to be voted or the proxy executed
in accordance with the provisions of this subdivision, unless the contrary is
shown.
(f) Shares of the corporation owned by any of its subsidiaries shall not be
entitled to vote on any matter.
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(g) Shares of the corporation held by the corporation in a fiduciary
capacity, and shares of the corporation held in a fiduciary capacity by any of
its subsidiaries, shall not be entitled to vote on any matter, except to the
extent that the settlor or beneficial owner possesses and exercises a right to
vote or to give the corporation binding instructions as to how to vote such
shares.
(h) If shares stand of record in the names of two or more persons, whether
fiduciaries, members of a partnership, joint tenants, tenants in common, husband
and wife as community property, tenants by the entirety, voting trustees,
persons entitled to vote under a shareholder voting agreement or otherwise, or
if two or more persons (including proxyholders) have the same fiduciary
relationship respecting the same shares, unless the secretary of the corporation
is given written notice to the contrary and is furnished with a copy of the
instrument or order appointing them or creating the relationship wherein it is
so provided, their acts with respect to voting shall have the following effect:
(i) If only one votes, such act binds all;
(ii) If more than one vote, the act of the majority so voting binds all;
(iii)If more than one vote, but the vote is evenly split on any particular
matter, each faction may vote the securities in question
proportionately.
If the instrument so filed or the registration of the shares shows that any such
tenancy is held in unequal interests, a majority or even split for the purpose
of this section shall be a majority or even split in interest.
No shareholder of any class of stock of this corporation shall be entitled
to cumulate votes at any election of directors of this corporation.
Elections for directors need not be by ballot; provided, however, that all
elections for directors must be by ballot upon demand made by a shareholder at
the meeting and before the voting begins.
In any election of directors, the candidates receiving the highest number
of votes of the shares entitled to be voted for them up to the number of
directors to be elected by such shares are elected.
Section 8. Record Date.
The Board may fix, in advance, a record date for the determination of the
shareholders entitled to notice of any meeting or to vote or entitled to receive
payment of any dividend or other distribution, or any allotment of rights, or to
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exercise rights in respect of any other lawful action. The record date so
fixed shall be not more than sixty days nor less than ten days prior to the date
of the meeting nor more than sixty days prior to any other action. When a record
date is so fixed, only shareholders of record at the close of business on that
date are entitled to notice of and to vote at the meeting or to receive the
dividend, distribution, or allotment of rights, or to exercise the rights, as
the case may be, notwithstanding any transfer of shares on the books of the
corporation after the record date, except as otherwise provided by law or these
Bylaws. A determination of shareholders of record entitled to notice of or to
vote at a meeting of shareholders shall apply to any adjournment of the meeting
unless the Board fixes a new record date for the adjourned meeting. The Board
shall fix a new record date if the meeting is adjourned for more than forty-five
days.
If no record date is fixed by the Board, the record date for determining
shareholders entitled to notice of or to vote at a meeting of shareholders shall
be at the close of business on the business day next preceding the day on which
notice is given or, if notice is waived, at the close of business on the
business day next preceding the day on which the meeting is held. The record
date for determining shareholders for any purpose other than as set forth in
this Section 8 or Section 10 of this Article shall be at the close of business
on the day on which the Board adopts the resolution relating thereto, or the
sixtieth day prior to the date of such other action, whichever is later.
Section 9. Consent of Absentees.
The transactions of any meeting of shareholders, however called and
noticed, and wherever held, are as valid as though had at a meeting duly held
after regular call and notice, if a quorum is present either in person or by
proxy, and if, either before or after the meeting, each of the persons entitled
to vote, not present in person or by proxy, signs a written waiver of notice or
a consent to the holding of the meeting or an approval of the minutes thereof.
All such waivers, consents or approvals shall be filed with the corporate
records or made a part of the minutes of the meeting. Neither the business to be
transacted at nor the purpose of any regular or special meeting of shareholders
need be specified in any written waiver of notice, consent to the holding of the
meeting or approval of the minutes thereof, except as provided in Section 601
(f) of the California General Corporation Law.
Section 10. Action Without Meeting.
Subject to Section 603 of the California General Corporation Law, any
action which, under any provision of the California General Corporation Law, may
be taken at any annual or special meeting of shareholders may be taken without a
meeting and without prior notice if a consent in writing, setting forth the
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action so taken, shall be signed by the holders of outstanding shares
having not less than the minimum number of votes that would be necessary to
authorize or take such action at a meeting at which all shares entitled to vote
thereon were present and voted. Unless a record date for voting purposes be
fixed as provided in Section 8 of this Article, the record date for determining
shareholders entitled to give consent pursuant to this Section 10, when no prior
action by the Board has been taken, shall be the day on which the first written
consent is given.
Section 11. Proxies.
Every person entitled to vote shares has the right to do so either in
person or by one or more persons, not to exceed three, designated by a proxy
authorized by such shareholder or the shareholder's attorney in fact and filed
with the corporation, in accordance with Cal. Corp. Code ss.178. Subject to the
following sentence, any proxy duly authorized continues in full force and effect
until revoked by the person authorizing it prior to the vote pursuant thereto by
a writing delivered to the corporation stating that the proxy is revoked or by a
subsequent proxy authorized by the person authorizing the prior proxy and
presented to the meeting, or by attendance at the meeting and voting in person
by the person authorizing the proxy; provided, however, that a proxy is not
revoked by the death or incapacity of the maker unless, before the vote is
counted, written notice of such death or incapacity is received by this
corporation. No proxy shall be valid after the expiration of eleven months from
the date of its authorization unless otherwise provided in the proxy.
Section 12. Inspectors of Election.
In advance of any meeting of shareholders, the Board may appoint any
persons other than nominees as inspectors of election to act at such meeting and
any adjournment thereof. If inspectors of election are not so appointed, or if
any persons so appointed fail to appear or refuse to act, the chairman of any
such meeting may, and on the request of any shareholder or shareholder's proxy
shall, make such appointments at the meeting. The number of inspectors shall be
either one or three. If appointed at a meeting on the request of one or more
shareholders or proxies, the majority of shares present shall determine whether
one or three inspectors are to be appointed.
The duties of such inspectors shall be as prescribed by Section 707 (b) of
the California General Corporation Law and shall include: determining the number
of shares outstanding and the voting power of each, the shares represented at
the meeting, the existence of a quorum, and the authenticity, validity and
effect of proxies; receiving votes, ballots or consents; hearing and determining
all challenges and questions in any way arising in connection with the right to
vote; counting and tabulating all votes or consents; determining when
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the polls shall close; determining the result; and doing such acts as may
be proper to conduct the election or vote with fairness to all shareholders. If
there are three inspectors of election, the decision, act or certificate of a
majority is effective in all respects as the decision, act or certificate of
all. Any report or certificate made by the inspectors of election is prima facie
evidence of the facts stated therein.
ARTICLE III -- DIRECTORS
Section 1. Powers.
Subject to limitations of the Articles, of these Bylaws and of the
California General Corporation Law relating to action required to be approved by
the shareholders or by the outstanding shares, the business and affairs of the
corporation shall be managed and all corporate powers shall be exercised by or
under the direction of the Board. The Board may delegate the management of the
day-to-day operation of the business of the corporation provided that the
business and affairs of the corporation shall be managed and all corporate
powers shall be exercised under the ultimate direction of the Board. Without
prejudice to such general powers, but subject to the same limitations, it is
hereby expressly declared that the Board shall have the following powers in
addition to the other powers enumerated in these Bylaws:
(a) To select and remove all the other officers, agents and employees of
the corporation, prescribe the powers and duties for them as may not be
inconsistent with law, with the Articles or these Bylaws, fix their compensation
and require from them security for faithful service.
(b) To conduct, manage and control the affairs and business of the
corporation and to make such rules and regulations therefor not inconsistent
with law, or with the Articles or these Bylaws, as they may deem best.
(c) To adopt, make and use a corporate seal, and to prescribe the forms of
certificates of stock, and to alter the form of such seal and of such
certificates from time to time as in their judgment they may deem best.
(d) To authorize the issuance of shares of stock of the corporation from
time to time, upon such terms and for such consideration as may be lawful.
(e) To borrow money and incur indebtedness for the purposes of the
corporation, and to cause to be executed and delivered therefor, in the
corporate name, promissory notes, bonds, debentures, deeds of trust, mortgages,
pledges, hypothecations or other evidences of debt and securities therefor.
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Section 2. Number of Directors.
The authorized number of directors shall be not less than nine nor more
than seventeen until changed by amendment of the Articles or by a Bylaw duly
adopted by the shareholders. The exact number of directors shall be fixed,
within the limits specified, by the Board by adoption of a resolution or by the
shareholders in the same manner provided in these Bylaws for the amendment
thereof.
Section 3. Election and Term of Office.
The directors shall be elected at each annual meeting of the shareholders,
but if any such annual meeting is not held or the directors are not elected
thereat, the directors may be elected at any special meeting of shareholders
held for that purpose. Each director shall hold office until the next annual
meeting and until a successor has been elected and qualified.
Section 4. Vacancies.
Any director may resign effective upon giving written notice to the
Chairman of the Board, the President, the Secretary or the Board, unless the
notice specifies a later time for the effectiveness of such resignation. If the
resignation is effective at a future time, a successor may be elected to take
office when the resignation becomes effective.
Vacancies in the Board, except those existing as a result of a removal of a
director, may be filled by a majority of the remaining directors, though less
than a quorum, or by a sole remaining director, and each director so elected
shall hold office until the next annual meeting and until such director's
successor has been elected and qualified. Vacancies existing as a result of a
removal of a director may be filled by the shareholders as provided by law.
A vacancy or vacancies in the Board shall be deemed to exist in case of the
death, resignation or removal of any director, or if the authorized number of
directors be increased, or if the shareholders fail, at any annual or special
meeting of shareholders at which any director or directors are elected, to elect
the full authorized number of directors to be voted for at that meeting.
The Board may declare vacant the office of a director who has been declared
of unsound mind by an order of court or convicted of a felony.
The shareholders may elect a director or directors at any time to fill any
vacancy or vacancies not filled by the directors. Any such election by written
consent other than to fill a vacancy created by removal requires the consent of
a
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majority of the outstanding shares entitled to vote. If the Board accepts
the resignation of a director tendered to take effect at a future time, the
Board or the shareholders shall have power to elect a successor to take office
when the resignation is to become effective.
No reduction of the authorized number of directors shall have the effect of
removing any director prior to the expiration of the director's term of office.
Section 5. Place of Meeting.
Regular or special meetings of the Board shall be held at any place within
or without the State of California which has been designated from time to time
by the Board or as provided in these Bylaws. In the absence of such designation,
regular meetings shall be held at the principal office of the corporation.
Section 6. Regular Meetings.
Promptly following each annual meeting of shareholders the Board shall hold
a regular meeting for the purpose of organization, election of officers and the
transaction of other business.
Regular meetings of the Board shall be held at the principal office of the
corporation without notice on the third Thursday of the months of February,
April, May, July and September, and on the second Thursday in December, at the
hour of 9:00 a.m. or as soon thereafter as the regular meeting of the Board of
Directors of Edison International is adjourned, and on the third Thursday in
March, at the hour of 8:00 a.m. or as soon thereafter as the regular meeting of
the Board of Directors of Edison International is adjourned. Call and notice of
all regular meetings of the Board are not required.
Section 7. Special Meetings.
Special meetings of the Board for any purpose or purposes may be called at
any time by the Chairman of the Board, the President, any Vice President, the
Secretary or by any two directors.
Special meetings of the Board shall be held upon four days' written notice
or forty-eight hours' notice given personally or by telephone, telegraph, telex,
facsimile, electronic mail or other similar means of communication. Any such
notice shall be addressed or delivered to each director at such director's
address as it is shown upon the records of the corporation or as may have been
given to the corporation by the director for purposes of notice or, if such
address is not shown on such records or is not readily ascertainable, at the
place in which the
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meetings of the directors are regularly held. The notice need not specify
the purpose of such special meeting.
Notice by mail shall be deemed to have been given at the time a written
notice is deposited in the United States mail, postage prepaid. Any other
written notice shall be deemed to have been given at the time it is personally
delivered to the recipient or is delivered to a common carrier for transmission,
or actually transmitted by the person giving the notice by electronic means to
the recipient. Oral notice shall be deemed to have been given at the time it is
communicated, in person or by telephone, radio or other similar means to the
recipient or to a person at the office of the recipient who the person giving
the notice has reason to believe will promptly communicate it to the recipient.
Section 8. Quorum.
One-third of the number of authorized directors constitutes a quorum of the
Board for the transaction of business, except to adjourn as provided in Section
ll of this Article. Every act or decision done or made by a majority of the
directors present at a meeting duly held at which a quorum is present shall be
regarded as the act of the Board, unless a greater number is required by law or
by the Articles; provided, however, that a meeting at which a quorum is
initially present may continue to transact business notwithstanding the
withdrawal of directors, if any action taken is approved by at least a majority
of the required quorum for such meeting.
Section 9. Participation in Meetings by Conference Telephone.
Members of the Board may participate in a meeting through use of conference
telephone or similar communications equipment, so long as all members
participating in such meeting can hear one another. Such participation
constitutes presence in person at such meeting.
Section 10. Waiver of Notice.
The transactions of any meeting of the Board, however called and noticed or
wherever held, are as valid as though had at a meeting duly held after regular
call and notice if a quorum is present and if, either before or after the
meeting, each of the directors not present signs a written waiver of notice, a
consent to holding such meeting or an approval of the minutes thereof. All such
waivers, consents or approvals shall be filed with the corporate records or made
a part of the minutes of the meeting.
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Section 11. Adjournment.
A majority of the directors present, whether or not a quorum is present,
may adjourn any directors' meeting to another time and place. Notice of the time
and place of holding an adjourned meeting need not be given to absent directors
if the time and place is fixed at the meeting adjourned. If the meeting is
adjourned for more than twenty-four hours, notice of any adjournment to another
time or place shall be given prior to the time of the adjourned meeting to the
directors who were not present at the time of the adjournment.
Section 12. Fees and Compensation.
Directors and members of committees may receive such compensation, if any,
for their services, and such reimbursement for expenses, as may be fixed or
determined by the Board.
Section 13. Action Without Meeting.
Any action required or permitted to be taken by the Board may be taken
without a meeting if all members of the Board shall individually or collectively
consent in writing to such action. Such written consent or consents shall have
the same force and effect as a unanimous vote of the Board and shall be filed
with the minutes of the proceedings of the Board.
Section 14. Rights of Inspection.
Every director shall have the absolute right at any reasonable time to
inspect and copy all books, records and documents of every kind and to inspect
the physical properties of the corporation and also of its subsidiary
corporations, domestic or foreign. Such inspection by a director may be made in
person or by agent or attorney and includes the right to copy and make extracts.
Section 15. Committees.
The Board may appoint one or more committees, each consisting of two or
more directors, to serve at the pleasure of the Board. The Board may delegate to
such committees any or all of the authority of the Board except with respect to:
(a) The approval of any action for which the California General Corporation
Law also requires shareholders' approval or approval of the outstanding shares;
(b) The filling of vacancies on the Board or in any committee;
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(c) The fixing of compensation of the directors for serving on the Board or
on any committee;
(d) The amendment or repeal of Bylaws or the adoption of new Bylaws;
(e) The amendment or repeal of any resolution of the Board which by its
express terms is not so amendable or repealable;
(f) A distribution to the shareholders of the corporation except at a rate
or in a periodic amount or within a price range determined by the Board; or
(g) The appointment of other committees of the Board or the members
thereof.
Any such committee, or any member or alternate member thereof, must be
appointed by resolution adopted by a majority of the exact number of authorized
directors as specified in Section 2 of this Article. The Board shall have the
power to prescribe the manner and timing of giving of notice of regular or
special meetings of any committee and the manner in which proceedings of any
committee shall be conducted. In the absence of any such prescription, such
committee shall have the power to prescribe the manner in which its proceedings
shall be conducted. Unless the Board or such committee shall otherwise provide,
the regular and special meetings and other actions of any such committee shall
be governed by the provisions of this Article applicable to meetings and actions
of the Board. Minutes shall be kept of each meeting of each committee.
ARTICLE IV -- OFFICERS
Section 1. Officers.
The officers of the corporation shall be a Chairman of the Board, a
President, a Chief Financial Officer, one or more Vice Presidents, a General
Counsel, one or more Associate General Counsel, one or more Assistant General
Counsel, a Controller, one or more Assistant Controllers, a Treasurer, one or
more Assistant Treasurers, a Secretary and one or more Assistant Secretaries,
and such other officers as may be elected or appointed in accordance with
Section 5 of this Article. The Board, the Chairman of the Board or the President
may confer a special title upon any Vice President not specified herein. Any
number of offices of the corporation may be held by the same person.
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Section 2. Election.
The officers of the corporation, except such officers as may be elected or
appointed in accordance with the provisions of Section 5 or Section 6 of this
Article, shall be chosen annually by, and shall serve at the pleasure of the
Board, and shall hold their respective offices until their resignation, removal,
or other disqualification from service, or until their respective successors
shall be elected.
Section 3. Eligibility of Chairman or President.
No person shall be eligible for the office of Chairman of the Board or
President unless such person is a member of the Board of the corporation; any
other officer may or may not be a director.
Section 4. Removal and Resignation.
Any officer may be removed, either with or without cause, by the Board at
any time or by any officer upon whom such power or removal may be conferred by
the Board. Any such removal shall be without prejudice to the rights, if any, of
the officer under any contract of employment of the officer.
Any officer may resign at any time by giving written notice to the
corporation, but without prejudice to the rights, if any, of the corporation
under any contract to which the officer is a party. Any such resignation shall
take effect at the date of the receipt of such notice or at any later time
specified therein and, unless otherwise specified therein, the acceptance of
such resignation shall not be necessary to make it effective.
Section 5. Appointment of Other Officers.
The Board may appoint such other officers as the business of the
corporation may require, each of whom shall hold office for such period, have
such authority, and perform such duties as are provided in the Bylaws or as the
Board may from time to time determine.
Section 6. Vacancies.
A vacancy in any office because of death, resignation, removal,
disqualification or any other cause shall be filled at any time deemed
appropriate by the Board in the manner prescribed in these Bylaws for regular
election or appointment to such office.
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Section 7. Salaries.
The salaries of the Chairman of the Board, President, Chief Financial
Officer, Vice Presidents, General Counsel, Controller, Treasurer and Secretary
of the corporation shall be fixed by the Board. Salaries of all other officers
shall be as approved from time to time by the chief executive officer.
Section 8. Furnish Security for Faithfulness.
Any officer or employee shall, if required by the Board, furnish to the
corporation security for faithfulness to the extent and of the character that
may be required.
Section 9. Chairman's Duties; Succession to Such Duties in Chairman's
Absence or Disability.
The Chairman of the Board shall be the chief executive officer of the
corporation and shall preside at all meetings of the shareholders and of the
Board. Subject to the Board, the Chairman of the Board shall have charge of the
business of the corporation, including the construction of its plants and
properties and the operation thereof. The Chairman of the Board shall keep the
Board fully informed, and shall freely consult them concerning the business of
the corporation.
In the absence or disability of the Chairman of the Board, the President
shall act as the chief executive officer of the corporation; in the absence or
disability of the Chairman of the Board and the President, the next in order of
election by the Board of the Vice Presidents shall act as chief executive
officer of the corporation.
In the absence or disability of the Chairman of the Board, the President
shall act as Chairman of the Board at meetings of the Board; in the absence or
disability of the Chairman of the Board and the President, the next, in order of
election by the Board, of the Vice Presidents who is a member of the Board shall
act as Chairman of the Board at any such meeting of the Board; in the absence or
disability of the Chairman of the Board, the President, and such Vice Presidents
who are members of the Board, the Board shall designate a temporary Chairman to
preside at any such meeting of the Board.
Section 10. President's Duties.
The President shall perform such other duties as the Chairman of the Board
shall delegate or assign to such officer.
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Section 11. Chief Financial Officer.
The Chief Financial Officer of the corporation shall be the chief
consulting officer in all matters of financial import and shall have control
over all financial matters concerning the corporation.
Section 12. Vice Presidents' Duties.
The Vice Presidents shall perform such other duties as the chief executive
officer shall designate.
Section 13. General Counsel's Duties.
The General Counsel shall be the chief consulting officer of the
corporation in all legal matters and, subject to the chief executive officer,
shall have control over all matters of legal import concerning the corporation.
Section 14. Associate General Counsel's and Assistant
General Counsel's Duties.
The Associate General Counsel shall perform such of the duties of the
General Counsel as the General Counsel shall designate, and in the absence or
disability of the General Counsel, the Associate General Counsel, in order of
election to that office by the Board at its latest organizational meeting, shall
perform the duties of the General Counsel. The Assistant General Counsel shall
perform such duties as the General Counsel shall designate.
Section 15. Controller's Duties.
The Controller shall be the chief accounting officer of the Corporation
and, subject to the Chief Financial Officer, shall have control over all
accounting matters concerning the Corporation and shall perform such other
duties as the Chief Executive Officer shall designate.
Section 16. Assistant Controllers' Duties.
The Assistant Controllers shall perform such of the duties of the
Controller as the Controller shall designate, and in the absence or disability
of the Controller, the Assistant Controllers, in order of election to that
office by the Board at its latest organizational meeting, shall perform the
duties of the Controller.
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Section 17. Treasurer's Duties.
It shall be the duty of the Treasurer to keep in custody or control all
money, stocks, bonds, evidences of debt, securities and other items of value
that may belong to, or be in the possession or control of, the corporation, and
to dispose of the same in such manner as the Board or the chief executive
officer may direct, and to perform all acts incident to the position of
Treasurer.
Section 18. Assistant Treasurers' Duties.
The Assistant Treasurers shall perform such of the duties of the Treasurer
as the Treasurer shall designate, and in the absence or disability of the
Treasurer, the Assistant Treasurers, in order of election to that office by the
Board at its latest organizational meeting, shall perform the duties of the
Treasurer, unless action is taken by the Board as contemplated in Article IV,
Section 22.
Section 19. Secretary's Duties.
The Secretary shall keep or cause to be kept full and complete records of
the proceedings of shareholders, the Board and its committees at all meetings,
and shall affix the corporate seal and attest by signing copies of any part
thereof when required.
The Secretary shall keep, or cause to be kept, a copy of the Bylaws of the
corporation at the principal office in accordance with Section 213 of the
California General Corporation Law.
The Secretary shall be the custodian of the corporate seal and shall affix
it to such instruments as may be required.
The Secretary shall keep on hand a supply of blank stock certificates of
such forms as the Board may adopt.
The Secretary shall serve or cause to be served by publication or
otherwise, as may be required, all notices of meetings and of other corporate
acts that may by law or otherwise be required to be served, and shall make or
cause to be made and filed in the principal office of the corporation, the
necessary certificate or proofs thereof.
An affidavit of mailing of any notice of a shareholders' meeting or of any
report, in accordance with the provisions of Section 601 (b) of the California
General Corporation Law, executed by the Secretary shall be prima facie evidence
of the fact that such notice or report had been duly given.
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The Secretary may, with the Chairman of the Board, the President, or a Vice
President, sign certificates of ownership of stock in the corporation, and shall
cause all certificates so signed to be delivered to those entitled thereto.
The Secretary shall keep all records required by the California General
Corporation Law.
The Secretary shall generally perform the duties usual to the office of
secretary of corporations, and such other duties as the chief executive officer
shall designate.
Section 20. Assistant Secretaries' Duties.
Assistant Secretaries shall perform such of the duties of the Secretary as
the Secretary shall designate, and in the absence or disability of the
Secretary, the Assistant Secretaries, in the order of election to that office by
the Board at its latest organizational meeting, shall perform the duties of the
Secretary, unless action is taken by the Board as contemplated in Article IV,
Sections 21 and 22 of these Bylaws.
Section 21. Secretary Pro Tempore.
At any meeting of the Board or of the shareholders from which the Secretary
is absent, a Secretary pro tempore may be appointed and act.
Section 22. Election of Acting Treasurer or Acting Secretary.
The Board may elect an Acting Treasurer, who shall perform all the duties
of the Treasurer during the absence or disability of the Treasurer, and who
shall hold office only for such a term as shall be determined by the Board.
The Board may elect an Acting Secretary, who shall perform all the duties
of the Secretary during the absence or disability of the Secretary, and who
shall hold office only for such a term as shall be determined by the Board.
Whenever the Board shall elect either an Acting Treasurer or Acting
Secretary, or both, the officers of the corporation as set forth in Article IV,
Section 1 of these Bylaws, shall include as if therein specifically set out, an
Acting Treasurer or an Acting Secretary, or both.
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Section 23. Performance of Duties.
Officers shall perform the duties of their respective offices as stated in
these Bylaws, and such additional duties as the Board shall designate.
ARTICLE V -- OTHER PROVISIONS
Section 1. Inspection of Corporate Records.
(a) A shareholder or shareholders holding at least five percent in the
aggregate of the outstanding voting shares of the corporation or who hold at
least one percent of such voting shares and have filed a Schedule 14B with the
United States Securities and Exchange Commission relating to the election of
directors of the corporation shall have an absolute right to do either or both
of the following:
(i) Inspect and copy the record of shareholders' names and addresses and
shareholdings during usual business hours upon five business days'
prior written demand upon the corporation; or
(ii) Obtain from the transfer agent, if any, for the corporation, upon five
business days' prior written demand and upon the tender of its usual
charges for such a list (the amount of which charges shall be stated
to the shareholder by the transfer agent upon request), a list of the
shareholders' names and addresses who are entitled to vote for the
election of directors and their shareholdings, as of the most recent
record date for which it has been compiled or as of a date specified
by the shareholder subsequent to the date of demand.
(b) The record of shareholders shall also be open to inspection and copying
by any shareholder or holder of a voting trust certificate at any time during
usual business hours upon written demand on the corporation, for a purpose
reasonably related to such holder's interest as a shareholder or holder of a
voting trust certificate.
(c) The accounting books and records and minutes of proceedings of the
shareholders and the Board and committees of the Board shall be open to
inspection upon written demand on the corporation of any shareholder or holder
of a voting trust certificate at any reasonable time during usual business
hours, for a purpose reasonably related to such holder's interests as a
shareholder or as a holder of such voting trust certificate.
20
(d) Any such inspection and copying under this Article may be made in
person or by agent or attorney.
Section 2. Inspection of Bylaws.
The corporation shall keep in its principle office the original or a copy
of these Bylaws as amended to date, which shall be open to inspection by
shareholders at all reasonable times during office hours.
Section 3. Contracts and Other Instruments, Loans, Notes and
Deposits of Funds.
The Chairman of the Board, the President, or a Vice President, either alone
or with the Secretary or an Assistant Secretary, or the Secretary alone, shall
execute in the name of the corporation such written instruments as may be
authorized by the Board and, without special direction of the Board, such
instruments as transactions of the ordinary business of the corporation may
require and, such officers without the special direction of the Board may
authenticate, attest or countersign any such instruments when deemed
appropriate. The Board may authorize any person, persons, entity, entities,
attorney, attorneys, attorney-in-fact, attorneys-in-fact, agent or agents, to
enter into any contract or execute and deliver any instrument in the name of and
on behalf of the corporation, and such authority may be general or confined to
specific instances.
No loans shall be contracted on behalf of the corporation and no evidences
of such indebtedness shall be issued in its name unless authorized by the Board
as it may direct. Such authority may be general or confined to specific
instances.
All checks, drafts, or other similar orders for the payment of money,
notes, or other such evidences of indebtedness issued in the name of the
corporation shall be signed by such officer or officers, agent or agents of the
corporation and in such manner as the Board or chief executive officer may
direct.
Unless authorized by the Board or these Bylaws, no officer, agent, employee
or any other person or persons shall have any power or authority to bind the
corporation by any contract or engagement or to pledge its credit or to render
it liable for any purpose or amount.
All funds of the corporation not otherwise employed shall be deposited from
time to time to the credit of the corporation in such banks, trust companies, or
other depositories as the Board may direct.
21
Section 4. Certificates of Stock.
Every holder of shares of the corporation shall be entitled to have a
certificate signed in the name of the corporation by the Chairman of the Board,
the President, or a Vice President and by the Treasurer or an Assistant
Treasurer or the Secretary or an Assistant Secretary, certifying the number of
shares and the class or series of shares owned by the shareholder. Any or all of
the signatures on the certificate may be facsimile. In case any officer,
transfer agent or registrar who has signed or whose facsimile signature has been
placed upon a certificate shall have ceased to be such officer, transfer agent
or registrar before such certificate is issued, it may be issued by the
corporation with the same effect as if such person were an officer, transfer
agent or registrar at the date of issue.
Certificates for shares may be used prior to full payment under such
restrictions and for such purposes as the Board may provide; provided, however,
that on any certificate issued to represent any partly paid shares, the total
amount of the consideration to be paid therefor and the amount paid thereon
shall be stated.
Except as provided in this Section, no new certificate for shares shall be
issued in lieu of an old one unless the latter is surrendered and canceled at
the same time. The Board may, however, if any certificate for shares is alleged
to have been lost, stolen or destroyed, authorize the issuance of a new
certificate in lieu thereof, and the corporation may require that the
corporation be given a bond or other adequate security sufficient to indemnify
it against any claim that may be made against it (including expense or
liability) on account of the alleged loss, theft or destruction of such
certificate or the issuance of such new certificate.
Section 5. Transfer Agent, Transfer Clerk and Registrar.
The Board may, from time to time, appoint transfer agents, transfer clerks,
and stock registrars to transfer and register the certificates of the capital
stock of the corporation, and may provide that no certificate of capital stock
shall be valid without the signature of the stock transfer agent or transfer
clerk, and stock registrar.
Section 6. Representation of Shares of Other Corporations.
The chief executive officer or any other officer or officers authorized by
the Board or the chief executive officer are each authorized to vote, represent
and exercise on behalf of the corporation all rights incident to any and all
shares of any other corporation or corporations standing in the name of the
corporation.
22
The authority herein granted may be exercised either by any such officer in
person or by any other person authorized so to do by proxy or power of attorney
duly executed by said officer.
Section 7. Stock Purchase Plans.
The corporation may adopt and carry out a stock purchase plan or agreement
or stock option plan or agreement providing for the issue and sale for such
consideration as may be fixed of its unissued shares, or of issued shares
acquired, to one or more of the employees or directors of the corporation or of
a subsidiary or to a trustee on their behalf and for the payment for such shares
in installments or at one time, and may provide for such shares in installments
or at one time, and may provide for aiding any such persons in paying for such
shares by compensation for services rendered, promissory notes or otherwise.
Any such stock purchase plan or agreement or stock option plan or agreement
may include, among other features, the fixing of eligibility for participation
therein, the class and price of shares to be issued or sold under the plan or
agreement, the number of shares which may be subscribed for, the method of
payment therefor, the reservation of title until full payment therefor, the
effect of the termination of employment and option or obligation on the part of
the corporation to repurchase the shares upon termination of employment,
restrictions upon transfer of the shares, the time limits of and termination of
the plan, and any other matters, not in violation of applicable law, as may be
included in the plan as approved or authorized by the Board or any committee of
the Board.
Section 8. Fiscal Year and Subdivisions.
The calendar year shall be the corporate fiscal year of the corporation.
For the purpose of paying dividends, for making reports and for the convenient
transaction of the business of the corporation, the Board may divide the fiscal
year into appropriate subdivisions.
Section 9. Construction and Definitions.
Unless the context otherwise requires, the general provisions, rules of
construction and definitions contained in the General Provisions of the
California Corporations Code and in the California General Corporation Law shall
govern the construction of these Bylaws.
23
ARTICLE VI -- INDEMNIFICATION
Section 1. Indemnification of Directors and Officers.
Each person who was or is a party or is threatened to be made a party to or
is involved in any threatened, pending or completed action, suit or proceeding,
formal or informal, whether brought in the name of the corporation or otherwise
and whether of a civil, criminal, administrative or investigative nature
(hereinafter a "proceeding"), by reason of the fact that he or she, or a person
of whom he or she is the legal representative, is or was a director or officer
of the corporation or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation or of a partnership,
joint venture, trust or other enterprise, including service with respect to
employee benefit plans, whether the basis of such proceeding is an alleged
action or inaction in an official capacity or in any other capacity while
serving as a director or officer, shall, subject to the terms of any agreement
between the corporation and such person, be indemnified and held harmless by the
corporation to the fullest extent permissible under California law and the
corporation's Articles of Incorporation, against all costs, charges, expenses,
liabilities and losses (including attorneys' fees, judgments, fines, ERISA
excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith, and such
indemnification shall continue as to a person who has ceased to be a director or
officer and shall inure to the benefit of his or her heirs, executors and
administrators; provided, however, that (A) the corporation shall indemnify any
such person seeking indemnification in connection with a proceeding (or part
thereof) initiated by such person only if such proceeding (or part thereof) was
authorized by the Board of the corporation; (B) the corporation shall indemnify
any such person seeking indemnification in connection with a proceeding (or part
thereof) other than a proceeding by or in the name of the corporation to procure
a judgment in its favor only if any settlement of such a proceeding is approved
in writing by the corporation; (C) that no such person shall be indemnified (i)
except to the extent that the aggregate of losses to be indemnified exceeds the
amount of such losses for which the director or officer is paid pursuant to any
directors' and officers' liability insurance policy maintained by the
corporation; (ii) on account of any suit in which judgment is rendered against
such person for an accounting of profits made from the purchase or sale by such
person of securities of the corporation pursuant to the provisions of Section
16(b) of the Securities Exchange Act of 1934 and amendments thereto or similar
provisions of any federal, state or local statutory law; (iii) if a court of
competent jurisdiction finally determines that any indemnification hereunder is
unlawful; and (iv) as to circumstances in which indemnity is expressly
prohibited by Section 317 of the General Corporation Law of California (the
"Law"); and (D) that no such person shall be indemnified with regard to any
action brought by or in the right of the corporation for breach of duty to the
corporation and its
24
shareholders (a) for acts or omissions involving intentional misconduct or
knowing and culpable violation of law; (b) for acts or omissions that the
director or officer believes to be contrary to the best interests of the
corporation or its shareholders or that involve the absence of good faith on the
part of the director or officer; (c) for any transaction from which the director
or officer derived an improper personal benefit; (d) for acts or omissions that
show a reckless disregard for the director's or officer's duty to the
corporation or its shareholders in circumstances in which the director or
officer was aware, or should have been aware, in the ordinary course of
performing his or her duties, of a risk of serious injury to the corporation or
its shareholders; (e) for acts or omissions that constitute an unexcused pattern
of inattention that amounts to an abdication of the director's or officer's
duties to the corporation or its shareholders; and (f) for costs, charges,
expenses, liabilities and losses arising under Section 310 or 316 of the Law.
The right to indemnification conferred in this Article shall include the right
to be paid by the corporation expenses incurred in defending any proceeding in
advance of its final disposition; provided, however, that if the Law permits the
payment of such expenses incurred by a director or officer in his or her
capacity as a director or officer (and not in any other capacity in which
service was or is rendered by such person while a director or officer,
including, without limitation, service to an employee benefit plan) in advance
of the final disposition of a proceeding, such advances shall be made only upon
delivery to the corporation of an undertaking, by or on behalf of such director
or officer, to repay all amounts to the corporation if it shall be ultimately
determined that such person is not entitled to be indemnified.
Section 2. Indemnification of Employees and Agents.
A person who was or is a party or is threatened to be made a party to or is
involved in any proceeding by reason of the fact that he or she is or was an
employee or agent of the corporation or is or was serving at the request of the
corporation as an employee or agent of another enterprise, including service
with respect to employee benefit plans, whether the basis of such action is an
alleged action or inaction in an official capacity or in any other capacity
while serving as an employee or agent, may, subject to the terms of any
agreement between the corporation and such person, be indemnified and held
harmless by the corporation to the fullest extent permitted by California law
and the corporation's Articles of Incorporation, against all costs, charges,
expenses, liabilities and losses, (including attorneys' fees, judgments, fines,
ERISA excise taxes or penalties and amounts paid or to be paid in settlement)
reasonably incurred or suffered by such person in connection therewith.
25
Section 3. Right of Directors and Officers to Bring Suit.
If a claim under Section 1 of this Article is not paid in full by the
corporation within 30 days after a written claim has been received by the
corporation, the claimant may at any time thereafter bring suit against the
corporation to recover the unpaid amount of the claim and, if successful in
whole or in part, the claimant shall also be entitled to be paid the expense of
prosecuting such claim. Neither the failure of the corporation (including its
Board, independent legal counsel, or its shareholders) to have made a
determination prior to the commencement of such action that indemnification of
the claimant is permissible in the circumstances because he or she has met the
applicable standard of conduct, if any, nor an actual determination by the
corporation (including its Board, independent legal counsel, or its
shareholders) that the claimant has not met the applicable standard of conduct,
shall be a defense to the action or create a presumption for the purpose of an
action that the claimant has not met the applicable standard of conduct.
Section 4. Successful Defense.
Notwithstanding any other provision of this Article, to the extent that a
director or officer has been successful on the merits or otherwise (including
the dismissal of an action without prejudice or the settlement of a proceeding
or action without admission of liability) in defense of any proceeding referred
to in Section 1 or in defense of any claim, issue or matter therein, he or she
shall be indemnified against expenses (including attorneys' fees) actually and
reasonably incurred in connection therewith.
Section 5. Non-Exclusivity of Rights.
The right to indemnification provided by this Article shall not be
exclusive of any other right which any person may have or hereafter acquire
under any statute, bylaw, agreement, vote of shareholders or disinterested
directors or otherwise.
Section 6. Insurance.
The corporation may maintain insurance, at its expense, to protect itself
and any director, officer, employee or agent of the corporation or another
corporation, partnership, joint venture, trust or other enterprise against any
expense, liability or loss, whether or not the corporation would have the power
to indemnify such person against such expense, liability or loss under the Law.
26
Section 7. Expenses as a Witness.
To the extent that any director, officer, employee or agent of the
corporation is by reason of such position, or a position with another entity at
the request of the corporation, a witness in any action, suit or proceeding, he
or she shall be indemnified against all costs and expenses actually and
reasonably incurred by him or her on his or her behalf in connection therewith.
Section 8. Indemnity Agreements.
The corporation may enter into agreements with any director, officer,
employee or agent of the corporation providing for indemnification to the
fullest extent permissible under the Law and the corporation's Articles of
Incorporation.
Section 9. Separability.
Each and every paragraph, sentence, term and provision of this Article is
separate and distinct so that if any paragraph, sentence, term or provision
hereof shall be held to be invalid or unenforceable for any reason, such
invalidity or unenforceability shall not affect the validity or enforceability
of any other paragraph, sentence, term or provision hereof. To the extent
required, any paragraph, sentence, term or provision of this Article may be
modified by a court of competent jurisdiction to preserve its validity and to
provide the claimant with, subject to the limitations set forth in this Article
and any agreement between the corporation and claimant, the broadest possible
indemnification permitted under applicable law.
Section 10. Effect of Repeal or Modification.
Any repeal or modification of this Article shall not adversely affect any
right of indemnification of a director or officer existing at the time of such
repeal or modification with respect to any action or omission occurring prior to
such repeal or modification.
ARTICLE VII -- EMERGENCY PROVISIONS
Section 1. General.
The provisions of this Article shall be operative only during a national
emergency declared by the President of the United States or the person
performing the President's functions, or in the event of a nuclear, atomic or
other attack on the United States or a disaster making it impossible or
impracticable for the corporation to conduct its business without recourse to
the provisions of this
27
Article. Said provisions in such event shall override all other Bylaws of
the corporation in conflict with any provisions of this Article, and shall
remain operative so long as it remains impossible or impracticable to continue
the business of the corporation otherwise, but thereafter shall be inoperative;
provided that all actions taken in good faith pursuant to such provisions shall
thereafter remain in full force and effect unless and until revoked by action
taken pursuant to the provisions of the Bylaws other than those contained in
this Article.
Section 2. Unavailable Directors.
All directors of the corporation who are not available to perform their
duties as directors by reason of physical or mental incapacity or for any other
reason or who are unwilling to perform their duties or whose whereabouts are
unknown shall automatically cease to be directors, with like effect as if such
persons had resigned as directors, so long as such unavailability continues.
Section 3. Authorized Number of Directors.
The authorized number of directors shall be the number of directors
remaining after eliminating those who have ceased to be directors pursuant to
Section 2, or the minimum number required by law, whichever number is greater.
Section 4. Quorum.
The number of directors necessary to constitute a quorum shall be one-third
of the authorized number of directors as specified in the foregoing Section, or
such other minimum number as, pursuant to the law or lawful decree then in
force, it is possible for the Bylaws of a corporation to specify.
Section 5. Creation of Emergency Committee.
In the event the number of directors remaining after eliminating those who
have ceased to be directors pursuant to Section 2 is less than the minimum
number of authorized directors required by law, then until the appointment of
additional directors to make up such required minimum, all the powers and
authorities which the Board could by law delegate, including all powers and
authorities which the Board could delegate to a committee, shall be
automatically vested in an emergency committee, and the emergency committee
shall thereafter manage the affairs of the corporation pursuant to such powers
and authorities and shall have all other powers and authorities as may by law or
lawful decree be conferred on any person or body of persons during a period of
emergency.
28
Section 6. Constitution of Emergency Committee.
The emergency committee shall consist of all the directors remaining after
eliminating those who have ceased to be directors pursuant to Section 2,
provided that such remaining directors are not less than three in number. In the
event such remaining directors are less than three in number the emergency
committee shall consist of three persons, who shall be the remaining director or
directors and either one or two officers or employees of the corporation, as the
remaining director or directors may in writing designate. If there is no
remaining director, the emergency committee shall consist of the three most
senior officers of the corporation who are available to serve, and if and to the
extent that officers are not available, the most senior employees of the
corporation. Seniority shall be determined in accordance with any designation of
seniority in the minutes of the proceedings of the Board, and in the absence of
such designation, shall be determined by rate of remuneration. In the event that
there are no remaining directors and no officers or employees of the corporation
available, the emergency committee shall consist of three persons designated in
writing by the shareholder owning the largest number of shares of record as of
the date of the last record date.
Section 7. Powers of Emergency Committee.
The emergency committee, once appointed, shall govern its own procedures
and shall have power to increase the number of members thereof beyond the
original number, and in the event of a vacancy or vacancies therein, arising at
any time, the remaining member or members of the emergency committee shall have
the power to fill such vacancy or vacancies. In the event at any time after its
appointment all members of the emergency committee shall die or resign or become
unavailable to act for any reason whatsoever, a new emergency committee shall be
appointed in accordance with the foregoing provisions of this Article.
Section 8. Directors Becoming Available.
Any person who has ceased to be a director pursuant to the provisions of
Section 2 and who thereafter becomes available to serve as a director shall
automatically become a member of the emergency committee.
Section 9. Election of Board of Directors.
The emergency committee shall, as soon after its appointment as is
practicable, take all requisite action to secure the election of a board of
directors,
29
and upon such election all the powers and authorities of the emergency
committee shall cease.
Section 10. Termination of Emergency Committee.
In the event, after the appointment of an emergency committee, a sufficient
number of persons who ceased to be directors pursuant to Section 2 become
available to serve as directors, so that if they had not ceased to be directors
as aforesaid, there would be enough directors to constitute the minimum number
of directors required by law, then all such persons shall automatically be
deemed to be reappointed as directors and the powers and authorities of the
emergency committee shall be at an end.
ARTICLE VIII -- AMENDMENTS
Section 1. Amendments.
These Bylaws may be amended or repealed either by approval of the
outstanding shares or by the approval of the Board; provided, however, that a
Bylaw specifying or changing a fixed number of directors or the maximum or
minimum number or changing from a fixed to a variable Board or vice versa may
only be adopted by approval of the outstanding shares. The exact number of
directors within the maximum and minimum number specified in these Bylaws may be
amended by the Board alone.
SOUTHERN CALIFORNIA EDISON COMPANY AND CONSOLIDATED UTILITY-RELATED SUBSIDIARIES
RATIOS OF EARNINGS TO FIXED CHARGES AND PREFERRED AND PREFERENCE STOCK
(Thousands of Dollars)
Year Ended December 31,
------------------------------------------------------------------------------------
1994 1995 1996 1997 1998 1999
--------- ---------- ---------- -------- ---------- ----------
EARNINGS BEFORE INCOME TAXES
AND FIXED CHARGES:
Income before interest expense(1) $1,081,800 $1,143,477 $1,108,410 $1,049,866 $999,910 $ 992,354
Add:
Taxes on income (2) 452,091 509,632 511,819 520,468 442,356 438,006
Rentals(3) 3,512 4,018 3,269 2,639 2,208 1,901
Allocable portion of interest
on long-term-term Contracts
for the purchase of power 1,870 1,848 1,824 1,797 1,767 1,735
Spent nuclear fuel interest(6) 68 - - - - -
Amortization of previously
capitalized fixed charges 2,271 1,185 814 1,127 1,571 1,508
- -----------------------------------------------------------------------------------------------------------------------
Total earnings before income
Taxes and fixed charges(A) $1,541,612 $1,660,160 $1,626,136 $1,575,897 $1,447,812 $1,435,504
- -----------------------------------------------------------------------------------------------------------------------
FIXED CHARGES:
Interest and amortization $ 443,219 $ 463,786 $ 453,015 $ 444,272 $ 484,788 $ 482,933
Rentals(3) 3,512 4,018 3,269 2,639 2,208 1,901
Capitalized fixed charges-
nuclear fuel(5) 254 1,531 1,711 2,398 1,294 1,211
Allocable portion of interest on
long-term contracts for
the purchase of power(4) 1,870 1,848 1,824 1,797 1,767 1,735
Spent nuclear fuel interest(6) 68 - - - - -
- -----------------------------------------------------------------------------------------------------------------------
Total fixed charges(B) $ 448,923 $ 471,183 $ 459,819 $ 451,106 $ 490,057 $ 487,780
- -----------------------------------------------------------------------------------------------------------------------
RATIO OF EARNINGS TO
FIXED CHARGES(A) (B) 3.43 3.52 3.54 3.49 2.95 2.94
- -----------------------------------------------------------------------------------------------------------------------
(1) Includes allowance for funds used during construction and accrual of
unbilled revenue.
(2) Includes allocation for federal income and state franchise taxes to other
income.
(3) Rentals include the interest factor relating to certain significant rentals
plus one-third of all remaining annual rentals.
(4) Allocable portion of interest included in annual minimum debt service
requirement of supplier.
(5) Includes fixed charges associated with Nuclear Fuel.
(6) Represents interest on spent nuclear fuel disposal obligation.
Southern California Edison Company
1999 Annual Report
- -------------------------------------------------------------------------------
A Profile of Southern California Edison Company
Southern California Edison (SCE) is the nation's second largest investor-owned
electric utility. Headquartered in Rosemead, California, SCE is a subsidiary of
Edison International, which is primarily an energy-services company.
SCE, a 114-year-old electric utility, serves 4.3 million customers and more than
11 million people within a 50,000-square-mile area of central, coastal and
Southern California.
Contents
1 Management's Discussion and Analysis of
Results of Operations and Financial Condition
11 Consolidated Financial Statements
16 Notes to Consolidated Financial Statements
33 Quarterly Financial Data
34 Responsibility for Financial Reporting
35 Report of Independent Public Accountants
36 Selected Financial and Operating Data: 1995-1999
37 Board of Directors
37 Management Team
- --------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations and
Financial Condition
Results of Operations
Earnings
Southern California Edison Company's (SCE) 1999 earnings were $484 million,
compared with $490 million in 1998 and $576 million in 1997. SCE's 1999 earnings
include an approximately $15 million one-time tax benefit due to an Internal
Revenue Service ruling. Excluding the one-time tax benefit, SCE's 1999 earnings
were $469 million, down $21 million from 1998. The 1999 decrease was primarily
due to the accelerated depreciation of SCE's generation assets, partially offset
by higher kilowatt-hour sales in 1999. The $86 million earnings decrease in 1998
was largely due to lower authorized revenue, which resulted from reduced
authorized returns on generating assets and a lower earning asset base resulting
from the accelerated recovery of investments and divestiture of 12 gas- and
oil-fueled generating plants, partially offset by superior operating performance
at San Onofre Nuclear Generating Station.
Operating Revenue
As a result of industry restructuring, customers have an option to buy power
from SCE or directly from the California Power Exchange (PX), thus becoming
direct access customers. Most direct access customers are continuing to be
billed by SCE, but are also given a credit for the generation portion of their
bills. Operating revenue increased by less than 1% in 1999, as increased
kilowatt-hour sales and revenue resulting from maintenance work SCE is providing
the new owners of the divested plants was almost completely offset by the credit
given to customers who chose direct access. Operating revenue decreased 6% in
1998 compared to 1997, reflecting lower average residential rates, partially
offset by an increase in revenue resulting from the maintenance work noted
above. In 1999, over 93% of operating revenue was from retail sales. Retail
rates are regulated by the California Public Utilities Commission (CPUC) and
wholesale rates are regulated by the Federal Energy Regulatory Commission
(FERC).
Due to warmer weather during the summer months, operating revenue during the
third quarter of each year is significantly higher than other quarters.
Legislation enacted in September 1996 provided for, among other things, a 10%
rate reduction for residential and small commercial customers beginning in 1998
and other rates to remain frozen at June 1996 levels (system average of
10.1(cent) per kilowatt-hour). See discussion of proposed post-rate freeze rates
in Regulatory Environment.
The changes in operating revenue resulted from:
In millions Year ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------
Operating revenue--
Rate changes (including refunds) $ (65) $ (498) $ 173
Direct access credit (213) (29) --
Sales volume changes 191 (44) 193
Other 110 117 4
- -----------------------------------------------------------------------------
Total $ 23 $ (454) $ 370
- -----------------------------------------------------------------------------
Operating Expenses
Fuel expense decreased in both 1999 and 1998. The decreases were the result of
the sale of the 12 generating plants in the first half of 1998.
Purchased-power expense -- contracts decreased in both 1999 and 1998, primarily
due to SCE entering into settlements to end its contractual obligations with
certain nonutility generators (known as qualifying facilities, or QFs) and the
terms in some of the QF contracts reverting to a lower price basis. Prior to
April 1998, SCE was required under federal law and CPUC orders to enter into
contracts to purchase power from QFs at CPUC-mandated prices even though energy
and capacity prices under many of these contracts are generally higher than
other sources. In 1999, SCE paid about $1.5 billion (including energy and
capacity payments) more for these power purchases than the cost of power
available from other
1
- -------------------------------------------------------------------------------
Management's Discussion and Analysis of Results of Operations
and Financial Condition
sources. SCE is continuing to purchase power under existing contracts from
certain QFs and from other utilities.
Since April 1, 1998, SCE has been required to sell all of its generated power
through the PX and acquire all of its power from the PX to distribute to its
retail customers. These transactions with the PX are reported net. In 1999, PX
purchased-power expense increased 19%, mainly due to three additional months of
PX transactions in 1999. However, when 1999 PX purchased-power expense is
compared on the same nine-month basis as 1998, the increase is less than 1%,
despite the fact SCE experienced a significant decrease in the volume of
kilowatt-hour sales through the PX. The lower volume of sales through the PX in
1999 was the result of less generation at SCE (San Onofre refueling outages in
1999, divestiture of 12 generating plants in 1998 and reduced hydroelectric
generation) and fewer purchases from QFs. QF power purchases and other purchased
power is also sold through the PX.
Provisions for regulatory adjustment clauses decreased in both 1999 and 1998.
The 1999 decrease was mainly due to undercollections related to the difference
between generation-related revenue and generation-related costs and the
rate-making treatment of the rate reduction notes. These undercollections were
partially offset by overcollections related to the administration of public
purpose funds. The 1998 decrease was mainly due to the revenue deferrals related
to the rate-making treatment of the rate reduction notes. This rate-making
treatment has allowed for the deferral of the recovery of a portion of the
transition-related costs, from a four-year period to a 10-year period. See the
discussion in Revenue and Cost-Recovery Mechanisms.
Other operating expenses increased in both 1999 and 1998, primarily due to an
increase in mandated transmission service (known as must-run reliability
services) expense and PX and Independent System Operator (ISO) costs incurred by
SCE. In 1998, storm damage expense resulting from the harsh winter and direct
access activities also contributed to the increase.
Maintenance expense decreased in 1999, primarily due to lower expenses incurred
at distribution facilities.
Depreciation, decommissioning and amortization expense remained constant in
1999. In 1998, depreciation, decommissioning and amortization expense increased,
primarily due to the further acceleration of recovery of San Onofre Units 2 and
3 and the Palo Verde Nuclear Generating Station units, accelerated recovery of
the generating plants, and the amortization of the loss on plant sales. The
amortization of the loss on plant sales, as well as the accelerated recoveries
implemented in 1998 are part of the competition transition charge (CTC)
mechanism.
In 1998, income tax expense decreased due to lower pre-tax income, as well as
additional amortization related to the CTC mechanism.
Net gain on sale of utility plant resulted from the sale of SCE's generating
plants in 1998. Gains were used to reduce stranded costs. Losses will be
recovered from customers over the transition period through the CTC mechanism.
Other Income
Interest and dividend income increased in 1998, reflecting higher investment
balances due to the sale of the generating plants, as well as increases in
interest earned on higher balancing account undercollections.
Other nonoperating income increased in 1999, when compared to 1998, primarily
due to the one-time adjustment in 1999, resulting from an Internal Revenue
Service ruling that allowed SCE to record a tax benefit, and the gain on sales
of equity investments. Other nonoperating income increased substantially in 1998
mostly due to the additional accruals in 1997 for regulatory matters.
2
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Southern California Edison Company
Interest Expense
Interest and amortization on long-term debt increased in 1998, when compared to
1997, mainly due to the issuance of the rate reduction notes in December 1997.
Interest on the rate reduction notes was $134 million in 1999 and $148 million
in 1998.
Other interest expense increased in 1999, mostly due to higher overall
short-term debt balances necessary to meet general cash requirements during the
year, as well as higher interest expense related to balancing account
overcollections. In 1998, other interest expense decreased substantially, mostly
due to lower overall short-term debt balances, particularly short-term debt used
to finance fuel inventories. These fuel inventories are no longer needed because
of the divestiture of the generating plants in the first half of 1998.
Financial Condition
SCE's liquidity is primarily affected by debt maturities, dividend payments and
capital expenditures. Capital resources include cash from operations and
external financings.
Edison International's board of directors has authorized the repurchase of up to
$2.8 billion of its outstanding shares of common stock. Edison International
repurchased approximately 101 million shares ($2.4 billion) between January 1995
and February 1999, funded by dividends from its subsidiaries and the proceeds of
the rate reduction notes.
Cash Flows from Operating Activities
Net cash provided by operating activities totaled $1.5 billion in 1999, $1.0
billion in 1998 and $1.7 billion in 1997. Cash from operations exceeds capital
requirements for all years presented. SCE's cash flow coverage of dividends was
2.2 times for 1999, and 0.9 times for both 1998 and 1997. The 1999 increase
primarily reflects the rate-making treatment of the gains on sales of the
generating plants, as well as the special dividends SCE paid to Edison
International ($680 million in 1998 and $1.2 billion in 1997).
Cash Flows from Financing Activities
At December 31, 1999, SCE had total credit lines of $1.25 billion, with $39
million available for general purpose, short-term debt and $515 million
available for the long-term refinancing of its variable-rate pollution-control
bonds. These unsecured lines of credit are at negotiated or bank index rates and
expire in 2002.
Short-term debt is used to finance fuel inventories and general cash
requirements. Long-term debt is used mainly to finance capital expenditures.
External financings are influenced by market conditions and other factors,
including limitations imposed by SCE's articles of incorporation and trust
indenture. As of December 31, 1999, SCE could issue approximately $11.1 billion
of additional first and refunding mortgage bonds and $2.8 billion of preferred
stock at current interest and dividend rates.
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure,
limiting the dividends it may pay Edison International. At December 31, 1999,
SCE had the capacity to pay $433 million in additional dividends and continue to
maintain its authorized capital structure.
In December 1997, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable
right known as transition property. Transition property is a current
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
property right created by the restructuring legislation and a financing order of
the CPUC and consists generally of the right to be paid a specified amount from
non-bypassable rates charged to residential and small commercial customers. The
rate reduction notes are being repaid over 10 years through these non-bypassable
residential and small commercial customer rates which constitute the transition
property purchased by SCE Funding LLC. The remaining series of outstanding rate
reduction notes have scheduled maturities beginning in 2000 and ending in 2007,
with interest rates ranging from 6.14% to 6.42%. The notes are secured by the
transition property and are not secured by, or payable from, assets of SCE or
Edison International. SCE used the proceeds from the sale of the transition
property to retire debt and equity securities.
Although, as required by generally accepted accounting principles, SCE Funding
LLC is consolidated with SCE and the rate reduction notes are shown as long-term
debt in the consolidated financial statements, SCE Funding LLC is legally
separate from SCE. The assets of SCE Funding LLC are not available to creditors
of SCE or Edison International and the transition property is legally not an
asset of SCE or Edison International.
On January 24, 2000, SCE issued $250 million of 7-5/8% notes, due 2010.
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and
plant, proceeds from the sale of plant and funding of nuclear decommissioning
trusts. Decommissioning costs are accrued and recovered in rates over the term
of each nuclear generating facility's operating license. SCE estimates that it
will spend approximately $8.6 billion through 2060 to decommission its nuclear
facilities. This estimate is based on SCE's current-dollar decommissioning costs
($2.0 billion), escalated at rates ranging from 0.3% to 10.0% (depending on the
cost element) annually. These costs are expected to be funded from independent
decommissioning trusts which receive SCE contributions of approximately $25
million per year.
Market Risk Exposures
SCE's primary market risk exposures arise from fluctuations in energy prices and
interest rates. SCE's risk management policy allows the use of derivative
financial instruments to manage its financial exposures, but prohibits the use
of these instruments for speculative or trading purposes.
A 10% increase in market interest rates would result in a $7 million increase in
the fair value of SCE's interest rate hedge agreement. A 10% decrease in market
interest rates would result in a $7 million decline in the fair market value of
SCE's interest rate hedge agreement. A 10% increase in natural gas prices would
result in a $20 million increase in the fair market value of gas call options. A
10% decrease in natural gas prices would result in an $11 million decline in the
fair market value of gas call options. A 10% change in market rates is expected
to have an immaterial effect on SCE's other financial instruments.
As a result of the rate freeze established in the restructuring legislation,
SCE's transition costs are recovered as the residual component of rates once the
costs for distribution, transmission, public purpose programs, nuclear
decommissioning and the cost of supplying power to its customers through the PX
and ISO have already been recovered. Accordingly, more revenue will be available
to cover transition costs when market prices in the PX and ISO are low than when
PX and ISO prices are high. The PX and ISO market prices to date have generally
been consistent, although some irregular price spikes have occurred. The ISO has
responded to price spikes in the market for reliability services (referred to as
ancillary services) by imposing a price cap on the market for such services
until certain actions have been completed to improve the functioning of those
markets. Similarly, the ISO currently maintains a cap on its market for
imbalance energy until adequate measures to improve the efficient operation of
the market have been implemented. The caps in these markets mitigate the risk of
costly price spikes that would reduce the revenue available to SCE to pay
transition costs. The price cap instituted by the ISO in the
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Southern California Edison Company
summer of 1998 was $250/MWh. In October 1999, that cap was raised to $750/MWh
and will remain at that level through the summer of 2000, unless certain
identified market improvements do not occur. Under such circumstances, the price
cap can be reduced to $500/MWh. SCE has entered into gas call options to
mitigate high natural gas prices, since increases in natural gas prices tend to
raise the price of electricity.
In July 1999, SCE began participating in forward purchases through a PX block
forward market. In the PX block forward market, SCE can purchase monthly blocks
of energy for six days a week (excluding Sundays and holidays) for 16 hours a
day. These purchases can be made up to 12 months in advance of the delivery
date. The CPUC has currently limited SCE's use of the PX block forward market to
a maximum of approximately 2,000 MW in any month. The PX has requested authority
from the FERC to sell other forward products including a peak product, six days
a week, for eight hours a day. SCE has requested rate-making treatment from the
CPUC for its use of these additional products, and has requested an expansion of
the limits from all forward PX products up to 5,200 MW in summer months. SCE
requested permission from the CPUC to begin a demand responsiveness program that
would allow customers to be paid to curtail their load during times of very high
prices. SCE expects a CPUC resolution on these issues by the end of March 2000.
Projected Capital Requirements
SCE's projected construction expenditures for the next five years are: 2000 --
$1.1 billion; 2001 -- $1.0 billion; 2002 -- $908 million; 2003 -- $901 million;
and 2004 -- $890 million.
Long-term debt maturities and sinking fund requirements for the next five years
are: 2000 -- $571 million; 2001 -- $646 million; 2002 -- $446 million; 2003 --
$371 million; and 2004 -- $371 million.
Preferred stock redemption requirements for the next five years are: 2000 and
2001 -- zero; 2002 -- $105 million; 2003 -- $9 million; and 2004 -- $9 million.
Regulatory 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
as a result of a 1995 CPUC decision on restructuring and state legislation
enacted in 1996. 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
generation-related assets. The Statute also included provisions to finance a
portion of the stranded costs that residential and small commercial customers
would have paid between 1998 and 2001, which allowed SCE to reduce rates by at
least 10% to these customers, effective January 1, 1998. The Statute mandated
other rates to remain frozen at June 1996 levels (system average of 10.1(cent)
per kilowatt-hour), including those for large commercial and industrial
customers, and included provisions for continued funding for energy
conservation, low-income programs and renewable resources. Despite the rate
freeze, SCE expects to be able to recover its revenue requirement during the
1998--2001 transition period. In addition, the Statute mandated the
implementation of the CTC (see the detailed discussion in Revenue and
Cost-Recovery Mechanisms) that provides utilities the opportunity to recover
costs made uneconomic by electric utility restructuring.
Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation.
Revenue related to distribution operations is being determined through a
performance-based rate-making (PBR) mechanism and the distribution assets have
the opportunity to earn a CPUC-authorized 9.49% return. The distribution PBR
will extend 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
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
changes that are not within SCE's control; a cost-of-capital trigger mechanism
based on changes in a bond index; standards for customer satisfaction; service
reliability and safety; and a net revenue-sharing mechanism that determines how
customers and shareholders will share gains and losses from distribution
operations. Transmission revenue is being determined through FERC-authorized
rates that are subject to refund.
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. At the
beginning of the transition period, SCE estimated its transition costs to be
approximately $10.6 billion (1998 net present value) from 1998 through 2030.
This estimate was based on incurred costs, forecasts of future costs and assumed
market prices. However, changes in the assumed market prices could materially
affect these estimates. 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. The potential transition costs
are comprised of $6.4 billion from SCE's QF contracts, which are the direct
result of prior legislative and regulatory mandates, and $4.2 billion from costs
pertaining to certain generating assets (including the 1998 sale of SCE's
generating plants) and regulatory commitments consisting of costs incurred
(whose recovery has been deferred by the CPUC) to provide service to customers.
Such commitments include the recovery of income tax benefits previously flowed
through to customers, postretirement benefit transition costs, accelerated
recovery of San Onofre Units 2 and 3 and the Palo Verde units, and certain other
costs. During 1998, SCE sold all of its gas- and oil-fueled generation plants
for $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. 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 write-offs associated with these
costs if they are not recovered through another regulatory mechanism.
Revenue from generation-related operations is being determined through the
competitive market and the CTC mechanism, which now includes the nuclear
rate-making agreements. The portion of revenue related to fossil and
hydroelectric generation operations that is made uneconomic by electric industry
restructuring is recovered through the CTC mechanism. The portion that is
economic is recovered through the market. SCE's costs associated with its
hydroelectric plants are being recovered through a performance-based mechanism.
The mechanism sets the hydroelectric revenue requirement and establishes a
formula for extending it through the duration of the electric industry
restructuring transition period, or until market valuation of the hydroelectric
facilities, whichever occurs first. The mechanism provides that power sales
revenue from hydroelectric facilities in excess of the hydroelectric revenue
requirement be credited against the costs to transition to a competitive market.
In 1999, fossil and hydroelectric generation assets had the opportunity to earn
a 7.22% return. SCE has filed an application with the CPUC regarding the market
valuation of its hydroelectric facilities. See further discussion below.
SCE is recovering its investment in its nuclear facilities on an accelerated
basis in exchange for a lower authorized rate of return. SCE's nuclear assets
are earning an annual rate of return of 7.35%. In addition, the San Onofre plan
authorizes a fixed rate of approximately 4(cent) per kilowatt-hour generated for
operating costs including incremental capital costs, and nuclear fuel and
nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and
ends in December 2001 for the accelerated recovery portion, and in December 2003
for the incentive-pricing portion. Palo Verde's operating costs, including
incremental capital costs, and nuclear fuel and nuclear fuel financing costs,
are subject to balancing account treatment. The Palo Verde plan commenced in
January 1997 and ends in December 2001. Beginning January 1, 1998, both the San
Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
In March 1997, SCE filed its first FERC transmission rate case. In March 1999, a
proposed FERC decision was issued which recommended a reduced rate of return on
equity of 9.68% (compared to SCE's current CPUC rate for distribution of 11.6%)
and a reduced return on transmission assets of 8.41% (compared to the current
rate of 9.43% being earned on transmission assets). SCE filed comments
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Southern California Edison Company
opposing the proposed decision in May 1999. In response to a recent FERC ruling,
on November 1, 1999, SCE filed additional evidence regarding return on equity. A
final FERC decision is expected during first quarter 2000. SCE does not expect
the final decision to have a material effect on its results of operations or
financial position.
As a further requirement of the law that restructured California's electric
utility industry, in October 1999, SCE filed an application with the CPUC to
approve an auction process for its 56% interest in the Mohave Generating
Station. A CPUC decision on the auction process is expected in early 2000.
In order to comply with the restructuring legislation, on December 15, 1999, SCE
filed an application with the CPUC establishing a market value for its
hydroelectric generation-related assets at approximately $1.0 billion (almost
twice the assets' book value) and proposing to retain and operate the
hydroelectric assets under a performance-based and revenue-sharing mechanism.
The application had broad-based support from labor, ratepayer and environmental
groups. If approved by the CPUC, SCE would be allowed to recover an authorized,
inflation-index operations and maintenance allowance, as well as a reasonable
return on capital investment. A revenue-sharing arrangement would be activated
if revenue from the sale of hydroelectricity exceeds or falls short of the
authorized revenue requirement. SCE would then refund 90% of the excess revenue
to ratepayers or recover 90% of any shortfalls from ratepayers. A final CPUC
decision is expected by the end of 2000.
On January 7, 2000, SCE filed an application with the CPUC proposing rates that
would go into effect when the current rate freeze ends on March 31, 2002, or
earlier, depending on the pace of CTC recovery. The proposal seeks CPUC approval
of a rate redesign that will result in reduced rates for most customers when SCE
completes the first phase of recovery of its transition costs. The proposed new
rates are expected to reduce SCE's system average rates by about 17% from
current frozen rate levels, based on certain assumptions about competitive
energy prices. In addition, SCE's filing proposes to redesign and establish
separate transmission and distribution rates to better reflect the actual costs
to deliver electricity and serve customers. This pricing approach is consistent
with CPUC policies requiring California's major utilities to move toward
cost-based transmission and distribution rates.
Restructuring Implementation Costs
In May 1998, SCE filed an application with the CPUC to identify the categories
of restructuring implementation costs (including costs related to the start-up
and development of both the PX and ISO, and related to the implementation of
direct access) and to establish the reasonableness of those costs incurred in
1997. In September 1999, the CPUC approved a settlement agreement between SCE,
the CPUC's Office of Ratepayer Advocates and several other parties allowing SCE
to recover substantially all (approximately $300 million) of its restructuring
implementation costs (incurred and estimated) for the period 1997-2001. In
addition, the settlement provides that up to $210 million of generation-related
costs (transition costs) that are displaced by recovery of the restructuring
implementation costs during the rate freeze may be recovered after December 31,
2001, the date SCE would cease to recover these transition costs under
restructuring legislation.
Accounting for Generation-Related Assets
If the CPUC's electric industry restructuring plan continues as described above,
SCE will be allowed to recover its transition costs through non-bypassable
charges to its distribution customers (although its investment in certain
generation assets is subject to a lower authorized rate of return). In 1997, SCE
discontinued application of accounting principles for rate-regulated enterprises
for its generation assets based on new accounting guidance. The new guidance did
not require SCE to write off any of its generation-related assets, including
related regulatory assets. SCE has retained these assets on its balance sheet
because the Statute and restructuring plan referred to above make probable their
recovery through a non-bypassable charge to distribution customers. The
regulatory assets relate primarily to the recovery of accelerated income tax
benefits previously flowed through to customers, purchased power
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
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, SCE reduced 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 expected 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 made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at December 31, 1999) as a one-time, non-cash charge against
earnings. 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.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
As further discussed in Note 11 to the Consolidated Financial Statements, SCE
records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE's recorded estimated minimum liability to remediate its 45
identified sites is $163 million. One of SCE's sites, a former pole-treating
facility, is considered a federal Superfund site and represents 40% of its
recorded liability. SCE believes that, due to the uncertainties inherent in the
estimation process, it is reasonably possible that cleanup costs could exceed
its recorded liability by up to $284 million. In 1998, SCE sold all of its gas-
and oil-fueled power plants but has retained some liability associated with the
divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 42 of its sites,
representing $90 million of its recorded liability, through an incentive
mechanism, which is discussed in Note 11. SCE has recorded a regulatory asset of
$126 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. As a result, 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 $5 million to $15 million. Recorded costs for
1999 were $14 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
The 1990 Federal Clean Air Act requires power producers to have emissions
allowances to emit sulfur dioxide. Power companies receive emissions allowances
from the federal government and may bank or sell excess allowances. SCE expects
to have excess allowances under Phase II of the Clean Air Act (2000 and later).
A study was undertaken to determine the specific impact of air contaminant
emissions
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Southern California Edison Company
from the Mohave Generating Station on visibility in Grand Canyon National Park.
The final report on this study, which was issued in March 1999, found negligible
correlation between measured Mohave station tracer concentrations and visibility
impairment. The absence of any obvious relationship cannot rule out Mohave
station contributions to haze in Grand Canyon National Park, but strongly
suggests that other sources were primarily responsible for the haze. In June
1999, the Environmental Protection Agency issued an advanced notice of proposed
rulemaking regarding assessment of visibility impairment at the Grand Canyon.
SCE filed comments on the proposed rulemaking in November 1999. In 1998, several
environmental groups filed suit against the co-owners of the Mohave station
regarding alleged violations of emissions limits. In order to accelerate
resolution of key environmental issues regarding the plant, the parties filed,
in concurrence with SCE and the other station owners, a consent decree, which
was approved by the court in December 1999. The Environmental Protection Agency
has notified SCE that the visibility concerns can be resolved by revising the
Mohave station's Federal Implementation Plan to include the relevant provisions
in the consent decree.
SCE's projected environmental capital expenditures are $850 million for the
2000--2004 period, mainly for undergrounding certain transmission and
distribution lines.
San Onofre Steam Generator Tubes
The San Onofre 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. The steam generator design allows for the removal of
up to 10% of the tubes before the rated capacity of the unit must be reduced. As
a result of the increased degradation found during a 1997 inspection, a
mid-cycle inspection outage was conducted in early 1998 for Unit 2. Continued
degradation was found during this inspection. A favorable or decreasing trend in
degradation was observed during inspection in the scheduled refueling outage in
January 1999 and as a result, a mid-cycle inspection outage in early 2000 was
unnecessary. With the results from the January 1999 outage, 7.5% of the tubes
have now been removed from service.
During Unit 3's refueling outage, which was completed in May 1999, a complete
inspection of the steam generator tubes was performed. Results obtained were
within expectations. To date, 5.4% of Unit 3's tubes have been removed from
service.
New Accounting Rules
In June 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which as amended will be effective
January 1, 2001, 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.
Year 2000 Issue
SCE implemented a comprehensive program to address potential Year 2000 computer
system impacts, consisting of five phases: inventory, impact assessment,
remediation, testing and implementation. SCE met its goal to have 100% of its
critical systems Year 2000-ready by July 1, 1999. A critical system was defined
as those applications and systems, including embedded processor technology,
which if not appropriately remediated, may have had a significant impact on
customers, the health and safety of the public and/or personnel, the revenue
stream, or regulatory compliance. A system, application or physical
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Management's Discussion and Analysis of Results of Operations and
Financial Condition
asset was deemed to be Year 2000-ready if it was determined by SCE to be
suitable for continued use through 2028 (or through the last year of the
anticipated life of the asset, whichever occurred first), even if not fully Year
2000-compliant (able to accurately process date/time data, between the 20th and
21st centuries, 1999 and 2000, and leap-year calculations).
Included among SCE's critical applications were the financial, customer
information and billing, material management, and human resource systems. Work
was also completed on critical physical assets in the areas of information
technology infrastructure, and embedded processor technology in generation,
transmission, distribution and facilities assets. None of SCE's critical
applications or assets has encountered significant problems on or since January
1, 2000, and they continue to operate as expected. SCE expects business as usual
in 2000, as it relates to its Year 2000 computer system issues.
The other essential component of the Year 2000 program was to identify and
assess vendor products and business partners for Year 2000 readiness, as these
external parties may have had the potential to impact SCE's Year 2000 readiness.
SCE implemented a process to identify and contact vendors and business partners
to determine their Year 2000 status. This process included appropriate follow-up
and contingency activities.
SCE's Year 2000 costs through December 31, 1999, were $65 million, of which 37%
was for capital costs. SCE's current rate levels for providing electric service
were sufficient to provide funding for utility-related modifications.
SCE developed contingency plans, which included provisions for monitoring,
validating and managing the continued performance of SCE's Year 2000-sensitive
systems and assets during critical transition periods, development of
work-arounds and expedited fix-on-failure strategies. These contingency plans,
whose initial development was completed in June 1999, were in place for year-end
1999. SCE will continue to maintain the readiness of its contingency plans
throughout 2000. Ongoing efforts include monitoring of systems over the February
29 leap-day period. SCE does not expect the Year 2000 issue to have a material
adverse effect on its results of operation or financial position.
Forward-looking Information
In the preceding Management's Discussion and Analysis of Results of Operations
and Financial Condition and elsewhere in this annual report, the words
estimates, expects, anticipates, believes, and other similar expressions are
intended to identify forward-looking information that involves risks and
uncertainties. Actual results or outcomes could differ materially as a result of
such important factors as further actions by state and federal regulatory bodies
setting rates and implementing the restructuring of the electric utility
industry; the effects of new laws and regulations relating to restructuring and
other matters; the effects of increased competition in the electric utility
business and other energy-related businesses, including 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
ability to create and expand new businesses such as telecommunications; and
other unforeseen events.
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Consolidated Statements of Income Southern California Edison Company
In thousands Year ended December 31, 1999 1998 1997
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Operating revenue $ 7,522,000 $ 7,499,519 $ 7,953,386
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Fuel 225,388 323,716 881,471
Purchased power-- contracts 2,419,147 2,625,900 2,854,002
Purchased power-- power exchange--net 759,818 636,343 --
Provisions for regulatory adjustment clauses-- net (763,830) (472,519) (410,935)
Other operating expenses 1,556,652 1,480,644 1,216,317
Maintenance 363,359 410,566 405,545
Depreciation, decommissioning and amortization 1,546,312 1,545,735 1,239,878
Income taxes 448,510 445,642 582,031
Property and other taxes 121,359 128,402 129,038
Net gain on sale of utility plant (3,035) (542,608) (3,849)
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Total operating expenses 6,673,680 6,581,821 6,893,498
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Operating income 848,320 917,698 1,059,888
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Provision for rate phase-in plan -- -- (48,486)
Allowance for equity funds used during construction 13,008 11,826 7,651
Interest and dividend income 69,029 66,725 44,636
Other nonoperating income (deductions)-- net 50,709 (4,385) (23,036)
Total other income (deductions)-- net 132,746 74,166 (19,235)
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Income before interest expense 981,066 991,864 1,040,653
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Interest and amortization on long-term debt 392,894 421,857 345,592
Other interest expense 91,250 64,225 101,078
Allowance for borrowed funds used during construction (11,288) (8,046) (9,213)
Capitalized interest (1,211) (1,294) (2,398)
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Total interest and amortization expense-- net 471,645 476,742 435,059
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Net income 509,421 515,122 605,594
Dividends on preferred stock 25,889 24,632 29,488
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Earnings available for common stock $ 483,532 $ 490,490 $ 576,106
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Consolidated Statements of Comprehensive Income
In thousands Year ended December 31, 1999 1998 1997
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Net income $ 509,421 $ 515,122 $ 605,594
Unrealized gain on securities - net 28,009 9,275 14,641
Reclassification adjustment for gains included in net income (45,920) (17,836) --
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 491,510 $ 506,561 $ 620,235
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
11
- --------------------------------------------------------------------------------
Consolidated Balance Sheets
In thousands December 31, 1999 1998
- --------------------------------------------------------------------------------------------------------
ASSETS
- --------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution $12,439,059 $11,771,678
Generation 1,717,676 1,689,469
Accumulated provision for depreciation
and decommissioning (7,520,036) (6,896,479)
Construction work in progress 562,651 516,664
Nuclear fuel, at amortized cost 132,197 172,250
- --------------------------------------------------------------------------------------------------------
Total utility plant 7,331,547 7,253,582
- --------------------------------------------------------------------------------------------------------
Nonutility property-- less accumulated provision
for depreciation of $6,797 and $25,682
at respective dates 103,644 56,681
Nuclear decommissioning trusts 2,508,904 2,239,929
Other investments 160,241 179,480
- --------------------------------------------------------------------------------------------------------
Total investments and other assets 2,772,789 2,476,090
- --------------------------------------------------------------------------------------------------------
Cash and equivalents 26,046 81,500
Receivables, including unbilled revenue, less allowances
of $24,665 and $22,230 for uncollectible accounts
at respective dates 1,013,661 1,112,630
Fuel inventory 49,989 51,299
Materials and supplies, at average cost 122,866 116,259
Accumulated deferred income taxes-- net 188,143 274,833
Regulatory balancing accounts-- net -- 287,377
Prepayments and other current assets 111,151 91,992
- --------------------------------------------------------------------------------------------------------
Total current assets 1,511,856 2,015,890
- --------------------------------------------------------------------------------------------------------
Unamortized nuclear investment-- net 1,365,848 2,161,998
Income tax-related deferred charges 1,272,947 1,463,256
Regulatory balancing accounts-- net 1,714,973 361,404
Unamortized debt issuance and reacquisition expense 335,044 348,816
Other deferred charges 1,352,302 865,892
- --------------------------------------------------------------------------------------------------------
Total deferred charges 6,041,114 5,201,366
- --------------------------------------------------------------------------------------------------------
Total assets $17,657,306 $16,946,928
- --------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
12
- --------------------------------------------------------------------------------
Southern California Edison Company
In thousands, except share amounts December 31, 1999 1998
- ---------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- ---------------------------------------------------------------------------------------------------------
Common shareholder's equity:
Common stock (434,888,104 shares outstanding
at each date) $ 2,168,054 $ 2,168,054
Additional paid-in capital 335,038 334,031
Accumulated other comprehensive income 21,551 39,462
Retained earnings 608,453 793,625
- ---------------------------------------------------------------------------------------------------------
3,133,096 3,335,172
Preferred stock:
Not subject to mandatory redemption 128,755 128,755
Subject to mandatory redemption 255,700 255,700
Long-term debt 5,136,681 5,446,638
- ---------------------------------------------------------------------------------------------------------
Total capitalization 8,654,232 9,166,265
- ---------------------------------------------------------------------------------------------------------
Current portion of long-term debt 571,300 400,810
Short-term debt 795,988 469,565
Accounts payable 573,919 447,484
Accrued taxes 500,709 678,955
Accrued interest 82,554 89,828
Dividends payable 94,407 91,742
Regulatory balancing accounts-- net 75,693 --
Deferred unbilled revenue and other current liabilities 1,440,387 1,096,332
- ---------------------------------------------------------------------------------------------------------
Total current liabilities 4,134,957 3,274,716
- ---------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes-- net 2,938,661 2,993,142
Accumulated deferred investment tax credits 205,197 250,116
Customer advances and other deferred credits 823,992 795,266
Power purchase contracts 563,459 129,698
Other long-term liabilities 336,473 337,411
- ---------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 4,867,782 4,505,633
- ---------------------------------------------------------------------------------------------------------
Minority interest 335 314
- ---------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2, 10, and 11)
Total capitalization and liabilities $17,657,306 $16,946,928
- ---------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
13
- --------------------------------------------------------------------------------
Consolidated Statements of Cash Flows
In thousands Year ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net income $ 509,421 $ 515,122 $ 605,594
Adjustments for non-cash items:
Depreciation, decommissioning and amortization 1,546,312 1,545,735 1,239,878
Other amortization 95,060 89,323 81,363
Deferred income taxes and investment tax credits 177,599 (94,504) 63,379
Other long-term liabilities 31,112 (12,528) 55,712
Regulatory balancing accounts-- long-term (1,353,570) (361,403) --
Regulatory asset related to the sale of
generating plants 179 (220,232) --
Net gain on sale of generating plants (938) (564,623) --
Other-- net (76,125) 7,600 (161,698)
Changes in working capital:
Receivables 98,969 (206,242) 14,695
Regulatory balancing accounts 363,071 (94,067) (374,799)
Fuel inventory, materials and supplies (5,297) 23,481 35,707
Prepayments and other current assets (19,159) 1,106 12,039
Accrued interest and taxes (185,520) 174,107 16,625
Accounts payable and other current liabilities 352,489 205,256 120,464
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,533,603 1,008,131 1,708,959
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 490,840 -- --
Long-term debt repaid (362,872) (776,030) (916,145)
Rate reduction notes issued -- -- 2,449,289
Rate reduction notes repaid (246,300) (251,591) --
Preferred stock redeemed -- (74,300) (100,000)
Nuclear fuel financing-- net (37,287) 16,244 (20,140)
Short-term debt issued-- net 326,423 147,537 91,879
Capital transferred -- -- 153,000
Dividends paid (685,731) (1,129,812) (1,871,944)
- -------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (514,927) (2,067,952) (214,061)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (984,197) (860,837) (685,320)
Proceeds from sale of generating plants -- 1,203,039 --
Funding of nuclear decommissioning trusts (115,937) (162,925) (153,756)
Unrealized gain (loss) in equity investments-- net (17,911) (8,561) 14,641
Other-- net 43,915 8,333 (28,133)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by investing activities (1,074,130) 179,049 (852,568)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (55,454) (880,772) 642,330
Cash and equivalents, beginning of year 81,500 962,272 319,942
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of year $ 26,046 $ 81,500 $ 962,272
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
14
- --------------------------------------------------------------------------------
Consolidated Statement of Changes
in Common Shareholder's Equity Southern California Edison Company
Accumulated Total
Additional Other Common
Common Paid-in Comprehensive Retained Shareholder's
In millions Stock Capital Income Earnings Equity
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 $ 2,168 $ 178 $ 33 $ 2,666 $5,045
- -----------------------------------------------------------------------------------------------------------------
Net income 606 606
Unrealized gain on securities 24 24
Tax effect (9) (9)
Dividends declared on common stock (1,829) (1,829)
Dividends declared on preferred stock (30) (30)
Reacquired capital stock expense (5) (5)
Additional investment from
parent company 156 156
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 2,168 334 48 1,408 3,958
- ----------------------------------------------------------------------------------------------------------------
Net income 515 515
Unrealized gain on securities 14 14
Tax effect (5) (5)
Reclassified adjustment for gain
Included in net income (30) (30)
Tax effect 12 12
Dividends declared on common stock (1,101) (1,101)
Dividends declared on preferred stock (24) (24)
Stock option appreciation (4) (4)
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 2,168 334 39 794 3,335
- -------------------------------------------------------------------------------------------------------------------
Net income 509 509
Unrealized gain on securities 46 46
Tax effect (17) (17)
Reclassified adjustment for gain
Included in net income (77) (77)
Tax effect 31 31
Dividends declared on common stock (666) (666)
Dividends declared on preferred stock (26) (26)
Stock option appreciation (3) (3)
Capital stock expense 1 1
- -------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $ 2,168 $ 335 $ 22 $ 608 $3,133
- -------------------------------------------------------------------------------------------------------------------
Authorized common stock is 560 million shares with no par value.
The accompanying notes are an integral part of these financial statements.
15
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Nature of Operations
Southern California Edison Company (SCE) is a rate-regulated electric utility
which supplies electric energy for its 4.3 million customers in central, coastal
and Southern California. SCE also produces electricity. The regulatory
environment in which SCE operates is changing as a result of a 1995 California
Public Utilities Commission (CPUC) decision on electric utility industry
restructuring and state legislation enacted in 1996.
Basis of Presentation
SCE's accounting policies conform with generally accepted accounting principles,
including the accounting principles for rate-regulated enterprises which reflect
the rate-making policies of the CPUC and the Federal Energy Regulatory
Commission (FERC). As a result of industry restructuring state legislation and
related changes in the rate-recovery of generation-related assets, SCE accounts
for its investment in generation facilities in accordance with accounting
principles applicable to enterprises in general. Application of such accounting
principles to SCE's generation assets began in 1997 and did not result in any
adjustment of their carrying value; however, the carrying value of SCE's nuclear
investments (excluding decommissioning) was reduced by $2.6 billion and a
regulatory asset was established for the same amount.
The consolidated financial statements include SCE and its subsidiaries.
Intercompany transactions have been eliminated. Certain prior-year amounts were
reclassified to conform to the December 31, 1999, financial statement
presentation.
SCE's outstanding common stock is owned entirely by its parent company, Edison
International.
Estimates
Financial statements prepared in compliance with generally accepted accounting
principles require management to make estimates and assumptions that affect the
amounts reported in the financial statements and disclosure of contingencies.
Actual results could differ from those estimates. Certain significant estimates
related to regulatory matters, decommissioning and contingencies are further
discussed in Notes 2, 10 and 11 to the Consolidated Financial Statements,
respectively.
Cash Equivalents
Cash equivalents include tax-exempt investments and time deposits and other
investments with maturities of three months or less.
Fuel Inventory
Fuel inventory is valued under the last-in, first-out method for fuel oil and
under the first-in, first-out method for coal.
Revenue
Operating revenue includes amounts for services rendered but unbilled at the end
of each year.
Investments
Net unrealized gains (losses) on equity securities are recorded as a separate
component of shareholder's equity under the caption: Accumulated other
comprehensive income. Unrealized gains and losses on decommissioning trust funds
are recorded in the accumulated provision for decommissioning.
16
- --------------------------------------------------------------------------------
Southern California Edison Company
All investments are classified as available-for-sale.
Regulation of Utility Business
SCE, which is subject to rate-regulation by the CPUC and the FERC, 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.
Effective January 1, 1998, SCE's rates were unbundled into separate charges for
energy, transmission, distribution, the non-bypassable competition transition
charge (CTC), public benefit programs and nuclear decommissioning. The
transmission component is being collected through FERC-approved rates, subject
to refund. SCE's costs associated with its hydroelectric plants are being
recovered through a performance-based mechanism. This mechanism sets the
hydroelectric revenue requirement and establishes a formula for extending it
through the duration of the electric industry restructuring transition period
(March 31, 2002), or until market valuation of the hydroelectric facilities,
whichever occurs first. (See Hydroelectric Market Value Filing discussion in
Note 2.) Revenue from hydroelectric facilities in excess of the hydroelectric
revenue requirement is credited against the costs to transition to a competitive
market. Decommissioning costs are being recovered through a CPUC-authorized
non-bypassable charge.
The CTC provides SCE the opportunity to recover its costs to transition to a
competitive market (approximately $10.6 billion 1998 net present value).
Transition costs related to power-purchase contracts are being recovered through
the terms of the contracts while most of the remaining transition costs will be
recovered through 2001. A portion of the stranded costs that residential and
small commercial customers would have paid between 1998 and 2001, has been
financed by the issuance of rate reduction notes, allowing SCE to reduce rates
by at least 10% to these customers, effective January 1, 1998. The notes allow
for the rate reduction by lowering the carrying cost on a portion of the
transition costs and by deferring recovery of a portion of these transition
costs until after the transition period. Additionally, the state legislation
contained provisions for the recovery (through 2006) of reasonable
employee-related transition costs, incurred and projected, for retraining,
severance, early retirement, outplacement and related expenses.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay
Edison International. At December 31, 1999, SCE had the capacity to pay $433
million in additional dividends and continue to maintain its authorized capital
structure.
Since April 1, 1998, when the new market structure began, SCE has been selling
all of its electric generation through the California Power Exchange (PX), as
mandated by the CPUC's 1995 restructuring decision. Through the PX, SCE
satisfies the electric energy needs of customers who did not choose an
alternative energy provider. These transactions through the PX are reported as
Purchased power -- power exchange -- net.
Transactions through the PX were:
- ---------------------------------------------------------------------------
In millions Year Ended December 31, 1999 1998
- ---------------------------------------------------------------------------
Purchases $ 2,479 $ 1,984
Generation sales 1,719 1,348
- ---------------------------------------------------------------------------
Purchased power-- PX-- net $ 760 $ 636
- ---------------------------------------------------------------------------
Regulatory Assets and Liabilities
In accordance with accounting principles for rate-regulated enterprises, SCE
records regulatory assets, which represent probable future revenue associated
with certain costs that will be recovered from
17
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
customers through the rate-making process, and regulatory liabilities, which
represent probable future reductions in revenue associated with amounts that are
to be credited to customers through the rate-making process. SCE's
discontinuance of accounting principles for rate-regulated enterprises to its
generation assets did not result in a write-off of its generation-related
regulatory assets since the CPUC has approved recovery of these assets through
the CTC.
Regulatory assets and liabilities included in the consolidated balance sheets
are:
December 31, December 31,
In millions 1999 1998
- --------------------------------------------------------------------------------
Generation-related:
Unamortized nuclear investment-- net $1,366 $2,162
Flow-through taxes 306 614
Rate reduction notes-- transition cost deferral 707 315
Unamortized loss on sale of plant 122 183
Purchased-power settlements 531 130
Environmental remediation 16 16
Regulatory balancing accounts and other 1,075 354
- --------------------------------------------------------------------------------
Subtotal 4,123 3,774
- --------------------------------------------------------------------------------
Other:
Flow-through taxes 967 849
Unamortized loss on reacquired debt 295 308
Environmental remediation 111 125
Regulatory balancing accounts and other (36) 110
- --------------------------------------------------------------------------------
Subtotal 1,337 1,392
- --------------------------------------------------------------------------------
Total $5,460 $5,166
- --------------------------------------------------------------------------------
Generation-related regulatory assets and liabilities are being recovered through
the CTC through March 31, 2002, except for the rate reduction notes regulatory
asset which will be recovered over the terms of the rate reduction notes. The
other regulatory assets and liabilities are being recovered through other
components of the unbundled rates.
The unamortized nuclear investment regulatory asset was created during the
second quarter of 1998. SCE reduced its remaining nuclear plant investment by
$2.6 billion (as of June 30, 1998) and recorded a regulatory asset on its
balance sheet for the same amount in accordance with asset impairment accounting
standards. For this impairment assessment, the fair value of the investment was
calculated by discounting expected 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 made the recovery of
these generation-related regulatory assets no longer probable, SCE would be
required to write off the remaining balance of such assets (approximately $2.6
billion, after tax, at December 31, 1999) as a one-time, non-cash charge against
earnings.
Regulatory Balancing Accounts
Beginning January 1, 1998, the difference between generation-related revenue and
generation-related costs is being accumulated in the transition cost balancing
account, effectively eliminating all other balancing accounts except those used
to assist in the administration of public purpose funds. Additionally, gains
resulting from the sale of the gas- and oil-fueled generation plants during 1998
were credited to the transition cost balancing account; the losses are being
amortized over the remaining transition period and accumulated in the transition
cost balancing account. These transition costs are being recovered from utility
customers (with interest) through the CTC mechanism.
18
- --------------------------------------------------------------------------------
Southern California Edison Company
Prior to January 1, 1998, the differences between CPUC-authorized and actual
base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy
costs were accumulated in balancing accounts until they were refunded to, or
recovered from, utility customers through authorized rate adjustments (with
interest). On January 1, 1998, the balances in these balancing accounts were
transferred to the transition cost balancing account.
Income tax effects on all balancing account changes are deferred.
Nuclear
SCE is recovering its investment in San Onofre Nuclear Generating Station Units
2 and 3 and Palo Verde Nuclear Generating Station on an accelerated basis, as
authorized by the CPUC. The accelerated recovery will continue through December
2001, earning a 7.35% fixed rate of return. San Onofre's operating costs,
including nuclear fuel and nuclear fuel financing costs, and incremental capital
expenditures, are recovered through an incentive pricing plan which allows SCE
to receive about 4(cent) per kilowatt-hour through 2003. Any differences between
these costs and the incentive price will flow through to the shareholders. Palo
Verde's accelerated plant recovery, as well as 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, San Onofre's incentive pricing plan and accelerated
plant recovery and the Palo Verde balancing account became part of the
transition cost balancing account. SCE will be required to share equally with
ratepayers the net benefits received from operation of Palo Verde, beginning in
2002, and from the operation of the San Onofre units in 2004. Palo Verde's
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.
Utility Plant
Plant additions, including replacements and betterments, are capitalized. Such
costs include direct material and labor, construction overhead and an allowance
for funds used during construction (AFUDC). AFUDC represents the estimated cost
of debt and equity funds that finance utility-plant construction. AFUDC is
capitalized during plant construction and reported in current earnings. AFUDC is
recovered in rates through depreciation expense over the useful life of the
related asset. Depreciation of utility plant is computed on a straight-line,
remaining-life basis.
Replaced or retired property and removal costs less salvage are charged to the
accumulated provision for depreciation. Depreciation expense stated as a percent
of average original cost of depreciable utility plant was 3.6% for 1999, 4.2%
for 1998 and 5.2% for 1997.
SCE's net investment in generation-related utility plant was $1.0 billion at
December 31, 1999, and $1.1 billion at December 31, 1998.
Supplemental Cash Flows Information
SCE's supplemental cash flows information was:
In millions Year ended December 31, 1999 1998 1997
- ---------------------------------------------------------------------------
Payments for interest and taxes:
Interest-- net of amounts capitalized $ 287 $ 264 $ 342
Taxes 433 405 438
- --------------------------------------------------------------------------
19
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Note 2. Regulatory Matters
FERC Transmission Rate Case
SCE filed its first FERC transmission rate case in March 1997. The filing
proposed a transmission revenue requirement of $211 million. In March 1999, a
proposed FERC decision was issued recommending a return on equity of 9.68%
(compared to SCE's current CPUC rate for distribution of 11.6%) and a lower
revenue requirement. SCE filed comments opposing the proposed decision in May
1999. In response to a recent FERC ruling, on November 1, 1999, SCE filed
additional evidence regarding return on equity. A final FERC decision is
expected in the first quarter of 2000. SCE does not expect the final decision to
have a material effect on its results of operations or financial position.
Hydroelectric Market Value Filing
In order to comply with the restructuring legislation passed in 1996, on
December 15, 1999, SCE filed an application with the CPUC establishing a market
value for its hydroelectric generation-related assets at approximately $1.0
billion (almost twice the assets' book value) and proposing to retain and
operate the hydroelectric assets under a performance-based and revenue-sharing
mechanism. The application had broad-based support from labor, ratepayer and
environmental groups. If approved by the CPUC, SCE would be allowed to recover
an authorized, inflation-index operations and maintenance allowance, as well as
a reasonable return on capital investment. A revenue-sharing arrangement would
be activated if revenue from the sale of hydroelectricity exceeds or falls short
of the authorized revenue requirement. SCE would then refund 90% of the excess
revenue to ratepayers or recover 90% of any shortfalls from ratepayers. A final
CPUC decision is expected by the end of 2000.
Note 3. Financial Instruments
Derivative Financial Instruments
SCE's risk management policy allows the use of derivative financial instruments
to manage financial exposure on its investments and fluctuations in interest
rates, but prohibits the use of these instruments for speculative or trading
purposes.
SCE uses the hedge accounting method to record its derivative financial
instruments, except for gas call options and PX block forward transactions.
Hedge accounting requires an assessment that the transaction reduces risk, that
the derivative be designated as a hedge at the inception of the derivative
contract, and that the changes in the market value of a hedge move in an inverse
direction to the item being hedged. Under hedge accounting, the derivative
itself is not recorded on SCE's balance sheet. Mark-to-market accounting would
be used if the hedge accounting criteria were not met. Interest rate
differentials and amortization of premiums for interest rate caps are recorded
as adjustments to interest expense. If the derivatives were terminated before
the maturity of the corresponding debt issuance, the realized gain or loss on
the transaction would be amortized over the remaining term of the debt.
SCE has gas call options that mitigate its exposure to increases in natural gas
prices. Increases in natural gas prices tend to increase the price of
electricity purchased from the PX. The options cover various periods from 1998
through 2001. Additionally, SCE participates in the PX block forward market. The
PX block forward market allows SCE to purchase monthly blocks of energy for six
days a week (excluding Sundays and holidays) for 16 hours a day. These purchases
can be made up to 12 months in advance of the delivery date. The CPUC has
currently limited SCE's use of the PX block forward market to a maximum of
approximately 2,000 MW in any month.
SCE uses the mark-to-market accounting method for its gas call options and block
forward purchases. Gains and losses from monthly changes in market prices are
recorded as income or expense. However, costs of the options and the market
price changes are included in the transition cost balancing account. As a
result, the mark-to-market gains or losses have no effect on earnings.
20
- --------------------------------------------------------------------------------
Southern California Edison Company
Interest rate swaps are used to reduce the potential impact of interest rate
fluctuations on floating-rate long-term debt. At the balance sheet dates of
December 31, 1999, and December 31, 1998, SCE had an interest rate swap
agreement which fixed the interest rate at 5.585% for $196 million of debt due
2008; it expires February 28, 2008. The interest rate swap agreement requires
the parties to pledge collateral according to bond rating and market interest
rate changes. At December 31, 1999, SCE had pledged $11 million as collateral
due to a decline in market interest rates. SCE is exposed to credit loss in the
event of nonperformance by the counterparty to the agreement, but does not
expect the counterparty to fail to meet its obligation.
Fair Value of Financial Instruments
Fair values of financial instruments were:
In millions December 31, 1999 1998
- --------------------------------------------------------------------------------
Cost Fair Cost Fair
Basis Value Basis Value
- --------------------------------------------------------------------------------
Financial assets:
Decommissioning trusts $1,650 $2,509 $1,534 $2,240
Equity investments -- 33 7 72
Gas call options 28 20 39 31
PX block forward power contracts 118 120 -- --
Financial liabilities:
DOE decommissioning and
decontamination fees 40 35 45 40
Interest rate hedges -- 13 -- 28
Long-term debt 5,137 5,044 5,447 5,699
Preferred stock subject to
mandatory redemption 256 259 256 274
- --------------------------------------------------------------------------------
Financial assets are carried at their fair value based on quoted market prices
for decommissioning trusts, equity investments, and on financial models for gas
call options. Financial liabilities are recorded at cost. Financial liabilities'
fair values are based on: termination costs for the interest rate swap; brokers'
quotes for long-term debt and preferred stock; and discounted future cash flows
for U.S. Department of Energy (DOE) decommissioning and decontamination fees.
Due to their short maturities, amounts reported for cash equivalents and
short-term debt approximate fair value.
Gross unrealized holding gains (losses) on debt and equity investments were:
In millions December 31, 1999 1998
- ----------------------------------------------------------------------------
Decommissioning trusts:
Municipal bonds $239 $196
Stocks 454 365
U.S. government issues 119 115
Short-term and other 47 30
- ----------------------------------------------------------------------------
859 706
Equity investments 33 65
- ----------------------------------------------------------------------------
Total $892 $771
- ----------------------------------------------------------------------------
There were no unrealized holding losses for the years presented.
In 1998, a new accounting standard for derivative instruments and hedging
activities was issued. The new standard, which will be effective January 1,
2001, 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
21
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
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.
Note 4. Long-Term Debt
California law prohibits SCE from incurring or guaranteeing debt for its
nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien. SCE has pledged
first and refunding mortgage bonds as security for borrowed funds obtained from
pollution-control bonds issued by government agencies. SCE uses these proceeds
to finance construction of pollution-control facilities. Bondholders have
limited discretion in redeeming certain pollution-control bonds, and SCE has
arranged with securities dealers to remarket or purchase them if necessary.
Debt premium, discount and issuance expenses are amortized over the life of each
issue. Under CPUC rate-making procedures, debt reacquisition expenses are
amortized over the remaining life of the reacquired debt or, if refinanced, the
life of the new debt.
Commercial paper intended to be refinanced for a period exceeding one year and
used to finance nuclear fuel scheduled to be used more than one year after the
balance sheet date is classified as long-term debt.
Long-term debt maturities and sinking-fund requirements for the five years are:
2000 -- $571 million; 2001 -- $646 million; 2002 -- $446 million; 2003 -- $371
million; and 2004 -- $371 million.
In December 1997, $2.5 billion of rate reduction notes were issued on behalf of
SCE by SCE Funding LLC, a special purpose entity. These notes were issued to
finance the 10% rate reduction mandated by state law. The proceeds of the rate
reduction notes were used by SCE Funding LLC to purchase from SCE an enforceable
right known as transition property. Transition property is a current property
right created by the restructuring legislation and a financing order of the CPUC
and consists generally of the right to be paid a specified amount from
non-bypassable rates charged to residential and small commercial customers. The
rate reduction notes are being repaid over 10 years through these non-bypassable
residential and small commercial customer rates which constitute the transition
property purchased by SCE Funding LLC. The notes are secured by the transition
property and are not secured by, or payable from, assets of SCE or Edison
International. SCE used the proceeds from the sale of the transition property to
retire debt and equity securities.
Although, as required by generally accepted accounting principles, SCE Funding
LLC is consolidated with SCE and the rate reduction notes are shown as long-term
debt in the consolidated financial statements, SCE Funding LLC is legally
separate from SCE. The assets of SCE Funding LLC are not available to creditors
of SCE or Edison International and the transition property is legally not an
asset of SCE or Edison International.
22
- --------------------------------------------------------------------------------
Southern California Edison Company
Long-term debt consisted of:
In millions December 31, 1999 1998
- ---------------------------------------------------------------------------
First and refunding mortgage bonds:
2000 - 2026 (5.625% to 7.25%) $1,400 $1,550
Rate reduction notes:
2000 - 2007 (6.14% to 6.42%) 1,970 2,217
Pollution-control bonds:
2008 - 2031 (5.125% to 7.2% and variable) 1,196 1,201
Funds held by trustees (2) (2)
Debentures and notes:
2000 - 2029 (5.875% to 8.25%) 1,000 700
Subordinated debentures:
2044 (8.375%) 100 100
Commercial paper for nuclear fuel 71 108
Long-term debt due within one year (571) (401)
Unamortized debt discount-- net (27) (26)
- ---------------------------------------------------------------------------
Total $5,137 $5,447
- ---------------------------------------------------------------------------
On January 24, 2000, SCE issued $250 million of 7-5/8% notes, due 2010.
Note 5. Short-Term Debt
SCE has lines of credit totaling $1.25 billion (that can be used at negotiated
or bank index rates) with $39 million available for general purpose short-term
debt and $515 million available for the long-term refinancing of certain
variable-rate pollution-control debt.
Short-term debt includes commercial paper used to finance fuel inventories and
general cash requirements. Commercial paper intended to finance nuclear fuel
scheduled to be used more than one year after the balance sheet date is
classified as long-term debt in connection with refinancing terms under
five-year term lines of credit with commercial banks. Weighted-average interest
rates were 6.1% and 5.3% at December 31, 1999, and December 31, 1998,
respectively.
Short-term debt consisted of:
In millions December 31, 1999 1998
- ---------------------------------------------------------------------------
Commercial paper $696 $581
Floating rate notes 175 --
Amount reclassified as long-term debt (71) (108)
Unamortized discount (4) (3)
- ---------------------------------------------------------------------------
Total $796 $470
- ---------------------------------------------------------------------------
Note 6. Preferred Stock
Authorized shares of preferred and preference stock are: $25 cumulative
preferred -- 24 million; $100 cumulative preferred -- 12 million; and preference
- -- 50 million. All cumulative preferred stock is redeemable.
Mandatorily redeemable preferred stock is subject to sinking-fund provisions.
When preferred shares are redeemed, the premiums paid are charged to common
equity.
23
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Preferred stock redemption requirements for the next five years are: 2000 and
2001 -- zero; 2002 --$105 million; 2003 -- $9 million; and 2004 -- $9 million.
Cumulative preferred stock consisted of:
Dollars in millions,
except per share amounts December 31, 1999 1998
- --------------------------------------------------------------------------------
December 31, 1999
------------------------
Shares Redemption
Outstanding Price
----------- ----------
Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000 $25.50 $ 25 $ 25
4.24 1,200,000 25.80 30 30
4.32 1,653,429 28.75 41 41
4.78 1,296,769 25.80 33 33
- --------------------------------------------------------------------------------
Total $129 $129
- --------------------------------------------------------------------------------
Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000 $100.00 $ 75 $ 75
6.45 1,000,000 100.00 100 100
7.23 807,000 100.00 81 81
- --------------------------------------------------------------------------------
Total $256 $256
- --------------------------------------------------------------------------------
In 1998, 193,000 shares of Series 7.23% preferred stock and 2.2 million shares
of 5.8% preferred stock were redeemed. There were no preferred stock issuances
for the years presented.
Note 7. Income Taxes
SCE and its subsidiaries are included in Edison International's consolidated
federal income tax and combined state franchise tax returns. Under income tax
allocation agreements, each subsidiary calculates its own tax liability.
Income tax expense includes the current tax liability from operations and the
change in deferred income taxes during the year. Investment tax credits are
amortized over the lives of the related properties.
24
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Southern California Edison Company
The components of the net accumulated deferred income tax liability were:
In millions December 31, 1999 1998
- --------------------------------------------------------------------------------
Deferred tax assets:
Property-related $ 184 $ 197
Unrealized gains or losses 453 387
Investment tax credits 113 152
Regulatory balancing accounts 67 96
Decommissioning-related 127 126
Fixed costs 247 188
Unbilled revenue 122 117
Other 92 168
- --------------------------------------------------------------------------------
Total $1,405 $1,431
- --------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related $2,629 $3,005
Capitalized software costs 225 196
Regulatory balancing accounts 448 162
Unrealized gains and losses - decommissioning 351 284
Other 502 502
- --------------------------------------------------------------------------------
Total $4,155 $4,149
- --------------------------------------------------------------------------------
Accumulated deferred income taxes-- net $2,750 $2,718
- --------------------------------------------------------------------------------
Classification of accumulated deferred income taxes:
Included in deferred credits $2,938 $2,993
Included in current assets 188 275
The current and deferred components of income tax expense were:
In millions Year ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
Current:
Federal $299 $450 $375
State 79 101 100
- --------------------------------------------------------------------------------
378 551 475
- --------------------------------------------------------------------------------
Deferred--federal and state:
Accrued charges (76) (43) (33)
Property related (187) (106) (47)
Investment and energy tax credits-- net (45) (74) (20)
Pension reserve 1 (3) (5)
Rate phase-in plan -- -- (19)
Regulatory balancing accounts 371 177 141
Unbilled revenue (5) (67) 6
Other 1 7 22
- --------------------------------------------------------------------------------
60 (109) 45
- --------------------------------------------------------------------------------
Total income tax expense $438 $442 $520
- --------------------------------------------------------------------------------
Classification of income taxes:
Included in operating income $449 $446 $582
Included in other income (11) (4) (62)
The composite federal and state statutory income tax rate was 40.551% for all
years presented.
25
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
The federal statutory income tax rate is reconciled to the effective tax rate
below:
Year ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------
Federal statutory rate 35.0% 35.0% 35.0%
Capitalized software (2.4) (0.7) (0.9)
Property-related and other 9.3 11.4 6.9
Investment and energy tax credits (4.4) (6.8) (1.8)
State tax-- net of federal deduction 8.5 6.9 7.0
- -----------------------------------------------------------------------------
Effective tax rate 46.0% 45.8% 46.2%
- -----------------------------------------------------------------------------
Note 8. Employee Compensation and Benefit Plans
Employee Savings Plan
SCE has a 401(k) defined contribution savings plan designed as a source of
employees' retirement income. The plan received employer contributions of $25
million in 1999, $17 million in 1998 and $15 million in 1997.
Pension Plan
SCE has a noncontributory, defined-benefit pension plan that covers employees
meeting minimum service requirements. SCE recognizes pension expense as
calculated by the actuarial method used for ratemaking. In April 1999, SCE
adopted a cash balance feature for its pension plan.
In 1998, SCE adopted a new accounting standard that revises the disclosure
requirements for pension plans. Prior years have been restated.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 1999 1998
- --------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $2,251 $2,094
Service cost 66 59
Interest cost 146 141
Plan amendment (22) --
Actuarial loss (gain) (224) 90
Benefits paid (142) (133)
- --------------------------------------------------------------------------------
Benefit obligation at end of year $2,075 $2,251
- --------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $2,552 $2,298
Actual return on plan assets 620 334
Employer contributions 48 53
Benefits paid (142) (133)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year $3,078 $2,552
- --------------------------------------------------------------------------------
Funded status $1,003 $ 301
Unrecognized net loss (gain) (1,018) (372)
Unrecognized transition obligation 28 33
Unrecognized prior service cost 132 168
- --------------------------------------------------------------------------------
Recorded asset $ 145 $ 130
- --------------------------------------------------------------------------------
Discount rate 7.75% 6.75%
Rate of compensation increase 5.0% 5.0%
Expected return on plan assets 7.5% 7.5%
26
- --------------------------------------------------------------------------------
Southern California Edison Company
Expense components were:
In millions Year ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
Service cost $ 66 $ 59 $ 44
Interest cost 146 141 138
Expected return on plan assets (188) (170) (160)
Net amortization and deferral 12 14 13
- --------------------------------------------------------------------------------
Pension expense under
accounting standards 36 44 35
Regulatory adjustment-- deferred 14 11 17
- --------------------------------------------------------------------------------
Total expense recognized $ 50 $ 55 $ 52
- --------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
Employees retiring at or after age 55 with at least 10 years of service are
eligible for postretirement health and dental care, life insurance and other
benefits. In 1998, SCE adopted a new accounting standard that revises the
disclosure requirements for postretirement benefit plans. Prior periods have
been restated.
Information on plan assets and benefit obligations is shown below:
In millions Year ended December 31, 1999 1998
- --------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $1,545 $1,533
Service cost 46 41
Interest cost 109 99
Actuarial loss (gain) (185) (74)
Benefits paid (53) (54)
- --------------------------------------------------------------------------------
Benefit obligation at end of year $1,462 $1,545
- --------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $1,029 $ 815
Actual return on plan assets 185 147
Employer contributions 122 121
Benefits paid (53) (54)
- --------------------------------------------------------------------------------
Fair value of plan assets at end of year $1,283 $1,029
- --------------------------------------------------------------------------------
Funded status $ (179) $ (516)
Unrecognized net loss (gain) (207) 84
Unrecognized transition obligation 349 376
- --------------------------------------------------------------------------------
Recorded asset (liability) $ (37) $ (56)
- --------------------------------------------------------------------------------
Discount rate 8.0% 6.75%
Expected return on plan assets 7.5% 7.5%
Expense components were:
In millions Year ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
Service cost $ 46 $ 41 $ 30
Interest cost 109 99 99
Expected return on plan assets (79) (62) (50)
Net amortization and deferral 27 28 31
- --------------------------------------------------------------------------------
Total expense $ 103 $ 106 $ 110
- --------------------------------------------------------------------------------
27
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
The assumed rate of future increases in the per-capita cost of health care
benefits is 11.75% for 2000, gradually decreasing to 5.0% for 2008 and beyond.
Increasing the health care cost trend rate by one percentage point would
increase the accumulated obligation as of December 31, 1999, by $227 million and
annual aggregate service and interest costs by $28 million. Decreasing the
health care cost trend rate by one percentage point would decrease the
accumulated obligation as of December 31, 1999, by $183 million and annual
aggregate service and interest costs by $22 million.
Stock Option Plans
In 1998, Edison International shareholders approved the Edison International
Equity Compensation Plan. The plan replaces the Long-Term Incentive Compensation
Program, consisting of officer, director, and management plans, which was
adopted by Edison International shareholders in 1992. No new awards will be made
under the prior program; however, it will remain in effect as long as any awards
remain outstanding under the prior program.
The prior program participated in the use of 8.2 million shares of parent
company common stock reserved for potential issuance under various stock
compensation programs to directors, officers and senior managers of Edison
International and its affiliates. Under these programs, options on 2.7 million
shares of Edison International common stock are currently outstanding to
officers and senior managers of SCE.
The new plan authorizes the annual issuance of shares equal to one percent of
the issued and outstanding shares of Edison International common stock as of
December 31 of the prior year. This authorization is cumulative so that to the
extent shares are not needed to meet new plan requirements in any year, the
excess authorized shares will carry over to subsequent years until plan
termination. One percent of the issued and outstanding Edison International
common stock on December 31, 1998 and December 31, 1997, was 3.5 million and 3.8
million shares, respectively. Under the new plan, options on 4.0 million shares
of Edison International common stock are currently outstanding to officers and
senior managers of SCE.
Each option may be exercised to purchase one share of Edison International
common stock, and is exercisable at a price equivalent to the fair market value
of the underlying stock at the date of grant. Edison International stock options
include a dividend equivalent feature. Generally, for options issued before
1994, amounts equal to dividends accrue on the options at the same time and at
the same rate as would be payable on the number of shares of Edison
International common stock covered by the options. The amounts accumulate
without interest. For Edison International stock options issued after 1993,
dividend equivalents are subject to reduction unless certain shareholder return
performance criteria are met. Beginning with the 1999 Edison International stock
option awards, only some stock options include a dividend equivalent feature.
Future stock option awards under the plan are not expected to include the
dividend equivalent feature. Additionally, awards of performance shares,
comprising a combination of Edison International common stock and cash, are
anticipated under the plan.
The new plan's stock options have a 10-year term with one-fourth of the total
award vesting after each of the first four years of the award term. The prior
program's stock options have a 10-year term with one-third of the total award
vesting after each of the first three years of the award term. If an optionee
retires, dies or is permanently and totally disabled during the vesting period,
the unvested options will vest and be exercisable to the extent of 1/36 (prior
program) or 1/48 (the new plan) of the grant for each full month of service
during the vesting period.
Unvested options of any person who has served in the past on the Edison
International or SCE Management Committee (which was dissolved in 1993) will
vest and be exercisable upon the member's retirement, death or permanent and
total disability. Upon retirement, death or permanent and total disability, the
vested options may continue to be exercised within their original terms by the
recipient or beneficiary. If an optionee is terminated other than by retirement,
death or permanent and total disability, options which had vested as of the
prior anniversary date of the grant are forfeited unless exercised within 180
days of the date of termination. All unvested options are forfeited on the date
of termination.
28
- --------------------------------------------------------------------------------
Southern California Edison Company
SCE measures compensation expense related to stock-based compensation by the
intrinsic value method. Compensation expense recorded under the
stock-compensation program was $5 million, $8 million and $5 million for the
years 1999, 1998 and 1997, respectively.
Stock-based compensation expense under the fair-value method of accounting would
have resulted in pro forma earnings of $509 million, $516 million and $602
million for the years 1999, 1998 and 1997, respectively.
The fair value for each option granted, reflecting the basis for the above pro
forma disclosures, was determined on the date of grant using the Black-Scholes
option-pricing model. The following assumptions were used in determining fair
value through the model:
1999 1998
- -----------------------------------------------------------------------------
Expected life 7 years 7 years
Risk-free interest rate 5.0% - 5.5% 4.7%- 5.6%
Expected volatility 18% 17%
- -----------------------------------------------------------------------------
The application of fair-value accounting to calculate the pro forma disclosures
above is not an indication of future income statement effects. The pro forma
disclosures do not reflect the effect of fair-value accounting on stock-based
compensation awards granted prior to 1995.
The weighted-average fair value of options granted during 1999 and 1998 was
$4.37 per share option and $6.44 per share option, respectively. The
weighted-average remaining life of options outstanding as of December 31, 1999,
and December 31, 1998, was 7 years.
Note 9. Jointly Owned Utility Projects
SCE owns interests in several generating stations and transmission systems for
which each participant provides its own financing. SCE's share of expenses for
each project is included in the consolidated statements of income.
The investment in each project, as included in the consolidated balance sheet as
of December 31, 1999, was:
Original Accumulated
Cost of Depreciation and Under Ownership
In millions Facility Amortization Construction Interest
- -------------------------------------------------------------------------------------------------------------------
Transmission systems:
Eldorado $ 39 $ 6 $ 3 60%
Pacific Intertie 241 78 6 50
Generating stations:
Four Corners Units 4 and 5 (coal) 459 325 3 48
Mohave (coal) 323 217 2 56
Palo Verde (nuclear)(1) 1,609 1,153 19 16
San Onofre (nuclear)(1) 4,275 3,269 16 75
- -------------------------------------------------------------------------------------------------------------------
Total $ 6,946 $ 5,048 $49
- -------------------------------------------------------------------------------------------------------------------
(1) Reported as Unamortized nuclear investment-- net."
29
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
Note 10. Commitments
Leases
SCE has operating leases, primarily for vehicles, with varying terms, provisions
and expiration dates.
Estimated remaining commitments for noncancellable leases at December 31, 1999,
were:
Year ended December 31, In millions
- -------------------------------------------------------------------
2000 $13
2001 10
2002 7
2003 5
2004 4
Thereafter 8
- -------------------------------------------------------------------
Total $47
- -------------------------------------------------------------------
Nuclear Decommissioning
Decommissioning is estimated to cost $2.0 billion in current-year dollars, based
on site-specific studies performed in 1998 for San Onofre and Palo Verde.
Changes in the estimated costs, timing of decommissioning, or the assumptions
underlying these estimates could cause material revisions to the estimated total
cost to decommission in the near term. SCE estimates that it will spend
approximately $8.6 billion through 2060 to decommission its nuclear facilities.
This estimate is based on SCE's current dollar decommissioning costs, escalated
at rates ranging from 0.3% to 10.0% (depending on the cost element) annually.
These costs are expected to be funded from independent decommissioning trusts,
which, effective 1999, receive contributions of approximately $25 million per
year. SCE estimates annual after-tax earnings on the decommissioning funds of
3.9% to 4.9%.
SCE plans to decommission its nuclear generating facilities by a prompt removal
method authorized by the Nuclear Regulatory Commission. Decommissioning is
expected to begin after the plants' operating licenses expire. The operating
licenses expire in 2013 for San Onofre Units 2 and 3, and 2025--2027 for Palo
Verde. Decommissioning costs, which are accrued and recovered through
non-bypassable customer rates over the term of each nuclear facility's operating
license, are recorded as a component of depreciation expense.
In June 1999, the CPUC authorized SCE to access its nuclear decommissioning
trust funds to start decommissioning San Onofre Unit 1 (shutdown in 1992 per
CPUC agreement) effective immediately.
Decommissioning expense was $124 million in 1999, $164 million in 1998 and $154
million in 1997. The accumulated provision for decommissioning, excluding San
Onofre Unit 1, was $1.3 billion at December 31, 1999, and $1.2 billion at
December 31, 1998. The estimated costs to decommission San Onofre Unit 1
(approximately $360 million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts,
which, together with accumulated earnings, will be utilized solely for
decommissioning.
Trust investments (cost basis) include:
Maturity
- --------------------------------------------------------------------------------
In millions Dates December 31, 1999 1998
- --------------------------------------------------------------------------------
Municipal bonds 2000--2033 $ 684 $ 547
Stocks -- 482 550
U.S. government issues 2000--2030 351 355
Short-term and other 2000--2040 133 82
- --------------------------------------------------------------------------------
Trust fund balance $1,650 $1,534
- --------------------------------------------------------------------------------
30
- --------------------------------------------------------------------------------
Southern California Edison Company
Trust fund earnings (based on specific identification) increase the trust fund
balance and the accumulated provision for decommissioning. Net earnings were $58
million in 1999, $63 million in 1998 and $54 million in 1997. Proceeds from
sales of securities (which are reinvested) were $2.6 billion in 1999, $1.2
billion in 1998 and $595 million in 1997. Approximately 90% of the trust fund
contributions were tax-deductible.
Other Commitments
SCE has fuel supply contracts which require payment only if the fuel is made
available for purchase. Additionally, SCE's gas and coal fuel contracts require
payment of certain fixed charges whether or not gas or coal is delivered.
SCE has power-purchase contracts with certain qualifying facilities
(cogenerators and small power producers) and other utilities. These contracts
provide for capacity payments if a facility meets certain performance
obligations and energy payments based on actual power supplied to SCE. There are
no requirements to make debt-service payments. As a result of the utility
industry restructuring, SCE has entered into purchased-power settlements to end
its contract obligations with certain qualifying facilities. The settlements are
reported as long-term liabilities. Settlement payments are being recovered
through the CTC.
SCE has unconditional purchase obligations for part of a power plant's
generating output, as well as firm transmission service from another utility.
Minimum payments are based, in part, on the debt-service requirements of the
provider, whether or not the plant or transmission line is operable. SCE's
minimum commitment under both contracts is approximately $166 million through
2017. The purchased-power contract (approximately $30 million) is expected to
provide approximately 5.5% of current or estimated future operating capacity,
and is reported as a long-term liability. The transmission service contract
requires a minimum payment of approximately $6 million a year.
Certain commitments for the years 2000 through 2004 are estimated below:
In millions 2000 2001 2002 2003 2004
- --------------------------------------------------------------------------------
Projected construction expenditures $1,108 $1,030 $908 $901 $890
Fuel supply contracts 180 123 132 142 121
Purchased-power capacity payments 793 783 683 668 678
- --------------------------------------------------------------------------------
Note 11. Contingencies
In addition to the matters disclosed in these notes, SCE is involved in other
legal, tax and regulatory proceedings before various courts and governmental
agencies regarding matters arising in the ordinary course of business. SCE
believes the outcome of these other proceedings will not materially affect its
results of operations or liquidity.
Environmental Protection
SCE is subject to numerous environmental laws and regulations, which require it
to incur substantial costs to operate existing facilities, construct and operate
new facilities, and mitigate or remove the effect of past operations on the
environment.
SCE records its environmental liabilities when site assessments and/or remedial
actions are probable and a range of reasonably likely cleanup costs can be
estimated. SCE reviews its sites and measures the liability quarterly, by
assessing a range of reasonably likely costs for each identified site using
currently
31
- --------------------------------------------------------------------------------
Notes to Consolidated Financial Statements
available information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites, and the probable level of
involvement and financial condition of other potentially responsible parties.
These estimates include costs for site investigations, remediation, operations
and maintenance, monitoring and site closure. Unless there is a probable amount,
SCE records the lower end of this reasonably likely range of costs (classified
as other long-term liabilities at undiscounted amounts).
SCE's recorded estimated minimum liability to remediate its 45 identified sites
is $163 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 $284 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. In 1998, SCE 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 42 of its sites,
representing $90 million of its recorded liability, through an incentive
mechanism (SCE may request to include additional sites). Under this mechanism,
SCE will recover 90% of cleanup costs through customer rates; shareholders fund
the remaining 10%, with the opportunity to recover these costs from insurance
carriers and other third parties. SCE has successfully settled insurance claims
with all responsible carriers. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory
asset of $126 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 now be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from
$5 million to $15 million. Recorded costs for 1999 were $14 million.
Based on currently available information, SCE believes it is unlikely that it
will incur amounts in excess of the upper limit of the estimated range and,
based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE
believes that costs ultimately recorded will not materially affect its results
of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or
the identification of new sites, will not require material revisions to such
estimates.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5
billion. SCE and other owners of San Onofre and Palo Verde have purchased the
maximum private primary insurance available ($200 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium
charges to every reactor licensee if a nuclear incident at any licensed reactor
in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial
protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from
this secondary level, effective June 1994. The maximum deferred premium for each
nuclear incident is $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. However, it would have to pay no more than $20 million per incident in
32
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Southern California Edison Company
any one year. Such amounts include a 5% surcharge if additional funds are needed
to satisfy public liability claims and are subject to adjustment for inflation.
If the public liability limit above is insufficient, federal regulations may
impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including
decontamination costs, at San Onofre and Palo Verde. Decontamination liability
and property damage coverage exceeding the primary $500 million also has 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 by a mutual insurance company owned by
utilities with nuclear facilities. If losses at any nuclear facility covered by
the arrangement were to exceed the accumulated funds for these insurance
programs, SCE could be assessed retrospective premium adjustments of up to $19
million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the DOE is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste.
Such a facility was to be in operation by January 1998. However, the DOE did not
meet its obligation. It is not certain when the DOE will begin accepting spent
nuclear fuel from San Onofre or from other nuclear power plants.
SCE has primary responsibility for the interim storage of its spent nuclear fuel
at San Onofre. Current capability to store spent fuel is estimated to be
adequate through 2005. Meeting spent-fuel storage requirements beyond that
period would require new and separate interim storage facilities, the costs for
which have not been determined. Extended delays by the DOE could lead to
consideration of costly alternatives involving siting and environmental issues.
SCE has paid the DOE the required one-time fee applicable to nuclear generation
at San Onofre through April 6, 1983, (approximately $24 million, plus interest).
SCE is also paying the required quarterly fee equal to one mill per
kilowatt-hour of nuclear-generated electricity sold after April 6, 1983.
Palo Verde on-site spent fuel storage capacity will accommodate needs until 2003
for Unit 2, and until 2004 for Units 1 and 3. Arizona Public Service Company,
operating agent for Palo Verde, is constructing an interim fuel storage facility
that is expected to be completed in 2002.
SCE and other owners of nuclear power plants may be able to recover interim
storage costs arising from DOE delays in the acceptance of utility spent nuclear
fuel by pursuing relief under the terms of the contracts, as directed by the
courts, or through other court actions.
- -------------------------------------------------------------------------------------------------------------------
Quarterly Financial Data
1999 1998
------------------------------------------ -----------------------------------------
In millions Total Fourth Third Second First Total Fourth Third Second First
- -------------------------------------------------------------------------------------------------------------------
Operating revenue $7,522 $1,820 $2,304 $1,721 $1,677 $7,500 $1,889 $2,369 $1,619 $1,623
Operating income 848 221 257 198 172 918 241 237 212 228
Net income 509 146 168 112 83 515 121 169 120 105
Earnings available for
common stock 484 141 160 106 77 490 115 163 114 98
Common dividends declared 666 117 269 111 169 1,101 141 422 442 96
- -------------------------------------------------------------------------------------------------------------------
33
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Responsibility for Financial Reporting
The management of Southern California Edison Company (SCE) is responsible for
the integrity and objectivity of the accompanying financial statements. The
statements have been prepared in accordance with accounting principles generally
accepted in the United States and are based, in part, on management estimates
and judgment.
SCE maintains systems of internal control to provide reasonable, but not
absolute, assurance that assets are safeguarded, transactions are executed in
accordance with management's authorization and the accounting records may be
relied upon for the preparation of the financial statements. There are limits
inherent in all systems of internal control, the design of which involves
management's judgment and the recognition that the costs of such systems should
not exceed the benefits to be derived. SCE believes its systems of internal
control achieve this appropriate balance. These systems are augmented by
internal audit programs through which the adequacy and effectiveness of internal
controls and policies and procedures are monitored, evaluated and reported to
management. Actions are taken to correct deficiencies as they are identified.
SCE's independent public accountants, Arthur Andersen LLP, are engaged to audit
the financial statements in accordance with auditing standards generally
accepted in the United States and to express an informed opinion on the
fairness, in all material respects, of SCE's reported results of operations,
cash flows and financial position.
As a further measure to assure the ongoing objectivity of financial information,
the audit committee of the board of directors, which is composed of outside
directors, meets periodically, both jointly and separately, with management, the
independent public accountants and internal auditors, who have unrestricted
access to the committee. The committee recommends annually to the board of
directors the appointment of a firm of independent public accountants to conduct
audits of its financial statements; considers the independence of such firm and
the overall adequacy of the audit scope and SCE's systems of internal control;
reviews financial reporting issues; and is advised of management's actions
regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing personnel to
assure that its operations are conducted in conformity with applicable laws and
is committed to maintaining the highest standards of personal and corporate
conduct. Management maintains programs to encourage and assess compliance with
these standards.
Thomas M. Noonan Stephen E. Frank
--------------------- --------------------------------
Thomas M. Noonan Stephen E. Frank
Vice President Chairman of the Board, President
and Controller and Chief Executive Officer
February 2, 2000
34
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Report of Independent Public Accountants Southern California Edison Company
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To the Shareholders and the Board of Directors,
Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern
California Edison Company (SCE, a California corporation) and its subsidiaries
as of December 31, 1999, and 1998, and the related consolidated statements of
income, comprehensive income, cash flows and common shareholder's equity for
each of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of SCE's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of SCE and its subsidiaries as of
December 31, 1999, and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
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ARTHUR ANDERSEN LLP
Los Angeles, California
February 2, 2000
35
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Selected Financial and Operating Data: 1995-1999 Southern California Edison Company
Dollars in millions 1999 1998 1997 1996 1995
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Income statement data:
Operating revenue $ 7,522 $ 7,500 $ 7,953 $ 7,583 $ 7,873
Operating expenses(1) 6,674 6,582 6,893 6,450 6,724
Fuel and purchased power expenses 3,404 3,586 3,735 3,336 3,197
Income tax from operations 449 446 582 578 560
Allowance for funds used during construction 24 20 17 25 34
Interest expense-- net 483 485 444 453 464
Net income 509 515 606 655 680
Earnings available for common stock 484 490 576 621 643
Ratio of earnings to fixed charges 2.94 2.95 3.49 3.54 3.52
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Balance sheet data:
Assets $ 17,657 $ 16,947 $ 18,059 $ 17,737 $ 18,155
Gross utility plant 14,852 14,150 21,483 21,134 20,717
Accumulated provision for depreciation and
decommissioning 7,520 6,896 10,544 9,431 8,569
Common shareholder's equity 3,133 3,335 3,958 5,045 5,144
Preferred stock:
Not subject to mandatory redemption 129 129 184 284 284
Subject to mandatory redemption 256 256 275 275 275
Long-term debt 5,137 5,447 6,145 4,779 5,215
Capital structure:
Common shareholder's equity 36.2% 36.4% 37.5% 48.6% 47.1%
Preferred stock:
Not subject to mandatory redemption 1.5% 1.4% 1.7% 2.7% 2.6%
Subject to mandatory redemption 2.9% 2.8% 2.6% 2.7% 2.5%
Long-term debt 59.4% 59.4% 58.2% 46.0% 47.8%
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Operating data:
Peak demand in megawatts (MW) 19,122 19,935 19,118 18,207 17,548
Generation capacity at peak (MW) 10,474 10,546 21,511 21,602 21,603
Kilowatt-hour sales (kWh) (in millions) 78,602 76,595 77,234 75,572 74,296
Total energy requirement (kWh) (in millions)(2) 78,752 80,289 86,849 84,236 81,924
Energy mix:
Thermal 35.5% 38.8% 44.6% 47.6% 51.6%
Hydro 5.6% 7.4% 6.5% 6.9% 7.7%
Purchased power and other sources 58.9% 53.8% 48.9% 45.5% 40.7%
Customers (in millions) 4.36 4.27 4.25 4.22 4.18
Full-time employees 13,040 13,177 12,642 12,057 14,886
(1) 1999 and 1998 includes net purchases from the PX.
(2) 1999 and 1998 excludes direct access and resale customer requirements.
36
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Board of Directors Southern California Edison Company
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Winston H. Chen* Charles D. Miller Robert H. Smith
Chairman of the Paramitas Foundation Chairman of the Board, Managing Director,
and Chairman of Paramitas Avery Dennison Corporation, Smith and Crowley Incorporated,
Investment Corporation, Pasadena, California Pasadena, California
Santa Clara, California
Luis G. Nogales Thomas C. Sutton
Warren Christopher President, Chairman of the Board and
Senior Partner, Nogales Partners, Chief Executive Officer
O'Melveny & Myers, Los Angeles, California Pacific Life Insurance Company,
Los Angeles, California Newport Beach, California
Ronald L. Olson
Stephen E. Frank Senior Partner, Daniel M. Tellep
Chairman of the Board, President and Munger, Tolles and Olson, Retired Chairman of the Board,
Chief Executive Officer, Los Angeles, California Lockheed Martin Corporation,
Southern California Edison Company Bethesda, Maryland
Joan C. Hanley James M. Rosser
The Former General Partner and Manager, President, Edward Zapanta, M.D.
Miramonte Vineyards, California State University, Physician and Neurosurgeon,
Rancho Palos Verdes, California Los Angeles, Torrance, California
Los Angeles, California
Carl F. Huntsinger
General Partner,
DAE Limited Partnership Ltd.,
Ojai, California
*Retiring on April 20, 2000.
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Management Team
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Stephen E. Frank Emiko Banfield Stephen E. Pickett
Chairman of the Board, President and Vice President, Vice President and General Counsel
Chief Executive Officer Shared Services
Frank J. Quevedo
Harold B. Ray Bruce C. Foster Vice President,
Executive Vice President, Vice President, Equal Opportunity
Generation Business Unit San Francisco Regulatory Operations
Joseph P. Ruiz
Pamela A. Bass A. L. Grant Vice President and General Auditor
Senior Vice President, Vice President, Transmission
Customer Service Business Unit W. James Scilacci
Lawrence D. Hamlin Vice President and
John R. Fielder Vice President, Power Production and Chief Financial Officer
Senior Vice President, Operations and Maintenance Services
Regulatory Policy and Affairs Dale E. Shull, Jr.
Holly Kolinski Vice President, Distribution
Robert G. Foster Vice President,
Senior Vice President, Mass Customers Anthony L. Smith
Public Affairs Vice President, Tax
R. W. Krieger
Lillian R. Gorman* Vice President, David Ned Smith
Senior Vice President, Nuclear Generation Vice President, Major Customers
Human Resources
J. Michael Mendez Joseph J. Wambold
Richard M. Rosenblum Vice President, Labor Relations Vice President, Nuclear Business and
Senior Vice President, Support Services
Transmission and Distribution Thomas M. Noonan
Business Unit Vice President and Controller Robert C. Boada
Treasurer
Mahvash Yazdi Dwight E. Nunn
Senior Vice President and Vice President, Nuclear Engineering Beverly P. Ryder
Chief Information Officer and Technical Services Secretary
*Resigned on February 29, 2000.
37
Shareholder Information
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Annual Meeting of Shareholders
Thursday, April 20, 2000
9:00 a.m., Central Time
Chicago Public Library
Harold Washington Library Center
400 South State Street
Chicago, Illinois 60605
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Stock Listing and Trading Information
SCE Preferred Stock
The American and Pacific stock exchanges use the ticker symbol SCE. Previous
day's closing prices, when traded, are listed in the daily newspapers in the
American Stock Exchange table under the symbol SoCalEd. The 6.05%, 6.45% and
7.23% series are not listed.
Where to Buy and Sell Stock
The listed preferred stocks may be purchased through any brokerage firm. Firms
handling unlisted series can be located through your broker.
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Transfer Agent and Registrar
Norwest Bank Minnesota, N.A. maintains shareholder records and is transfer agent
and registrar for SCE preferred stock. Shareholders may call Norwest Shareowner
Services, (800) 347-8625, between 7:00 a.m. and 7:00 p.m. (Central Time) every
business day, regarding:
o stock transfer and name-change requirements;
o address changes, including dividend addresses;
o electronic deposit of dividends;
o taxpayer identification number submission or changes;
o duplicate 1099 forms and W-9 forms;
o notices of and replacement of lost or destroyed stock certificates;
o dividend checks;
o requests to eliminate multiple annual report mailings; and
o requests for access to online account information.
The address of Norwest Shareowner Services is:
P.O. Box 64854, St. Paul, Minnesota 55164-0854
FAX: (651) 450-4033
Southern California Edison
2244 Walnut Grove Avenue
Rosemead, California 91770
(626) 302-1212