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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, 2001
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue (626) 302-1212
Rosemead, California 91770 (Registrant's telephone number,
(Address of principal executive 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
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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. [X]
As of March 25, 2002, 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 $323,592.460.35 on or about March 25, 2002, 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 25, 2001, were as follows: CUMULATIVE PREFERRED STOCK $75,829,990.35; $100 CUMULATIVE PREFERRED STOCK
$247,762,470.00.
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, 2001............................ Parts I, II and IV
(2) Designated portions of the Joint Proxy Statement
relating to registrant's 2002 Annual Meeting of Shareholders................. Part III
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TABLE OF CONTENTS
Item Page
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Part I
1. Business ............................................................................................... 1
Forward-Looking Statements and Risk Factors......................................................... 1
Competitive Environment............................................................................. 3
Regulation.......................................................................................... 3
Changing Regulatory Environment..................................................................... 4
Other Rate Matters.................................................................................. 13
Fuel Supply and Purchased Power Costs............................................................... 17
Environmental Matters............................................................................... 19
2. Properties.............................................................................................. 22
Existing Generating Facilities...................................................................... 22
Construction Program and Capital Expenditures....................................................... 24
Nuclear Power Matters............................................................................... 24
3. Legal Proceedings....................................................................................... 27
San Onofre Personal Injury Litigation............................................................... 27
Navajo Nation Litigation............................................................................. 28
Shareholder Litigation............................................................................... 28
Qualifying Facilities Litigation.................................................................... 29
Power Exchange (PX) Performance Bond Litigation..................................................... 30
CPUC Litigation and Settlement...................................................................... 31
4. Submission of Matters to a Vote of Security Holders..................................................... 31
Executive Officers of the Registrant................................................................ 31
Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters................................... 33
6. Selected Financial Data................................................................................. 33
7. Management's Discussion and Analysis of Results of Operations and Financial Condition................... 33
7A. Quantitative and Qualitative Disclosures About Market Risk.............................................. 33
8. Financial Statements and Supplementary Data............................................................. 33
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 33
Part III
10. Directors and Executive Officers of the Registrant...................................................... 34
11. Executive Compensation.................................................................................. 34
12. Security Ownership of Certain Beneficial Owners and Management.......................................... 34
13. Certain Relationships and Related Transactions.......................................................... 34
Part IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................ 35
Financial Statements................................................................................ 35
Report of Independent Public Accountants and Schedules Supplementing Financial Statements........... 35
Exhibits............................................................................................ 35
Reports on Form 8-K................................................................................. 35
Signatures.......................................................................................... 40
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, coastal 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. In 2001, SCE's total operating revenue was derived from: 34% residential customers, 42% commercial
customers, 10% industrial customers, 7% public authorities, 2% agricultural and other customers, and 5% other
electric revenue. SCE had 11,663 full-time employees at year-end 2001.
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 retained other electric generating plants, however,
and it retained 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 was required for an interim transitional period to sell all SCE-generated electricity
to the California Power Exchange (PX) at prices determined by periodic public auctions, and to buy any
electricity needed to serve SCE's retail customers from the PX at similarly determined prices. Due to the
California energy crisis and SCE's resulting financial difficulties, as described below under "Changing
Regulatory Environment," in January 2001 SCE ceased buying and selling power through the PX. In 2001,
legislation was enacted in California prohibiting SCE and other California utilities from selling their remaining
generating facilities. SCE has continued to provide power for its customers from its own generation sources and
from existing contracts with other utilities and power producers. The California Department of Water Resources
(CDWR) is providing power for sale to SCE's customers to the extent SCE cannot provide sufficient power from
SCE's own generation and power contracts. SCE delivers such power and collects and remits revenues on behalf of
the CDWR.
Forward-Looking Statements and Risk Factors
This annual report on Form 10-K 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," "probable" 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, or that otherwise could
impact SCE, are:
o SCE's financial condition, liquidity and credit ratings were adversely affected by California's electricity
crisis. SCE is seeking to regain an investment grade credit rating so it can re-enter the credit markets on
more efficient and reasonable terms. Whether and when investment grade credit ratings can be regained will
have a significant impact on SCE's financial condition. Based on the rights to cost recovery and revenue
established by the settlement agreement with the California Public Utilities Commission (CPUC) (discussed
below) and CPUC implementing orders, including the procurement-related obligations account (PROACT)
resolution (discussed below), SCE's credit ratings were raised and the company repaid all of its undisputed
past-due obligations in March 2002 to creditors from a combination of cash on hand and the proceeds of
senior secured credit facilities and a remarketing of pollution control bonds. Although Fitch IBCA,
Standard & Poor's and Moody's Investors Service
raised their credit ratings significantly for both Edison International and SCE in March 2002, the new
ratings are still below investment grade.
o The court order approving SCE's settlement agreement with the CPUC is being appealed by a consumer advocacy
group to the federal court of appeals. If the order is successfully challenged on appeal, implementation of
the settlement agreement by SCE and the CPUC could be affected adversely, which in turn may have an adverse
affect on SCE's ability to restore its financial condition.
o SCE is affected by actions of regulatory bodies setting rates, adopting or modifying cost recovery,
accounting or rate-setting mechanisms and implementing the restructuring of the electric utility industry.
o SCE may be affected by legislative measures adopted and being contemplated by federal and state authorities
to address the California electricity crisis or deregulation in other states, and pending legislation that
would repeal or amend key statutes governing the electric industry.
o SCE may be affected by 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 SCE owns and operates power generation facilities and, therefore, may be affected by changes in the supply,
demand and price for electric capacity and energy in relevant markets and the cost and availability of fuel
and fuel transportation.
o As an owner-operator of power generation facilities, SCE also may be affected by 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.
o SCE may be affected by financial market conditions such as inflation and changes in interest rates, which
could affect the availability and cost of external financing, as well as the actions of securities rating
agencies.
o SCE is subject to power plant operation risks, including strikes, equipment failures and other issues.
o SCE may be affected by changes in tax laws or unfavorable interpretation and application of the laws by tax
authorities.
o The operation of power generation, transmission or distribution facilities by SCE involves the potential for
new or increased environmental liabilities associated with power plants and other facilities or operations,
resulting from changes in laws, accidents or other events. Environmental advocacy groups and regulatory
agencies have been focusing considerable attention on carbon dioxide emissions from coal-fired plants and
their potential role in the "global-warming" issue. The adoption of new laws and regulations to implement
carbon dioxide or other emission controls could adversely affect SCE's coal plants. For further discussion,
see "Business - Environmental Matters."
o SCE may be subject to legal proceedings arising out of financial reporting, commercial disputes, property
rights, personal injuries, and other circumstances.
Additional information about the risk factors listed above and other risks and uncertainties is contained
throughout this report and in the Notes to Consolidated Financial Statements and Management's Discussion and
Analysis of Results of Operations and Financial Condition (MD&A) that are incorporated by reference into Part II
of this annual report. Readers are urged to read this entire report, including the information incorporated by
reference, 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, and
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SCE is not obligated to publicly update or revise forward-looking statements. Readers should review future
reports filed by SCE with the Securities and Exchange Commission (SEC).
Competitive Environment
Throughout most of its history, SCE provided integrated electric generation, transmission, and distribution
services on a bundled basis to its customers and had an exclusive franchise within its service territory.
Customers had the right to generate their own electricity through cogeneration or other means, but third parties
were not permitted to sell energy directly to customers within SCE's service territory. In 1994, the CPUC
commenced the electric industry restructuring process. In 1996, the California Legislature enacted comprehensive
restructuring legislation. SCE's business was unbundled into separate generation, transmission, and distribution
components, and the development of a competitive generation market was authorized. SCE was directed by the CPUC
to divest the bulk of its gas-fired generation portfolio. Those plants are now owned and operated by independent
power producers. Under the legislation and CPUC decisions, independent power producers and other energy service
providers were authorized to enter into contracts to provide electricity to retail customers over SCE's
distribution system. Power producers and suppliers were authorized to sell energy to the PX at wholesale prices
set by the market. In 2001, as a result of the California energy crisis, the PX ceased operation and the CDWR
took over the purchase of power for utility customers. The ability of customers to depart utility service and
buy power from power producers and suppliers other than SCE was suspended. The future of the competitive market
in California is uncertain. The effects on SCE of this changing competitive environment are discussed below
under "Business - Changing Regulatory Environment."
Regulation
SCE's retail operations are, for the most part, subject to regulation by the 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 retail transmission service pricing,
accounting practices, and licensing of hydroelectric projects.
SCE is subject to the jurisdiction of the United States 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 (San Onofre) 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. Additionally, SCE has a coastal permit to construct a dry cask
spent fuel storage installation for Units 2 and 3.
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The United States 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.
Changing Regulatory Environment
SCE operates in a highly regulated environment in which it has an obligation to deliver electric service to
customers within its service territory in return for certain obligations of the regulatory authorities to provide
just and reasonable rates. In 1994, state lawmakers and the CPUC initiated the electric industry restructuring
process, as discussed above under "Competitive Environment". As part of California's electric industry
restructuring, a multi-year freeze on the rates that SCE could charge its customers was mandated and transition
cost recovery mechanisms were implemented allowing SCE to recover certain specified costs associated with
generation-related assets (referred to as "stranded costs").
California's electric utility industry restructuring statute 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. These frozen rates
were to remain in effect until the earlier of March 31, 2002, or the date when the CPUC-authorized costs for
utility-owned generation assets and obligations were recovered.
In May 2000, SCE began experiencing adverse impacts from unusually high prices for energy and ancillary services
procured through the PX and the California Independent System Operator (ISO). These high wholesale prices,
coupled with the freeze on SCE's retail rates resulted in substantial revenue undercollections. Pursuant to CPUC
and accounting rules, SCE recorded the undercollections in the transition revenue account (TRA). As of
December 31, 2000, the amount of undercollections recorded was $4.5 billion. Based on a CPUC decision on
March 27, 2001 (see further discussion in "Recovery of Transition and Power Procurement Costs" below), the TRA
undercollection, along with SCE's coal and hydroelectric balancing account overcollections (which amounted to
$1.5 billion as of December 31, 2000), were reclassified to a transition cost balancing account (TCBA). In
addition, the CPUC recalculated the TCBA to be a $2.9 billion undercollection.
Liquidity Issues
Sustained higher wholesale energy prices that exceeded SCE's retail rate levels resulted in large
undercollections in the TRA and TCBA regulatory balancing accounts. The undercollections in these accounts,
coupled with near-term capital requirements and the adverse reaction of the credit markets to regulatory
uncertainty regarding SCE's ability to recover its power procurement costs, materially and adversely affected
SCE's liquidity throughout late 2000 and 2001. As a result of its liquidity crisis, SCE took steps to conserve
cash while continuing to provide service to its customers. Beginning in January 2001, SCE suspended payments
owed to the ISO, the PX, and qualifying facilities (QFs), deferred payments of certain obligations for principal
and interest on outstanding debt, and did not declare dividends on any of its cumulative preferred stock. The
suspension or deferral of payments caused defaults on two series of SCE's senior unsecured notes and all of SCE's
commercial paper. In March 2001, the CPUC ordered SCE to commence payments to QFs for future energy deliveries
and by April 1, 2001, SCE resumed payment of interest on its debt obligations.
In October 2001, SCE entered into an agreement settling a lawsuit against the CPUC concerning SCE's right to
recover its power procurement costs in retail rates. On January 23, 2002, the CPUC adopted a resolution
implementing a mechanism for recovery of these costs. (See "CPUC Settlement Agreement" below for a discussion of
this matter.)
On March 1, 2002, SCE closed on a $1.6 billion credit facility, secured by three newly issued series of SCE's
first mortgage bonds, and remarketed approximately $196 million of pollution control bonds that SCE repurchased
in late 2000.
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The proceeds from the credit facilities and pollution-control bond remarketing were used along with SCE's
available cash to repay $3.2 billion in past-due obligations and $1.65 billion in near-term debt maturities. The
past-due obligations consisted of: (1) $875 million to the PX; (2) $99 million to the ISO; (3) $1.1 billion to
QFs; (4) $193 million in PX energy credits for energy service providers; (5) $531 million of matured commercial
paper; (6) $400 million of principal on its 5-7/8% and 6-1/2% senior unsecured notes which were issued prior to
the energy crisis; and (7) $23 million in preferred dividends in arrears. The near-term debt maturities
consisted of credit facilities whose maturity dates were extended several times and were scheduled to mature in
March and May 2002. After making the above-described payments, SCE has no material undisputed obligations that
are past-due or in default. In addition, SCE entered into an agreement with the CDWR to pay for prior deliveries
of energy of $100 million on April 1, 2002, $150 million on June 3, 2002, and the balance on July 1, 2002.
CDWR Power Purchases
On January 17, 2001, following rolling blackouts in the northern California service territory of Pacific Gas and
Electric Company (PG&E), California Governor Gray Davis signed an order declaring an emergency and authorizing
the CDWR to purchase power in order to prevent further blackouts.
In accordance with the emergency order, the CDWR began making emergency power purchases for SCE's customers on
January 17, 2001. Amounts SCE bills to and collects from its customers for electric power purchased and sold by
the CDWR and through the ISO are remitted directly to the CDWR and are not recognized as revenue by SCE. In
February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law. AB 1X authorized the
CDWR to enter into contracts to purchase electric power and sell power at cost directly to retail customers being
served by SCE, and authorized the CDWR to issue bonds to finance electricity purchases.
On March 27, 2001, the CPUC issued an interim order requiring SCE to pay the CDWR a per-kWh price equal to the
applicable generation-related retail rate per kWh for electricity for each kWh the CDWR sells to SCE's
customers. The CPUC determined that the generation-related retail rate should be equal to the total bundled
electric rate (including the 1(cent)per kWh and 3(cent)per kWh surcharges adopted by the CPUC on January 4, 2001, and
March 27, 2001, respectively) less certain nongeneration-related rates or charges. For the period January 19
through January 31, 2001, the CPUC ordered SCE to pay the CDWR at a rate of 6.277(cent)per kWh for power delivered to
SCE's customers. This amount increased per the 1(cent)and 3(cent)surcharges referenced above. The CPUC ordered SCE to
pay the CDWR its applicable generation rate within 45 days after the CDWR supplies power to retail customers,
subject to penalties for each day the payment is late.
On February 21, 2002, the CPUC issued a decision implementing a CDWR revenue requirement of $9.0 billion to pay
its costs associated with bonds issued to finance the CDWR's energy procurement costs for the period January 17,
2001, through December 31, 2002. The decision states that SCE's allocated share of this revenue requirement
would be approximately $3.6 billion, and changes SCE's payment from an average recorded rate of 11.46(cent)per kWh to
9.744(cent)per kWh. Amounts remitted to the CDWR on or after March 15, 2002, will be based on the new rate. The
decision also requires SCE to pay the CDWR the difference in the amount SCE previously paid the CDWR for
electricity delivered from January 17, 2001, through March 15, 2002, and the amount that would have been paid had
the new rate been in effect for the entire period (approximately $41 million). This amount may be paid in equal
monthly installments over a six-month period.
On February 14, 2001, FERC issued an order that denied the ISO's request to relax creditworthiness standards in
the ISO tariff to the extent this would affect third-party suppliers. FERC, however, allowed the ISO to revise
its tariff so that a "creditworthy counterparty" could assume responsibility for procuring power with respect to
utilities that do not have the credit rating required by the ISO tariff, such as SCE or PG&E. On April 6, 2001,
FERC issued an order essentially reaffirming the February 14 order and holding that the ISO must assure that
there is a creditworthy buyer for power delivered to loads through the ISO. SCE has not met the ISO's
creditworthiness requirements since its credit ratings were downgraded in mid-January 2001. As a result, SCE
protested and returned the bills it had received from the ISO. On
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August 9, 2001, the ISO filed a petition for review of the FERC's April 6, 2002, order with the court of appeals
for the D.C. Circuit Court.
On November 7, 2001, the FERC issued an order directing the ISO, within 15 days of the order, to invoice the CDWR
for all ISO transactions it entered into on behalf of SCE and PG&E. The FERC also directed the ISO, within 15
days from the date of the order, to file a compliance report with the FERC indicating overdue amounts from the
CDWR and a schedule for payment of those overdue amounts within three months of the date of the order. On
November 21, 2001, the ISO filed the compliance report. On December 7, 2001, SCE sought a limited rehearing of
the November 7, 2001, order. On the same day, the CDWR also filed its rehearing request. On December 21, 2001,
SCE filed comments on the ISO's compliance filing and many parties, including the CDWR, protested the compliance
filing.
On February 28, 2002, SCE and the CDWR executed an agreement that resolves outstanding issues relating to payment
for imbalance energy delivered to SCE's customers (imbalance energy is energy obtained from the ISO's real-time
market) and responsibility for certain ISO charges. Under this agreement, SCE will pay the CDWR for imbalance
energy previously delivered in three installments ($100 million on April 1, 2002; $150 million on June 3, 2002;
and the balance on July 1, 2002). The agreement also establishes a mechanism for SCE to pay the CDWR for
imbalance energy that the CDWR sells to SCE's customers in the future. Additionally, the agreement allocates
responsibility for ISO charges between the CDWR and SCE. The agreement provides that SCE will reimburse the CDWR
by September 1, 2002, for ISO charges which the CDWR previously paid and which SCE agrees to pay in the
agreement. The agreement also provides a mechanism for payment of ISO charges that are incurred in the future.
Direct Access
A related power-procurement issue is the extent to which customers should be allowed to purchase power directly
from energy service providers (Direct Access) instead of through SCE. As part of emergency legislation
authorizing the CDWR to purchase power on behalf of utility customers, the CPUC was ordered to suspend Direct
Access until such time as the CDWR was no longer supplying power. The CPUC was given flexibility as to the
timing of its order. In early 2001, when extremely high power prices prevailed in the wholesale markets, many
customers who had previously chosen Direct Access returned to SCE bundled utility service, and the CDWR purchased
power on their behalf. As the crisis in the wholesale energy markets eased in summer of 2001, customers again
sought to move to Direct Access suppliers. On September 20, 2001, the CPUC suspended Direct Access on an interim
basis, reserving its right to review the suspension date. On March 21, 2002, the Commission voted to maintain
the September 20, 2001, suspension date. The Commission also ordered that Direct Access surcharges or exit fees
shall be developed in a separate proceeding so that there is an equitable allocation of the CDWR costs and that
Direct Access customers pay their fair share of CDWR costs. Based on the September 20, 2001, suspension,
approximately 14% or more of SCE's retail energy load will likely be served through Direct Access. Because the
CDWR is presently supplying all power in excess of SCE's own generation and long-term contracts, a change in the
amount of Direct Access load could affect the CDWR's total costs going forward.
The CPUC has also initiated hearings on an additional Direct Access issue. Until June 3, 2001, Direct Access
customers were receiving a credit based on SCE's weighted-average energy cost. When wholesale energy costs
skyrocketed in early 2001, this energy cost often exceeded the generation rate component of frozen rates. Thus,
during these times, SCE incurred a liability to fund both energy purchases for bundled service customers and
energy credits for Direct Access customers. These costs were reflected in SCE's regulatory asset accounts. As a
result, Direct Access customers contributed to SCE's procurement related liabilities in the same manner as SCE's
bundled customers. The CPUC is investigating whether and how to allocate to Direct Access customers an
appropriate share of the balance in the PROACT, which is described under "CPUC Settlement Agreement" and "PROACT"
below. Briefs were filed on this issue on February 13 and February 20, 2002, with a draft decision expected by
mid 2002. As part of the Direct Access proceeding, the CPUC will consider whether the method used to calculate
the credits paid to Direct Access customers after January 17, 2001, was appropriate.
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Affiliate and Holding Company Proceedings
In 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. As required by the new rules and an
interim CPUC resolution, SCE has filed preliminary and revised compliance plans which set forth SCE's
implementation of the new affiliate transaction rules. The CPUC has not yet ruled on the sufficiency of SCE's
October 1998 revised compliance plan. In January 2001, the CPUC issued an order instituting rulemaking to
commence the review of the 1997 affiliate transaction rules that the original decision itself requires. The CPUC
proposes that some rules be considered for streamlining or other revision, while inviting interested parties to
submit proposals of their own. No decision has yet been issued.
In April 2001, the CPUC adopted an order instituting investigation that reopened the past CPUC decisions
authorizing the utilities to form holding companies and initiated an investigation into: whether the holding
companies violated CPUC requirements to give first priority to the capital needs of their respective utility
subsidiaries; whether actions by Edison International and PG&E Corporation and their respective nonutility
affiliates to shield, or "ring-fence," nonutility assets also violated the requirements that the holding
companies give first priority to the capital needs of their utility subsidiaries; whether the payment of
dividends by the utilities violated requirements that the utilities maintain dividend policies as though they
were comparable stand-alone utility companies; any additional suspected violations of laws or CPUC rules and
decisions; and whether additional rules, conditions, or other changes to the holding company decisions are
necessary. On January 9, 2002, the CPUC issued a decision regarding the "first priority" condition that defined
the term "capital" as encompassing all of the following: "the money and property with which a company carries on
its corporate business; a company's assets, regardless of source, utilized for the conduct of the corporate
business and for the purpose of deriving gains and profits; and a company's working capital," and which found
that the first priority condition does not preclude the requirement that the holding companies infuse all types
of "capital" into their respective utility subsidiaries where necessary to fulfill the utility's obligation to
serve. The CPUC stated that it had not conclusively found that any holding company has violated such condition.
Also on January 9. 2002, the CPUC denied motions by Edison International and the other holding companies to
dismiss the proceeding as it pertains to them for lack of jurisdiction. Both Edison International and SCE filed
requests for rehearing of the decision on the first priority condition, and Edison International filed a request
for rehearing of the denial of its motion to dismiss for lack of jurisdiction.
Although the CPUC denied the holding companies' motions to dismiss for lack of jurisdiction, the CPUC then
dismissed PG&E Corporation from the proceeding so that the issue of whether PG&E Corporation's bankruptcy plan
would result in a violation of the first priority condition could be resolved "in the appropriate judicial
forums." On January 10, 2002, the California Attorney General filed a civil lawsuit in state court alleging that
PG&E Corporation had violated California's Unfair Competition Act by, among other things, failing to infuse
capital into Pacific Gas and Electric Company as required by the first priority condition and seeking to insulate
assets from the CPUC's jurisdiction through the improper use of the power of the bankruptcy court. The lawsuit
seeks injunctions, restitution, and a civil penalty of at least $500 million. The CPUC announced that it intends
to join in the lawsuit against PG&E Corporation, based on the CPUC's January 9, 2002 decisions.
SCE cannot predict what effects the CPUC's investigation or any other actions by the CPUC or the Attorney General
may have.
Qualifying Facilities
On March 27, 2001, the CPUC ordered SCE to begin making payments to QFs for power deliveries on a going forward
basis. Under the order, SCE was directed to pay QFs within 15 days of the end of the QFs' billing period, and
QFs are allowed to establish 15-day billing periods. A supplemental order issued on December 11, 2001, deleted
the automatic penalty provisions and instead advised SCE that it could be
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subject to an order to show cause in the event of a violation. Furthermore, settlement agreement amendments
entered into with the vast majority of the QFs under contract with SCE resulted in the QFs' waiver of the 15-day
payment opportunity coincident with the making of a "final" settlement payment by SCE on March 1, 2002. SCE is
pursuing agreements with the remaining QFs that likewise would result in a waiver of the 15-day payment
directive. In the March 27 order, the CPUC also modified the formula used in calculating payments to most QFs by
substituting natural gas index prices based on deliveries at the Oregon border in the place of index prices at
the Arizona border. The order further revises other aspects of the payment formula to take into account changes
in intrastate gas transportation costs. SCE anticipates that the changes will probably result in lower QF energy
prices. The changes apply where appropriate regardless of whether the QF uses natural gas or other resources
such as solar or wind. In March 2002, SCE paid $1.1 billion to QFs to resolve issues related to SCE's suspension
of payments for deliveries by QFs during the period November 1, 2000, through March 26, 2001. For additional
information about lawsuits filed against SCE by QFs, see "Qualifying Facilities Litigation" in Part 1, Item 3 of
this report.
CPUC Settlement Agreement
In November 2000, SCE filed a complaint in federal District Court against the Commissioners of the CPUC, alleging
that their refusal to allow SCE to recover its wholesale costs of purchasing power in its retail rates violated
federal law. The case was stayed in April 2001 by agreement of SCE and the CPUC, with the support of Governor
Davis, to create an opportunity to implement a consensual resolution. The state legislature, however, did not
pass legislation to implement such a resolution by late September 2001. At that point, the CPUC and SCE
negotiated a settlement agreement (CPUC Settlement Agreement) to resolve the litigation, and the district court
entered a stipulated judgment on October 5, 2001, incorporating the settlement. Several entities appealed the
stipulated judgment entered by the district court, including a California consumer group that had been allowed to
intervene in the litigation as a permissive intervenor, and three other entities whose motions to intervene had
been denied.
On November 28, 2001, a federal court of appeals denied the consumer group's request for a stay of the
settlement. The group had alleged that it was denied due process, that the settlement violated state law, and
that the CPUC had no authority to agree to the settlement. In its ruling, the court of appeals also granted
SCE's request for an expedited hearing of the appeal. On March 4, 2002, the court of appeals heard argument on
the appeal, and the matter is now under submission. A decision could be issued anytime within the next several
months. It is impossible to predict the outcome of the appeal, or the impact that any outcome would have upon
the stipulated judgment or the settlement.
Key elements of the CPUC Settlement Agreement include the following items:
o Establishment of an account called the procurement-related obligations account, or PROACT, as of
September 1, 2001, which will have an opening balance equal to the amount of SCE's procurement-related
liabilities as of August 31, 2001 (approximately $6.4 billion), less SCE's cash and cash equivalents as of
that date (approximately $2.5 billion), and less $300 million.
o Beginning September 1, 2001, and ending on the earlier of the date that SCE has recovered all of its
procurement-related obligations recorded in the PROACT or December 31, 2005, SCE will apply to the PROACT,
on a monthly basis, the difference between SCE's revenue from retail electric rates (including surcharges)
and the costs that SCE is authorized by the CPUC to recover in retail electric rates. Unrecovered
obligations in the PROACT will accrue interest from September 1, 2001.
o SCE will recover in retail electric rates its procurement-related obligations in the PROACT, with
interest, by December 31, 2005. Subject to certain adjustments, the CPUC will maintain current rates
(including surcharges) in effect until December 31, 2003, or, if earlier, until the date that SCE recovers
the entire PROACT balance. If SCE has not recovered the entire balance by December 31, 2003, the
unrecovered balance will be amortized over a period not to extend beyond December 31, 2005. The parties
project that existing retail electric rates, including surcharges and as adjusted to reflect certain
Page 8
costs, will likely result in SCE recovering substantially all of its unrecovered procurement-related
obligations prior to the end of 2003.
o If the CPUC concludes that it is desirable to authorize a securitized financing of SCE's
procurement-related obligations, the parties will work together to achieve the securitization. Proceeds of
any securitization will be credited to the PROACT when they are actually received.
o During the period that SCE is recovering its procurement-related obligations, no penalty will be imposed
by the CPUC on SCE for any noncompliance with CPUC-mandated capital structure requirements.
o SCE will incur up to $250 million of recoverable costs to acquire financial instruments and engage in
other transactions intended to hedge fuel cost risks associated with SCE's retained generation assets and
power purchase contracts with qualifying facilities and other utilities. As of December 31, 2001, SCE had
purchased $209 million in hedging instruments. See discussion under "Market Risk Exposures" in the MD&A
that is incorporated by reference into Part II, Item 7 of this report.
o SCE will not declare or pay dividends or other distributions on its common stock (all of which is held
by its parent) prior to the earlier of the date SCE has recovered all of its procurement-related obligations
in the PROACT or January 1, 2005. However, if SCE has not recovered all of its procurement-related
obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common stock dividends,
and the CPUC will not unreasonably withhold its consent.
o To ensure the ability of SCE to continue to provide adequate service until the effectiveness of SCE's
next general rate case, SCE may make capital expenditures above the level contained in current rates, up to
$900 million per year, which will be treated as recoverable costs.
o Subject to certain qualifications, SCE will cooperate with the CPUC and the California Attorney General
to pursue and resolve SCE's claims and rights against sellers of energy and related services, SCE's defenses
to claims arising from any failure to make payments to the PX or ISO, and similar claims by the State of
California or its agencies against the same adverse parties. During the recovery period discussed above,
refunds obtained by SCE related to its procurement-related liabilities will be applied to the balance in the
PROACT.
The CPUC Settlement Agreement states that one of its purposes is to restore the investment grade creditworthiness
of SCE as rapidly as reasonably practicable so that it will be able to provide reliable electrical service as a
state-regulated entity as it has in the past. SCE cannot provide assurance that it will regain investment grade
credit ratings by any particular date.
PROACT
On January 23, 2002, the CPUC issued a resolution that approved the new ratemaking and accounting structure that
SCE proposed to implement the CPUC Settlement Agreement. Among other things, the new structure eliminates the
TCBA as of August 31, 2001, and creates the new PROACT. This change implements the provision of the CPUC
Settlement Agreement declaring that "balances in SCE's TCBA as of August 31, 2001, shall have no further impact
on SCE's retail electric rates." According to the terms of the CPUC Settlement Agreement and the CPUC's
implementing resolution, in the fourth quarter of 2001, SCE established (retroactive to August 31, 2001) a
$3.6 billion PROACT regulatory asset for its previously incurred procurement costs. On February 25, 2002, TURN
submitted an application for rehearing, of the CPUC's January 23, 2002, resolution. In its application for
rehearing, TURN challenges the CPUC Settlement Agreement and its implementation. On March 12, 2002, SCE
submitted to the CPUC its opposition to the TURN application for rehearing.
Page 9
Recovery of Transition and Power Procurement Costs
SCE's transition costs include power purchases from QF contracts (which are the direct result of prior
legislative and regulatory mandates), recovery of certain generating assets and other costs incurred to provide
service to customers. Other costs include the recovery of income tax benefits previously flowed through to
customers, postretirement benefit transition costs and accelerated recovery of investment in SCE's nuclear
plants. Recovery of costs related to power-purchase QF contracts is permitted through the terms of each
contract. Legislation and regulatory decisions issued prior to the beginning of the rate freeze called for most
of the remaining transition costs to be recovered through the end of the four-year transition period (not later
than March 31, 2002).
There were three sources of revenue available to SCE for transition cost recovery through the TCBA mechanism:
revenue from the sale or valuation of generation assets in excess of book values, net market revenue from the
sale of SCE-controlled generation into the ISO and PX markets, and competition transition charge (CTC) revenue.
Revenue from the first two sources has not been available since January 2001. Net proceeds of the 1998 plant
sales were used to reduce transition costs, which otherwise had been expected to be collected through the TCBA
mechanism. State legislation enacted in January 2001 prohibits the sale of SCE's remaining generation assets
until 2006. SCE stopped selling power from its generation into the ISO and PX markets in January 2001, after
SCE's credit ratings were downgraded and the PX suspended SCE's trading privileges.
The CTC applied to all customers who were using or began using utility services on or after the CPUC's 1995
restructuring decision date. CTC revenue was determined residually (i.e., CTC revenue was the residual amount
remaining from monthly gross customer revenue under the rate freeze after subtracting the revenue requirements
for transmission, distribution, nuclear decommissioning and public benefit programs, and ISO payments and power
purchases from the PX and ISO). Residual CTC revenue was calculated through the TRA mechanism. In accordance
with the March 27, 2001, rate stabilization decision, both positive and negative residual CTC revenue was
transferred from the TRA to the TCBA on a monthly basis, retroactive to January 1, 1998. A previous decision had
called only for a transfer of positive residual CTC revenue (TRA overcollections) to the TCBA and there had not
been any positive residual CTC revenue between May 2000 and June 2001.
Because the regulatory and legislative actions did not occur that would have made recovery of transition costs
probable, SCE was unable to conclude as of December 31, 2000, that the recalculated TCBA net undercollection was
probable of recovery through the ratemaking process. As a result, the $2.9 billion TCBA net undercollection was
written off as a charge to earnings as of that date, and an additional $552 million (pre-tax) in net
undercollected transition costs were charged to earnings in 2001. Although the TCBA was written off, SCE
continued to calculate the account for ratemaking purposes, and the account reflected a $4.2 billion
undercollection as of September 1, 2001, which, as discussed below, is the effective date of the beginning of the
PROACT mechanism and the end of the TCBA mechanism. Additional information about the financial impact of this
undercollection and various ongoing and proposed regulatory efforts and judicial proceedings designed to address
or otherwise relating to it, is provided under "Regulatory Environment - Status of Transition and Power
Procurement Cost Recovery" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.
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 four classes of notes matured in December 1998 and March 2000,
2001, and 2002, respectively. The remaining three classes of notes valued at approximately $1.5 billion have
maturities beginning in 2003 and ending in 2007, with interest rates ranging from 6.28% to 6.42%.
Page 10
Other Revenue and Cost-Recovery Mechanisms
Revenue is determined by various mechanisms depending on the utility operation: distribution, transmission and
generation.
Distribution
Revenue related to distribution operations is being determined through a performance-based ratemaking mechanism
(PBR) and the distribution assets have the opportunity to earn a CPUC-authorized 9.49% return. The PBR mechanism
was to have ended in 2001, and SCE's distribution costs were to be established for 2002 in a general rate case
(GRC). Due to the industry upheaval of the last year, SCE was allowed to defer the GRC for one year, and a
proceeding was established to extend the existing PBR mechanism through 2002. In addition, legislative changes
required that the mechanism be altered to eliminate revenue volatility due to sales fluctuations. As a result,
the proceeding also addresses how to establish balancing accounts such that the revenues set in this proceeding
for 2001 and 2002 will be fully recovered. A CPUC proposed decision on the PBR mechanism for 2002 was issued in
January 2002. The proposed decision authorized SCE to use a formula to determine its distribution revenue
requirement for the last half of 2001 and 2002, and a revenue balancing account to ensure that variations in
sales do not result in under or overcollections. A final decision is expected by mid-2002. At this time, SCE
cannot predict the effect of the final decision on its results of operation.
At the expiration of the PBR, SCE is to begin recovering costs based on cost of service ratemaking. In December
2001, SCE filed its 2003 general rate case with the CPUC, requesting an increase of approximately $500 million in
revenue (compared to 2000 recorded revenue) for its distribution and generation operations. Hearings are
expected to begin in July 2002, with a final decision expected in second quarter 2003.
Transmission
Transmission revenue is being determined through the FERC-authorized rates that are subject to refund. Since the
initiation of the ISO in April 1998, transmission cost recovery has been under FERC authority. In July 2000, the
FERC issued a final decision in SCE's 1998 transmission rate case in which it ordered a reduction of
approximately $38 million to SCE's proposed annual base transmission revenue requirement of $213 million. Of the
total reduction of $38 million, about $24 million is associated with the rejection by the FERC of SCE's proposed
method for allocating overhead costs to transmission operations. SCE filed a conditional petition for rehearing
of the decision in August 2000, asking that the FERC reconsider the decision assuming that the CPUC does not
allow SCE to recover the $24 million in CPUC jurisdictional rates. In February 2001, SCE filed with the CPUC a
request to recover in CPUC-jurisdictional rates the overhead costs not permitted by the FERC to be included in
transmission rates. A CPUC decision is pending. In the meantime, SCE continues to collect transmission revenues
based on the originally proposed $213 million level, subject to refund pending final resolution of the 1998 rate
case. SCE expects that any refund amounts ultimately ordered by the FERC associated with transmission will not
be refunded to retail customers but will be credited to the PROACT balance reflecting SCE's procurement-related
obligations. Additionally, on January 31, 2002, SCE filed to increase the base transmission revenue requirement
to $280 million. This proposed increase is to reflect higher costs of capital, increased depreciation expense,
and increased operation and maintenance costs attributable to FERC-jurisdictional services. FERC action on
whether and when the proposed transmission rates will be placed into effect, subject to refund, is expected in
April 2002. As discussed above, under "CPUC Settlement Agreement," total rates to retail customers were
unchanged. Thus, SCE intends to file an equal and opposite reduction in generation rates upon acceptance by the
FERC of the increased transmission rates.
Generation
Effective with the commencement of the ISO and PX operations on March 31, 1998, generation costs were subject to
recovery through the market and transition cost recovery mechanisms, which included the nuclear ratemaking
agreements. During the rate freeze, revenue from generation-related operations has also been determined through
the market and transition cost recovery mechanisms, which also included the nuclear
Page 11
ratemaking agreements. The portion of revenue related to coal generation plant costs (Mohave Generating Station
(Mohave Station) and Four Corners Generating Station (Four Corners)) that were made uneconomic by electric
industry restructuring has been recovered through the transition cost recovery mechanisms. After April 1, 1998,
coal generation operating costs have been recovered through the market. The excess of power sales revenue from
the coal generating plants over the plants' operating costs has been accumulated in a coal generation balancing
account. SCE's costs associated with its hydroelectric plants have been recovered through a performance-based
mechanism. The mechanism set the hydroelectric revenue requirement and established a formula for extending it
through the duration of the electric industry restructuring transition period, or until market valuation of the
hydroelectric facilities, whichever occurred first. The mechanism provided that power sales revenue from
hydroelectric facilities in excess of the hydroelectric revenue requirement is accumulated in a hydroelectric
balancing account. In accordance with a CPUC decision issued in 1997, the credit balances in the coal and
hydroelectric balancing accounts were transferred to the TCBA at the end of 1998 and 1999. However, due to the
CPUC's March 27, 2001, rate stabilization decision, the credit balances in these balancing accounts were
transferred to the TRA on a monthly basis, retroactive to January 1, 1998, which later were transferred to the
TCBA on a monthly basis, retroactive to January 1, 1998, and subsequently replaced by the PROACT mechanism
effective September 1, 2001.
In June 2001, SCE filed a comprehensive proposal for new cost-of-service ratemaking for utility retained
generation (URG) through the end of 2002. After that time, SCE's URG-related revenue requirement will be
determined by the general rate case. The URG proposal calls for balancing accounts for SCE-owned generation, QFs
and interutility contracts, procurement costs and ISO charges based on either actual or CPUC-authorized revenue
requirements. Under the proposal, the four new balancing accounts would be effective January 1, 2001, for
capital-related costs, and February 1, 2001, for non-capital-related costs. In addition, SCE's unamortized
nuclear investment would be amortized and recovered in rates over a 10-year period, effective January 1, 2001.
Should this application be approved as filed, SCE expects to reestablish for financial reporting purposes its
unamortized nuclear investment and regulatory assets related to purchased-power settlement and flow-through
taxes, with a corresponding credit to earnings, and adjust the PROACT regulatory asset in accordance with the
final URG decision.
On January 18, 2002, a CPUC administrative law judge issued a proposed decision and a CPUC commissioner issued an
alternate proposed decision in the URG proceeding. Both the proposed and alternate proposed decisions adopt most
of the elements of SCE's application, but propose eliminating incremental cost incentive pricing for San Onofre,
effective January 1, 2002, and replacing it with balancing account treatment for San Onofre's operating costs,
subject to a later reasonableness review. On February 7, 2002, another CPUC commissioner issued an alternate
proposed decision recommending continuing the incentive pricing plan for San Onofre Units 2 and 3 through
December 31, 2003, as originally provided in CPUC decisions adopted in early 1996. If the CPUC approves SCE's URG
application, as filed, SCE expects to reapply accounting principles for rate-regulated enterprises for its
generation assets. These assets will then be subject to traditional cost-of-service regulation.
Generation Procurement Proceeding
In October 2001, the CPUC issued an order instituting rulemaking (OIR) to establish policies and cost recovery
mechanisms for generation procurement. The OIR directed SCE and the other major California electric utilities to
provide recommendations for establishing these policies and mechanisms to enable the utilities to resume their
power procurement responsibilities in 2003. In comments filed with the CPUC on November 26, 2001, SCE
recommended that the CPUC issue a procurement framework decision in February 2002, and direct the utilities to
submit their specific procurement plan proposals and related framework compliance proposals in March 2002. SCE
also proposed that a final decision be issued in October 2002 adopting utility-specific procurement plans. The
CPUC has not yet acted on SCE's recommendations, but is expected in second quarter 2002 to issue a scoping memo
setting forth issues to be addressed in this proceeding.
Page 12
FERC Related Matters
Due to a December 15, 2000, FERC order, SCE is no longer required to buy and sell power exclusively through the
ISO and PX. In mid-January 2001, the PX suspended SCE's trading privileges for failure to post collateral due to
SCE's rating agency downgrades. As a result, power from SCE's coal and hydroelectric plants is no longer being
sold through the market.
In October 2000, SCE filed a joint petition urging the FERC to immediately find the California wholesale
electricity market to be not workably competitive; immediately impose a cap on the price for energy and ancillary
services; and institute further expedited proceedings regarding the market failure, mitigation of market power,
structural solutions and responsibility for refunds. On December 15, 2000, the FERC released a final order
containing remedies and other actions in response to the problems in the California electricity market. On
December 26, 2000, SCE filed an emergency petition in the federal court of appeals challenging the FERC order and
seeking a writ of mandamus requiring the FERC to immediately establish cost-based wholesale rates. On January 5,
2001, the court denied SCE's petition. The effect of the denial is to leave in place the FERC's market
mechanisms. SCE's petition for rehearing remains pending.
In its December 2000 order, the FERC established an "underscheduling" penalty applicable to scheduling
coordinators that do not schedule sufficient resources to supply 95% of their respective loads. In December
2001, the FERC eliminated the underscheduling penalty, retroactive to January 1, 2001.
On March 9, 2001, the FERC directed 13 wholesale sellers of energy to refund $69 million or submit
cost-of-service information to the FERC to justify their prices above $273 per MWh during ISO Stage 3 emergencies
in January 2001. On April 9, 2001, SCE filed opposing the order as inadequate, particularly because the FERC is
unwilling to exercise any control over the sellers' exercise of market power during periods other than Stage 3
emergencies. On March 16, 2001, the FERC ordered six wholesale sellers of energy to refund an additional $55
million or submit cost-of-service information to the FERC to justify their prices above $430 per MWh during ISO
Stage 3 emergencies in February 2001. A Stage 3 emergency refers to 1.5% or less in reserve power, which could
trigger rotating blackouts in some neighborhoods.
On April 25, 2001, after months of extremely high power prices, the FERC issued an order providing for energy
price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve power). The order
established an hourly clearing price based on the costs of the least efficient generating unit during the
period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency periods
and price mitigation in the 11-state western region. The latest order is in effect until September 30, 2002.
After unsuccessful settlement negotiations among utilities, power sellers and state representatives, on July 25,
2001, the FERC issued an order that limited potential refunds from alleged overcharges to the ISO and PX spot
markets during the period from October 2, 2000, through June 20, 2001, and adopted a refund methodology based on
daily spot market gas prices. An administrative law judge will conduct evidentiary hearings on this matter. SCE
cannot predict the amount of any potential refunds. Under the CPUC Settlement Agreement, refunds will be applied
to the balance in the PROACT.
See the "Regulatory Environment - Generation and Power Procurement" and "Regulatory Environment - Rate
Stabilization Proceedings" sections of the MD&A that is incorporated by reference into Part II, Item 7 for more
information about SCE's revenue from its generation-related operations, recovery of its investment in its nuclear
facilities, and on accounting for generation-related assets and power procurement costs.
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 way in which the CPUC regulates SCE
Page 13
has been changing. The CPUC has issued both final and interim decisions regarding Direct Access, transition cost
recovery, and rate unbundling in the restructuring of the electric industry. While some of the decisions (such
as those regarding transition cost recovery) are being challenged by SCE both before the CPUC as well as in
judicial proceedings, the above decisions have affected cost recovery and rate regulation, and authorized new
ratemaking mechanisms.
Under the restructuring legislation, total rates for all customers were frozen at June 10, 1996, levels, although
residential and small commercial customers received a 10% reduction from the June 10, 1996, rate levels beginning
on January 1, 1998. These rate levels were to remain in effect for the remainder of the transition period;
however, on January 4, 2001, the CPUC issued an interim decision authorizing SCE to establish an interim
surcharge of 1(cent)per kilowatt-hour for 90 days, subject to refund. This was followed by a 3(cent)per kilowatt-hour
surcharge pursuant to the CPUC's interim rate stabilization order adopted on March 27, 2001. Under these frozen
rates, individual rate components (distribution, transmission, nuclear decommissioning, and public purpose
programs) are determined according to CPUC- or FERC-authorized mechanisms, with the generation rate determined
residually by subtracting these other components from the total rate. Beginning for rates effective in 1999, the
consolidation of the individual rate component changes and the calculation of the residual generation rate are
set forth for CPUC approval as part of the Revenue Adjustment Proceeding (RAP). On June 1, 1998, SCE filed its
first annual RAP Report in compliance with 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 TRA; (3) verify the regulatory account balances which were transferred to the TCBA on January 1, 1998 (see
"Annual Transition Cost Proceeding" 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.
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; (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;
(7) administration of SCE's self-generation deferral rate contracts; and (8) the proposed additional 7(cent)per MWh
credit to Direct Access customers associated with SCE's procurement of PX energy for bundled service customers.
On January 4, 2001, the CPUC issued its decision, which put SCE on notice that it will no longer be able to
prospectively recover 100% of its reliability must-run costs in the TRA, and adopted all other RAP issues SCE
requested.
On September 4, 2001, SCE filed its 2000/2001 RAP Report. On November 30, 2001, SCE amended its 2000/2001 RAP
report to reflect the CPUC Settlement Agreement. The CPUC Settlement Agreement indicates that the TCBA (which,
by definition, includes the TRA) shall have no further impact on SCE's retail electric rates. Thus, the only
issues remaining in SCE's 2000/2001 RAP Report are a review of SCE's Low Emission Vehicle program and SCE's
special contracts.
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. As a result, SCE's return
on equity from 1999 through 2001 was unchanged at 11.6%.
Page 14
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 Proceeding
In 1997, the CPUC established the ATCP to determine whether SCE's TCBA entries are recorded pursuant to
applicable CPUC decisions and the restructuring legislation, and whether certain expenses are justified. The
purpose of the ATCP was to ensure the recovery of generation-related transition costs through the TCBA. The TCBA
tracked the recovery of transition costs, including the accelerated recovery of plant balances, QF and purchased
power costs, and regulatory assets and obligations. As discussed above, the CPUC recently approved the new
ratemaking and accounting structure, referred to as the PROACT, to implement the CPUC Settlement Agreement. See
the discussion above under "Changing Regulatory Environment - PROACT." The PROACT mechanism replaces the ATCP
mechanism effective as of September 1, 2001. SCE will prepare and file revised testimony in its ATCP proceedings
described below to withdraw all matters related to entries made on or before August 31, 2001. It is not known at
this time whether or to what extent the CPUC's Office of Ratepayer Advocates (ORA), may recommend any
disallowances related to the revised testimony.
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 with applicable CPUC decisions
and the restructuring legislation. On February 17, 2000, the CPUC issued a decision finding that SCE's
calculation of the TCBA for the record period was correct. The decision changed the accounting methodology used
to estimate the market value of retained generating assets and required that SCE credit the TCBA for the
aggregate net book value of certain of SCE's non-nuclear assets.
SCE reviewed the decision and discovered that the CPUC had inadvertently omitted establishing a new account to
record the corresponding debit to the TCBA credit for the aggregate net book value of any remaining non-nuclear
generation assets. SCE proposed that the Generation Asset Balancing Account (GABA) be established in order to
avoid problems associated with limits for short-term borrowing purposes. The CPUC agreed, and on June 8, 2000,
established the GABA. SCE filed its compliance advice letter in June 2000. On April 13, 2000, SCE filed a
petition for modification seeking modification of the decision to restore recovery of authorized return, taxes,
and depreciation for its hydro assets through the TCBA. It is not known when the CPUC will act on SCE's petition
for modification.
2000 ATCP
On September 1, 2000, SCE filed its 2000 ATCP setting forth entries made to the TCBA and other generation-related
accounts for the months of July 1999 through June 2000. ORA issued its report on February 27, 2001. In its
report, ORA recommended, among other things, that the CPUC: (1) defer review of SCE's natural gas procurement
and management activities, including a $10 million post record period adjustment, until the 2001 ATCP;
(2) disallow $882,000 of employee-related transition costs; and (3) adjust the TCBA undercollection downward $4.35
million to reflect the reasonableness of post record period adjustments. ORA subsequently withdrew its
recommendation to defer its review of SCE's natural gas procurement and management activities and found the
$10,000,000 post-period adjustment to be reasonable as well as SCE's natural gas procurement and management
activities. The only contested issue that remains is the $882,000 in employee-related transition costs.
Hearings were held in May 2001, and briefs were filed in June 2001. The CPUC has not yet issued a decision
concerning the 2000 ATCP.
Page 15
2001 ATCP
On September 4, 2001, SCE filed its 2001 ATCP report setting forth entries made to the TCBA and other generation
memorandum accounts for the months of July 2000 through June 2001. On October 11, 2001, the ORA filed a protest
to SCE's application which included a motion to consolidate SCE's application with those of PG&E and SDG&E. SCE
opposed consolidation of its ATCP with the other application. A prehearing conference to establish a procedural
schedule was held on November 14, 2001, at which time the administrative law judge ruled that SCE's ATCP would
not be consolidated with those of PG&E and SDG&E.
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 would have continued through December 2001,
earning a 7.35% fixed rate of return. However, due to the various unresolved regulatory and legislative issues
(see discussion in "Changing Regulatory Environment" above), SCE is not able to conclude that the unamortized
nuclear investment regulatory assets are probable of recovery through the ratemaking process. As a result, these
balances were written off as a charge to earnings as of December 31, 2000.
In 1996, the CPUC adopted an incentive plan for SCE's San Onofre Units 2 and 3 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, required the recovery of the San Onofre investment to be
completed by December 31, 2001. Due to the various unresolved regulatory and legislative issues (see discussion
in "Regulation" above), SCE was not able to conclude that the unamortized nuclear investment regulatory assets
were probable of recovery through the ratemaking process. As a result, these balances were written off as a
charge to earnings as of December 31, 2000.
In addition, the incentive plan adopted by the CPUC in 1996 adopted a preset price for each kWh of energy
generated at San Onofre during the eight-year period. Under the CPUC Settlement Agreement, SCE also retained the
ability to request recovery of the cost of replacement energy for periods in which San Onofre will not generate
power through energy cost adjustment clause filings and, beginning September 1, 2001, as part of the PROACT
mechanism. San Onofre Units 2 and 3 incentive pricing was authorized to continue through December 31, 2003. On
January 18, 2002, the assigned administrative law judge issued a proposed decision and CPUC President Loretta
Lynch issued an alternate proposed decision in the URG proceeding both proposing to eliminate the existing cost
recovery procedure for San Onofre Units 2 and 3, effective January 1, 2002, and to replace it with a balancing
account treatment of San Onofre Units 2 and 3 operating costs, subject to a later reasonableness review. On
February 7, 2002, CPUC Commissioner Bilas issued an alternate proposed decision that continued the existing
procedure for San Onofre Units 2 and 3 through December 31, 2003. The restructuring legislation allows SCE to
continue to collect funds for decommissioning expenses through traditional ratemaking treatment.
SCE requested in its URG application to recover the unamortized cost of the nuclear investment regulatory asset
over a ten-year period, retroactive to January 1, 2001. All present proposed decisions and alternates in the URG
proceeding would authorize this recovery. If any of the present URG proposed decisions are adopted, SCE would
reestablish for financial reporting purposes its unamortized nuclear investment in San Onofre and Palo Verde and
related flow-through taxes as regulatory assets with a corresponding credit to earnings.
In 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.
Page 16
Palo Verde Nuclear Generating Station
In 1996, SCE filed an application requesting adoption of a new rate mechanism for Palo Verde consistent with that
of San Onofre Units 2 and 3. See the discussion under "Other Rate Matters - San Onofre Nuclear Generating
Station Units 2 and 3." On November 15, 1996, SCE, the ORA, and a consumer group entered into a settlement
agreement, which was approved by the CPUC on December 20, 1996. The settling parties agreed that SCE would
recover its share of Palo Verde incremental operating costs, except if those costs exceed 95% of the levels
forecast by SCE in its application by more than 30% in any given year. In such cases, SCE must demonstrate that
the aggregate amount of the costs exceeding the forecast in that year is 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.
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 would have continued through December 2001,
earning a 7.35% fixed rate of return. However, due to certain unresolved regulatory and legislative issues
discussed above with respect to San Onofre, the unamortized nuclear investment regulatory assets were written off
as a charge to earnings as of December 31, 2000. See the discussion under "Changing Regulatory Environment,"
above.
In January 1997, the CPUC authorized the future Palo Verde operating costs, including nuclear fuel costs and
incremental capital expenditures, to be subject to balancing account treatment through 2001. Beginning
August 31, 2001, the balancing account became part of the PROACT mechanism. In January 1997, the CPUC also
authorized continuation of the existing nuclear unit incentive procedure for Palo Verde. The existing procedure
will continue only for purposes of calculating a reward for performance of any unit above an 80% capacity factor
for a fuel cycle.
Beginning in 2002, SCE was required to share the net benefits received from the operation of Palo Verde equally
with ratepayers. In a September 2001 decision, the CPUC granted SCE's request to eliminate the Palo Verde
post-2001 benefit sharing mechanism and to continue the current rate treatment for Palo Verde, including the
continuation of the existing nuclear unit incentive procedure with a 5(cent)per kWh cap on replacement power costs,
until resolution of SCE's next general rate case or further CPUC action. Palo Verde's existing nuclear unit
incentive procedure calculates a reward for performance of any unit above an 80% capacity factor for a fuel
cycle.
Fuel Supply and Purchased Power Costs
In 2001, PX/ISO purchased power expense decreased in accordance with an emergency order signed by Governor Davis
authorizing the CDWR to begin making emergency power purchases for SCE's customers beginning on January 17,
2001. In February 2001, Assembly Bill 1 (First Extraordinary Session, AB 1X) was enacted into law. AB 1
authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to retail
customers being served by SCE and authorized the CDWR to issue bonds to finance electricity purchases. (See
discussion above under "Changing Regulatory Environment - CDWR Power Purchases").
In 2000, PX/ISO purchased power expense increased significantly due to electricity shortages and dramatic price
increases for natural gas, a key input of electricity production. The increased volume of higher priced PX
purchases was minimally offset by increases in PX sales revenue and ISO net revenue, as well as an increase in
the market value of gas call options. Increases in the options' market value decreased purchased power expense.
These gas call options (which were sold in October 2000) mitigated SCE's transition cost recovery exposure to
increases in energy prices.
Page 17
SCE's sources of energy during 2001 were as follows: 34% purchased power; 29.9% CDWR, ISO and PX; 19.1% nuclear;
13.4% coal; and 3.6% hydro.
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. SCE permanently
assigned its contract with El Paso in November 2000 paying $12.3 million in consideration to a third party.
Nuclear Fuel Supply
SCE has contractual arrangements covering 100% of the projected nuclear fuel requirements for San Onofre through
the years indicated below:
Uranium concentrates(*)........................................................... 2003
Conversion................................................................... 2003
Enrichment................................................................... 2003
Fabrication.................................................................. 2005
---------------
(*) Assumes the San Onofre participants meet their supply obligations in a timely manner.
Assuming normal operation and full utilization of existing on-site fuel-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. Additional on-site spent fuel
storage capacity is being developed for availability in 2003 for San Onofre Unit 1, and by 2006 for San Onofre
Units 2 and 3.
Participants at Palo Verde have contractual agreements for uranium concentrates to meet projected requirements
through 2002. Independent of arrangements made by other participants, SCE will furnish its share of uranium
concentrates requirements through at least 2001 from existing contracts. Contracts covering 100% of requirements
are in place for uranium enrichment and conversion through 2008 and fabrication through 2015.
Palo Verde has existing fuel storage pools and is in the process of completing construction of a new facility for
on-site dry storage of spent fuel. With the existing storage pools and the addition of the new facility, spent
fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through
the term of the plant license.
Coal Supply
SCE purchases coal pursuant to long term contracts to provide stable and reliable fuel supplies to its two
coal-fired generating stations (Mohave Station and Four Corners). SCE entered into a coal contract, dated
September 1, 1966, with BHP Navajo Coal Company, the predecessor to the current owner of the Navajo mine, to
supply coal to Units 4 and 5 of Four Corners. The coal supply contract's initial term is through 2004 and
includes extension options for up to 15 additional years. For additional discussion of the litigation affecting
the coal supply contract for the Mohave Station, see "Navajo Nation Litigation" in Part I, Item 3 of this
report. SCE does not have reasonable assurance of an adequate coal supply for operating the Mohave Station after
2005. If reasonable assurance of an adequate coal supply is not obtained, it will become necessary to shut down
the Mohave Station after December 31, 2005. If the station is shut down
Page 18
at that time, the shutdown is not expected to have a material adverse impact on SCE's financial position or
results of operations, assuming the remaining book value of the station (approximately $88 million as of
December 31, 2001), and plant closure and decommissioning-related costs are recoverable in future rates. SCE
cannot predict what effect any future actions by the CPUC may have on this matter.
Environmental Matters
Legislative and regulatory activities in the areas of air and water pollution, waste management, hazardous
chemical use, noise abatement, land use, aesthetics, and nuclear control continue to result in the imposition of
numerous restrictions on SCE's operation of existing facilities, on the timing, cost, location, design,
construction, and operation by SCE of new facilities, and on the cost of mitigating the effect of past operations
on the environment. These activities substantially affect future planning and will continue to require
modifications of SCE's existing facilities and operating procedures. SCE is unable to predict the extent to
which additional regulations may affect its operations and capital expenditure requirements.
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.
SCE also owns a 56% undivided interest in the Mohave Station located in Laughlin, Nevada, which is subject to
certain air quality programs. SCE is the operator of the Mohave Station on behalf of its co-owners. 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 co-owners, a consent decree, which was approved by the Court
in December 1999. The decree was designed also to address concerns raised by two EPA programs regarding regional
haze and visibility. The EPA issued its final rulemaking regarding regional haze regulations on July 1, 1999.
That final rule does not impose any additional emissions control requirements on the Mohave Station beyond
meeting the provisions of the consent decree.
Regarding visibility, a study was undertaken 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. In
June 1999, the EPA issued an advanced notice of proposed rulemaking regarding assessment of visibility impairment
at the Grand Canyon. The EPA issued its final rule on February 8, 2002, which incorporates the terms of the
consent decree into the Visibility Federal Implementation Plan for the state of Nevada, making the terms of the
consent decree federally enforceable.
SCE's share of the costs of complying with the consent decree and taking other actions to continue operation of
the Mohave Station is estimated to be approximately $560 million over the next four years. However, SCE has
suspended its efforts to seek approval from the CPUC to install the Mohave Station controls because it has not
obtained reasonable assurance of an adequate coal supply for operating Mohave Station beyond 2005. For
additional discussion, see "Business - Fuel Supply and Purchased Power Costs - Coal Supply."
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
Page 19
emissions if the EPA's Administrator makes certain findings. The study's final report to Congress concluded that
mercury from coal-fired plants 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 plants are negligible and that there is no need
for further evaluation of the risks of hazardous air pollutants emitted from such plants.
In December 2000, the EPA announced its intentions to regulate mercury emissions from coal-fired and oil-fired
electric power plants under Section 112 of the Clean Air Act and indicated that it would propose a rule to
regulate these emissions by no later than December 15, 2003. The EPA expects to finalize this rule by
December 15, 2004. Because SCE does not know what the EPA may require with respect to this issue, SCE is
presently unable to evaluate the impact of potential mercury regulations on the operations of its coal- and
oil-fired generating facilities.
On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities,
not including SCE, for alleged violations of the Clean Air Act's "new source review" requirements related to
modifications of air emissions sources at electric generating stations located in the southern and midwestern
regions of the United States. Several states have joined these lawsuits. In addition, the EPA has issued
administrative notices of violation alleging similar violations at additional power plants owned by some of the
same utilities named as defendants in the Department of Justice lawsuit, as well as other utilities, and also
issued an administrative order to the Tennessee Valley Authority for similar violations at certain of its power
plants. The EPA has also issued requests for information pursuant to the Clean Air Act to numerous other
electric utilities seeking to determine whether these utilities also engaged in activities that may have been in
violation of the Clean Air Act's new source review requirements.
To date, one utility--the Tampa Electric Company--has reached a formal agreement with the United States (February
2000) to resolve alleged new source review violations. Two other utilities, the Virginia Electric Power Co. and
Cinergy Corp., have reached agreements in principle with the EPA (November and December 2000, respectively). In
each case, the settling party has agreed to incur over $1 billion in expenditures over several years for the
installation of additional pollution controls, the retirement or repowering of coal-fired generating units,
supplemental environmental projects and civil penalties. These agreements provide for a phased approach to
achieving required emission reductions over the next 10 to 15 years. The settling utilities have also agreed to
pay civil penalties ranging from $3.5 million to $8.5 million.
SCE owns a 48% undivided interest in Units 4 and 5 at the Four Corners coal plant in New Mexico, which is
operated by Arizona Public Service Company (APS). On June 27, 2000, the EPA issued a request for information to
the Four Corners plant. On September 1, 2000, APS replied to the request. To date, no further action has been
taken with respect to the Four Corners plant.
Regulations under the Clean Water Act require permits for the discharge of certain pollutants into United States
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 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
Page 20
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 undiscounted amounts). SCE's environmental liabilities include
expenses to remediate sites currently owned by SCE or by third parties, and for which SCE has been named as one
of the potential responsible parties. They also include mitigation expenses associated with the construction of
its San Onofre nuclear power plant.
As of December 31, 2001, SCE's recorded estimated minimum liability to remediate its 42 identified sites is
$111 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 $279 million. The upper limit of this
range of costs ($390.2 million) was estimated using assumptions least favorable to SCE among a range of
reasonably possible outcomes. SCE has sold all of its gas-fueled generation plants and has retained some
liability associated with the divested properties.
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. No reasonable estimate of cleanup costs can now
be made for these sites. Thus, the estimated minimum liability and possible range does not include any monetary
information associated with these sites.
The CPUC allows SCE to recover environmental-cleanup costs at certain sites, representing $50 million of its
recorded liability, through an incentive mechanism. Under this mechanism, SCE will recover 90% of cleanup costs
through customer rates. Shareholders fund the remaining 10%, with the opportunity to recover these costs from
insurance carriers and other third parties subject to certain time limitations. 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 $76 million for its estimated minimum
environmental-cleanup costs expected to be recovered through customer rates.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation expenditures in each
of the next several years are expected to range from $10 million to $25 million. Recorded expenditures for 2001
were $16.8 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.
Currently, environmental advocacy groups and regulatory agencies in the United States are focusing considerable
attention on carbon dioxide emissions from coal-fired power plants and their potential role in the
"global-warming" issue. SCE believes that evolving environmental laws and regulations will need to recognize that
coal-fired power plants must continue to play an essential role in providing electricity
Page 21
supply. Nevertheless, the fact that SCE is a co-owner of two coal-fired power plants exposes the company to the
uncertainties and risks inherent in the environmental laws and regulations applicable to such plants. The
adoption of laws and regulations to implement carbon dioxide controls could adversely impact SCE's coal plants.
Coal plant emissions of nitrogen and sulphur oxides, mercury and particulates also are potentially subject to
increased controls. The Bush administration, Congress and the EPA are now considering various proposals that
would impose, or modify, controls on these power plant emissions. As a regulated utility, SCE has access to
cost-of-service ratemaking that may allow it to recover costs reasonably incurred in complying with environmental
regulations. For additional discussion, see "Business - Environmental Matters."
SCE's projected environmental capital expenditures are $1.3 billion for the 2002 - 2006 period, mainly for
undergrounding certain transmission and distribution lines.
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 nuclear generating station Units 2 and 3.
These plants are located in Central and Southern California.
SCE also operates and owns a 56% undivided interest (885 MW) in the Mohave Station, which consists of two
coal-fueled generating units in Clark County, Nevada. See "Business - Environmental Matters and - Fuel Supply
and Purchased Power Costs - Coal Supply," above, for a discussion of the coal supply and environmental issues
affecting the Mohave Station.
SCE also owns a 15.8% (590 MW net) share of Palo Verde nuclear generating station, which is located near Phoenix,
Arizona, and a 48% undivided interest (754 MW net) in Units 4 and 5 at the Four Corners, which is a coal-fueled
generating plant located in New Mexico. Palo Verde and Four Corners are operated by other utilities.
In April 2000, SCE agreed to sell its 15.8% interest in Palo Verde and its 48% interest in Four Corners to
Pinnacle West Energy. In May 2000, after conducting an auction that had been approved by the CPUC, SCE agreed to
sell its 56% interest in Mohave to The AES Corporation. All three of these transactions remained subject to
certain conditions, including the final approval of the CPUC. However, the CPUC suspended action on these sales
as problems began to develop in the California electricity market. As indicated above, subsequently enacted
California state legislation barred the sale of utility generating facilities until 2006. Consequently, SCE then
withdrew its applications to sell its shares of Palo Verde, Four Corners and Mohave plants.
During the fall of 2003, the steam generators are scheduled to be replaced at Palo Verde Unit 2. SCE and the
other participants are also considering issues related to the potential replacement of the steam generators in
Units 1 and 3. Although a final determination of whether Units 1 and 3 steam generators will be replaced has not
yet been made, SCE and the other participants have approved the expenditure of $25.6 million ($4.0 million SCE
share) in 2002 to procure long lead-time materials for fabrication of a spare set of steam generators for either
Unit 1 or 3. This action will provide Palo Verde participants an option to replace the steam generators in
Unit 1 as early as fall 2005 or in Unit 3 as early as fall 2007 should they ultimately decide to do so. If the
participants decide to proceed with the earliest possible steam generator replacement at both Units 1 and 3, SCE
estimates that its portion of the fabrication and installation costs and associated power upgrade modifications
would be approximately $70 million over the next seven years.
At year-end 2001, the existing SCE-owned generating capacity (summer effective rating) was divided approximately
as follows: 44% nuclear, 32% coal, 24% hydroelectric, and less than 1% diesel. San Onofre, Four Corners, certain
of SCE's substations and portions of its transmission, distribution and communication systems are located on
lands of the United States or others under (with minor exceptions)
Page 22
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 United States lands pursuant to, 30- to 50-year
governmental licenses that expire at various times between 2001 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 dependable operating capacity of about 112.67 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 utility industry
restructuring legislation. In June 2000, SCE credited the TCBA with the proposed excess of market value over
book value of its hydroelectric generation assets and simultaneously recorded the same amount in the GABA (see
"1998 ATCP" above), pursuant to a CPUC decision. This balance was to remain in GABA until final market valuation
of the hydroelectric assets. Due to the various unresolved regulatory and legislative issues (as discussed in
Regulation), the GABA transaction was reclassified back to the TCBA, and the TCBA balance (as recalculated based
on a March 27, 2001, CPUC interim decision) was written off as of December 31, 2000. Pursuant to the terms of
the CPUC Settlement Agreement, SCE is no longer proposing to market value its hydro facilities. Accordingly, SCE
filed a motion on November 15, 2001, to withdraw its December 1999 petition.
In 2001, the capacity factors in 2001 for SCE's principal generation resources were: 30% for SCE's hydroelectric
plants (lower than average due to below-normal water conditions); 80% for San Onofre; 74% for the Mohave Station;
87% for Four Corners Units 4 and 5; and 88% 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 $3.6 billion in principal amount was outstanding on
March 1, 2002. 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 insubstantial 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
United States and a lease from The Navajo Nation, may be subject to possible defects. These defects include
possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the
applicable recording law and the record systems of the Bureau of Indian Affairs and The Navajo Nation, the
possible inability of SCE to resort to legal process to enforce its rights against The Navajo Nation without
Congressional consent, possible impairment or termination under certain circumstances of the easement and lease
by The Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the Trust
Indenture lien against SCE's interest in the easement, lease, and improvements on Four Corners.
Page 23
Construction Program and Capital Expenditures
Cash required by SCE for its capital expenditures totaled $569 million in 2001, $1.0 billion in 2000, and
$959 million in 1999. Construction expenditures for the 2002 - 2006 period are forecasted at $6.2 billion, but
may have to be changed depending on SCE's financial situation.
In addition to cash required for construction expenditures for the next five years as discussed above,
$3.6 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 2006 assume, among other things,
satisfactory reimbursement of cost incurred during the California energy crisis, 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.
SCE's ability to obtain financing has been affected adversely by the effects of California's energy crisis during
2000 and 2001, as described above in Part I under "Changing Regulatory Environment - Liquidity Issues."
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.
SCE requested in its URG application to recover the unamortized cost of the nuclear investment regulatory asset
over a ten-year period, retroactive to January 1, 2001. All present proposed decisions and alternates in the URG
proceeding would authorize this recovery. If any of the present URG proposed decisions are adopted, SCE would
reestablish for financial reporting purposes its unamortized nuclear investment in San Onofre and Palo Verde and
related flow-through taxes as regulatory assets with a corresponding credit to earnings.
San Onofre Nuclear Generating Station
San Onofre Unit 3 suffered a forced outage because of the failure of an electrical component in the non-nuclear
portion of the plant resulting in a fire on February 3, 2001. The electrical circuit breaker failure and
resultant fire had significant consequences beyond just the damage to the electrical components and cabling.
Loss of electrical power supply also resulted in loss of lubricating oil to the turbine generator system while it
was still rotating. This caused severe and extensive damage to the turbine generator rotors, bearings and other
components. San Onofre Unit 3 returned to service on June 1, 2001, and has operated reliably since that date.
The lost revenue due to this repair outage was covered by SCE's insurance.
The San Onofre Units 2 and 3 steam generator design allows for the removal of up to 10% of the tubes before the
rated capacity of the unit must be reduced. Increased tube degradation was found during routine inspections in
1997. To date, 8% of Unit 2's tubes and 6% of Unit 3's tubes have been removed from service. A decreasing
(favorable) trend in degradation has been observed in more recent inspections.
Page 24
Additionally, in the summer of 2000, SCE applied for a coastal permit to construct a dry cask spent fuel storage
facilities for Units 2 and 3. This permit was approved, with certain conditions, by the California Coastal
Commission at its meeting on March 13, 2001.
Nuclear Facility Decommissioning
In 1992, the CPUC approved a settlement agreement between SCE and the ORA to discontinue operation of San Onofre
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 dry cask spent fuel storage facility 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 will be completed in three phases,
(1) decontamination and dismantling of all structures and most foundations, (2) spent fuel storage monitoring, and
(3) fuel storage facility dismantling and site restoration. Phase one is anticipated to continue through 2008.
Phase two is expected to continue until 2026. Phase three will be conducted concurrently with San Onofre Units 2
and 3 decommissioning projects. All of SCE's reasonable San Onofre Unit 1 decommissioning costs will be paid
from its nuclear decommissioning trust funds.
SCE plans to decommission its nuclear generating facilities as expeditiously as possible once authorized by the
NRC. Decommissioning is expected to begin after the plants' operating licenses expire. The operating licenses
expire in 2022 for San Onofre Units 2 and 3, and in 2026 and 2028 for the Palo Verde units. Decommissioning
costs, which are recovered through non-bypassable customer rates and are recorded as a component of depreciation
expense.
Decommissioning is estimated to cost $2.1 billion in year 2001 dollars based on site-specific studies performed
in 1998 for San Onofre and Palo Verde. This estimate considers the total cost of decommissioning and dismantling
the plant, including labor, material, burial, and other costs. The site-specific studies are updated
approximately every three years. Changes in the estimated costs, timing of decommissioning, or the assumptions
underlying these estimates could cause material revisions to the estimated total cost to decommission in the
near-term. SCE estimates that it will spend approximately $8.6 billion in nominal dollars through completion of
decommissioning of its nuclear facilities.
Decommissioning expenses were $96 million in 2001, $106 million in 2000, and $124 million in 1999.
The accumulated provision for decommissioning excluding San Onofre Unit 1 and unrealized holding gains was
$1.5 billion at December 31, 2001, $1.4 billion at December 31, 2000, and $1.3 billion at December 31, 1999. The
estimated cost to decommission San Onofre Unit 1 is approximately $300 million in year 2001 dollars and is
recorded as a liability.
Decommissioning funds collected in rates are placed in independent trust accounts 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 United States results in claims and/or costs which
exceed the primary insurance at that plant site. Federal
Page 25
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 $35 million per year. Insurance premiums are charged to operating expense.
The Federal law requiring the nuclear insurance described above for all new NRC licensed reactors was due to
expire in August 2002. The United States Senate passed an amendment to the Energy bill which renews the law for
another 10 years. The United States House of Representatives has also passed a bill renewing the law for another
10 years. Congressional action to reconcile differences between the House and Senate versions appears to be
necessary. Even if this Federal law did expire, all of the nuclear insurance provisions required by the law, as
described above, will still apply to SCE, as an owner of the existing San Onofre and Palo Verde units, until the
termination of each unit's NRC license and the removal of all radioactive materials from its site.
-
Page 26
Item 3. Legal Proceedings
San Onofre Personal Injury Litigation
SCE is actively involved in four 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
United States 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 Appeals, 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 Appeals 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 United States 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 Appeals. Briefing on the appeal was completed in
January 1999, oral argument took place on February 10, 2000, and the matter was taken under submission. On
July 20, 2000, the Ninth Circuit Court of Appeals issued an opinion reversing the District Court judgment and
ordering a retrial as to both defendants. On August 10, 2000, SCE filed a petition for rehearing with the Ninth
Circuit Court of Appeals. On September 27, 2001, the Ninth Circuit issued a new opinion affirming the District
Court judgment in favor of all defendants. On October 9, 2001, plaintiffs filed a petition for rehearing or, in
the alternative, for a rehearing en banc, with the Ninth Circuit. On December 28, 2001, the Ninth Circuit denied
plaintiffs' petition for rehearing and its alternative petition for a rehearing en banc. Plaintiffs could seek
further review in the United States Supreme Court.
On November 28, 1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the United
States 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.
On May 9, 2001, SCE was served with a complaint filed on March 1, 2001, by a former contract worker at San Onofre
and his wife in the United States District Court for the Southern District of California. In addition to SCE,
plaintiffs also named as defendants Combustion Engineering and Bechtel Construction Company, the employer of the
former San Onofre worker. Pursuant to an agreement of the parties as described below, all proceedings in this
matter have been stayed.
In March 1999, SCE reached an agreement with the plaintiffs in the above four cases at the United States District
Court level to stay all proceedings including trial, pending the results of the case currently before the Ninth
Circuit Court of Appeals. 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. The stay will remain in effect
until the conclusion of the appellate process, including filing and disposition of any petitions for rehearing in
the Ninth Circuit or petitions for certiorari in the United States Supreme Court.
SCE was previously involved, along with other defendants, in two earlier cases raising allegations similar to
those described above. Plaintiffs in those cases have agreed to a stay of proceedings similar to the stay
agreements entered into by plaintiffs with SCE in the above four lawsuits. 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.
Page 27
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 the 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. That
decision is on appeal. 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, and the
Court calendared all pending motions for hearing on March 15, 2001. On March 15, 2001, the District Court heard
arguments, granted the Hopi Tribe's motion to intervene and denied Peabody and SCE's motions to dismiss. The
Court, however, did grant Salt River's motion on jurisdictional grounds. The Court denied SCE's and Peabody's
motions to allow an interlocutory appeal.
Peabody and SCE filed cross claims against the Navajo Nation on February 21, 2002, alleging that the Navajo
breached a settlement agreement between Peabody and the Navajo Nation by filing their lawsuit. Additionally,
Peabody has filed a motion to transfer the matter to Arizona in conjunction with their demand that the matter be
submitted to arbitration pursuant to the settlement agreement. A response to the cross claim or the motion to
transfer has not yet been received.
Shareholder Litigation
Two purported class actions were filed in October 2000 and March 2001, and involved securities fraud claims
arising from alleged improper accounting by Edison International and SCE of undercollections in SCE's TRA. These
actions, as described below, were dismissed with prejudice on March 8, 2002.
On October 30, 2000, a purported class action lawsuit was filed in federal district court in Los Angeles against
SCE and Edison International. By agreement of the parties and the Court, plaintiffs amended their complaint on
two occasions. Pursuant to this stipulation, on March 5, 2001, plaintiffs filed a second amended complaint. The
second amended complaint alleged that the companies were engaging in securities fraud by over-reporting income
and improperly accounting for the TRA undercollections. The second amended complaint purported to be filed on
behalf of a class of persons who purchased Edison International common stock beginning June 1, 2000, and
continuing until such time as TRA-related undercollections were recorded as a loss on SCE's income statements.
The second amended complaint sought compensatory damages caused by the alleged fraud as well as punitive
damages. As discussed below, this lawsuit was consolidated with another action, a new consolidated complaint was
filed and defendants responded to the consolidated complaint.
On March 15, 2001, a purported class action lawsuit was filed in federal district court in Los Angeles,
California, against Edison International and SCE and certain of their officers. The complaint alleged that the
defendants engaged in securities fraud by misrepresenting and/or failing to disclose material facts
Page 28
concerning the financial condition of Edison International and SCE, including that the defendants allegedly
overreported income and improperly accounted for the TRA undercollections. The complaint purported to be filed
on behalf of a class of persons who purchased publicly-traded securities of Edison International between May 12,
2000, and December 22, 2000. Plaintiffs sought damages, in an unstated amount, in connection with their purchase
of securities during the class period.
On August 3, 2001, the plaintiffs in both cases filed a consolidated complaint on behalf of alleged shareholders
of Edison International, naming as defendants SCE, Edison International, and certain officers of Edison
International. The consolidated complaint alleged that the defendants engaged in securities fraud by
misrepresenting and/or failing to disclose material facts concerning the financial condition of Edison
International and SCE, including that defendants allegedly over-reported income and improperly accounted for the
TRA undercollections. The complaint purported to be filed on behalf of a class of persons who purchased Edison
International stock between July 21, 2000, and April 17, 2001. Plaintiffs sought damages in an unstated amount
in connection with their purchase of securities during the class period. On September 17, 2001, the defendants
filed a motion to dismiss for failure to state a claim. On March 8, 2002, the Court issued an order granting the
motion and dismissing the complaint with prejudice as to all defendants. Plaintiffs could appeal this ruling to
the Ninth Circuit Court of Appeals.
Qualifying Facilities Litigation
SCE is involved in a number of legal actions brought by various QFs, alleging SCE failed to timely pay for power
deliveries made from November 1, 2000, through March 26, 2001. The QF plaintiffs include gas-fired cogenerators
and owners of solar, wind, geothermal and biomass projects. The lawsuits, in aggregate, seek payments of more
than $833,000,000 for energy and capacity supplied to SCE under QF contracts, and in some cases additional
damages. Many of these QF lawsuits also seek an order allowing the suppliers to stop providing power to SCE so
that they may sell to other purchasers.
The table below sets forth the principal parties, filing date and court jurisdiction of the QF litigation:
Principal Party Date Filed Court Jurisdiction
--------------- ---------- ------------------
City of Long Beach February 9, 2001 Los Angeles County Superior Court,
South District
Salton Sea Power Generation, L.P. February 20, 2001 Imperial County Superior Court
Beowawe Power, L.L.C. March 2, 2001 United States District Court,
District of Nevada
Mohave 16/17/18 LLC; Ridgetop March 5, 2001 Los Angeles County Superior Court,
Energy, L.L.C. Central District
IMC Chemicals, Inc. March 26, 2001 San Bernardino County Superior Court,
Barstow District
NP Cogen, Inc. March 28, 2001 Los Angeles County Superior Court,
Central District
Watson Cogeneration Co. March 29, 2001 Los Angeles County Superior Court
O.L.S. Energy-Chino March 30, 2001 Los Angeles County Superior Court,
Central District
E.F. Oxnard, Inc. April 2, 2001 United States District Court,
Central District
Herber Geothermal Company April 6, 2001 Imperial County Superior Court
Inland Paperboard and April 9, 2001 United States District Court,
Packaging, Inc. Central District
Mammoth Pacific, L.P. April 9, 2001 Mono County Superior Court
Brea Power Partners, L.P. April 5, 2001 Los Angeles County Superior Court,
Central District
Kern River Cogeneration Company April 10, 2001 Kern County Superior Court
Page 29
Southern California Sunbelt March 27, 2001 Riverside County Superior Court,
Developers Indio Branch
Corona Energy Partners, LTD April 5, 2001 Riverside County Superior Court
Procter & Gamble Paper April 11, 2001 Ventura County Superior Court
Products Company
Oak Creek Wind Power, Inc. April 16, 2001 Kern County Superior Court, Central
District
Willamette Industries, Inc. April 12, 2001 Ventura County Superior Court
Mammoth Pacific, L.P. May 25, 2001 Los Angeles County Superior Court
Berry Petroleum Company May 2, 2001 Los Angeles County Superior Court,
Central District
Ace Cogeneration Company May 1, 2001 Los Angeles County Superior Court,
Central District
Cabazon Power Partners LLC May 2, 2001 Los Angeles County Superior Court,
Central District
U.S. Borax Inc. May 6, 2001 Kern County Superior Court
Black Hills Ontario, LLC May 7, 2001 San Bernardino County Superior Court,
Rancho Cucamonga District
Luz Solar Partners LTD., III May 8, 2001 Sacramento County Superior Court
Rio Bravo Jasmin May 16, 2001 Los Angeles County Superior Court
CalWind Resources May 18, 2001 Los Angeles County Superior Court
Wheelabrator Norwalk Energy Co. Inc. May 18, 2001 Los Angeles County Superior Court,
Southeast District
Smurfit Stone Container May 24, 2001 United States District Court,
Central District
Ripon Cogeneration, Inc. June 6, 2001 Los Angeles County Superior Court
San Gorgonio Westwinds II, LLC June 8, 2001 Riverside County Superior Court
Colmac Energy, Inc. June 12, 2001 Los Angeles County Superior Court
Midway-Sunset Cogeneration June 7, 2001 Kern County Superior Court
Company
Plaintiffs in most of these cases have entered into settlement agreements providing for stays of litigation,
payments to the QFs upon the occurrence of specified conditions, modifications in some cases to the contract
prices going forward, releases and dismissals of the litigation upon payment by SCE. On March 1, 2002, and with
several exceptions related to unique disputes or other unique circumstances, including the status of regulatory
approval, SCE paid the amounts due under the settlement agreements with these QFs, which triggered the releases
and other provisions effectuating the settlements. As a result, the litigation with those QFs to whom payment in
full has been made under the parties' settlement agreements should be dismissed during 2002.
Power Exchange (PX) Performance Bond Litigation
On January 19, 2001, American Home Assurance Company (American Home) notified SCE that due to SCE's failure to
comply with its payment obligations to the PX, the PX issued a demand to American Home on a $20,000,000 pool
performance bond. American Home demanded payment from SCE by January 29, 2001, of $20,000,000 under an indemnity
agreement between SCE and American Home.
SCE has exercised its right under the indemnity agreement to assume the defense of American Home against claims
arising from the pool performance bond. As required by the indemnity agreement, in February 2001, SCE deposited
$20,200,000 in an account in trust to be available to satisfy any judgment, should there be one, against American
Home as a result of SCE's alleged default. SCE has further instituted the alternative dispute resolution
provisions provided for in the applicable PX tariff, which provide for negotiation followed by mediation and, if
unsuccessful, arbitration. On or about September 13, 2001,
Page 30
the PX submitted a demand for arbitration against American Home, asserting causes of action for breach of
contract and bad faith refusal to pay. On September 25, 2001, American Home demanded that SCE indemnify and
defend American Home in connection with the demand for arbitration, pursuant to the operative documents between
the parties. SCE assumed the defense of the arbitration. On March 1, 2002, SCE made payment directly to CalPX
on the full amount of its outstanding obligations. See "Business - Changing Regulatory Environment - Liquidity
Issues." CalPX was unwilling to provide American Home with an exoneration of the pool performance bond, and has
continued to pursue the arbitration, asserting, among other things, that it is entitled to the face amount of the
bond on account of PG&E's default. On March 19, 2002, American Home initiated suit against SCE, alleging that
SCE's failure to obtain an exoneration of the bond in connection with SCE's payment of its indebtedness was a
material breach of the indemnity agreement.
CPUC Litigation and Settlement
See the discussion under "Changing Regulatory Environment" for a description of SCE's lawsuit against the CPUC,
its settlement (referred to as the CPUC Settlement Agreement), and the legal proceedings associated with the CPUC
Settlement Agreement, including the appeal thereof.
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, 2001 Company Position
------------------------------ ------------------------ ------------------------------------------------------
Alan J. Fohrer 51 Chairman of the Board, Chief Executive Officer and
Director
------------------------------ ------------------------ ------------------------------------------------------
Robert G. Foster 54 President
------------------------------ ------------------------ ------------------------------------------------------
Harold B. Ray 61 Executive Vice President, Generation Business Unit
------------------------------ ------------------------ ------------------------------------------------------
Pamela A. Bass 54 Senior Vice President, Customer Service Business Unit
------------------------------ ------------------------ ------------------------------------------------------
John R. Fielder 56 Senior Vice President, Regulatory Policy and Affairs
------------------------------ ------------------------ ------------------------------------------------------
Stephen E. Pickett 51 Senior Vice President and General Counsel
------------------------------ ------------------------ ------------------------------------------------------
Richard M. Rosenblum 51 Senior Vice President, Transmission and Distribution
Business Unit
------------------------------ ------------------------ ------------------------------------------------------
Mahvash Yazdi 50 Senior Vice President and Chief Information Officer
------------------------------ ------------------------ ------------------------------------------------------
Bruce C. Foster 49 Vice President, Regulatory Operations
------------------------------ ------------------------ ------------------------------------------------------
Frederick J. Grigsby, Jr. 54 Vice President, Human Resources & Labor Relations
------------------------------ ------------------------ ------------------------------------------------------
Thomas M. Noonan 50 Vice President and Controller
------------------------------ ------------------------ ------------------------------------------------------
W. James Scilacci 46 Vice President and Chief Financial Officer
------------------------------ ------------------------ ------------------------------------------------------
------------------------
(1) Executive Officers are defined by Rule 3b-7 of the General Rules and Regulations under the Securities
Exchange Act of 1934, as amended.
Page 31
None of SCE's executive officers is 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 above officers have been actively engaged
in the business of SCE for more than five years except Mahvash Yazdi and Frederick J. Grigsby, Jr. Those
officers who have not held their present position with SCE for the past five years had the following business
experience during that period:
-------------------------------- ---------------------------------------------- ----------------------------------------
Executive Officer Company Position Effective Dates
-------------------------------- ---------------------------------------------- ----------------------------------------
Alan J. Fohrer Chairman of the Board, Chief Executive January 2002 to present
Officer and Director, SCE
---------------------------------------------- ----------------------------------------
President and Chief Executive Officer, January 2000 to December 2001
Edison Mission Energy
---------------------------------------------- ----------------------------------------
Executive Vice President and Chief Financial September 1996 to January 2000
Officer, Edison International
---------------------------------------------- ----------------------------------------
Chairman of the Board, Edison Enterprises January 1998 to September 1999
---------------------------------------------- ----------------------------------------
Executive Vice President and Chief Financial September 1996 to December 1999
Officer, SCE
---------------------------------------------- ----------------------------------------
Vice Chairman of the Board, Edison Mission May 1993 to January 1999
Energy
-------------------------------- ---------------------------------------------- ----------------------------------------
Robert G. Foster President, SCE January 2002 to present
Senior Vice President, External Affairs, SCE April 2001 to December 2001
and Edison International
Senior Vice President, Public Affairs, SCE November 1996 to April 2001
and Edison International
-------------------------------- ---------------------------------------------- ----------------------------------------
Pamela A. Bass Senior Vice President, Customer Service March 1999 to present
Business Unit, SCE
Vice President, Customer Solutions Business June 1996 to February 1999
Unit, SCE
-------------------------------- ---------------------------------------------- ----------------------------------------
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present
Affairs, SCE
Vice President, Regulatory Policy and February 1992 to February 1998
Affairs, SCE
-------------------------------- ---------------------------------------------- ----------------------------------------
Stephen E. Pickett Senior Vice President and General Counsel, January 2002 to present
SCE
Vice President and General Counsel, SCE January 2000 to December 2001
Associate General Counsel, SCE November 1993 to December 1999
-------------------------------- ---------------------------------------------- ----------------------------------------
Richard M. Rosenblum Senior Vice President, Transmission and February 1998 to present
Distribution Business Unit, SCE
Vice President, Distribution Business Unit, January 1996 to February 1998
SCE
-------------------------------- ---------------------------------------------- ----------------------------------------
Mahvash Yazdi Senior Vice President and Chief Information January 2000 to present
Officer, SCE and Edison International
Vice President and Chief Information May 1997 to December 1999
Officer, SCE and Edison International
Vice President of Information Technology and September 1995 to May 1997
Chief Information Officer, Hughes Aircraft
Company(1)
-------------------------------- ---------------------------------------------- ----------------------------------------
Frederick J. Grigsby, Jr. Vice President, Human Resources & Labor July 2001 to present
Relations
Senior Vice President, Human Resources, December 1998 to October 2000
Fluor Corporation(1) (2)
Vice President, Human Resources, Thermo King December 1995 to November 1998
Corporation(1) (3)
-------------------------------- ---------------------------------------------- ----------------------------------------
Page 32
-------------------------------- ---------------------------------------------- ----------------------------------------
Thomas M. Noonan Vice President and Controller, SCE and March 1999 to present
Edison International
Assistant Controller, SCE and Edison September 1993 to February 1999
International
-------------------------------- ---------------------------------------------- ----------------------------------------
W. James Scilacci Vice President and Chief Financial Officer, January 2000 to present
SCE
Director, 2002 General Rate Case, SCE August 1999 to December 1999
Director, Qualifying Facility Resources, SCE January 1995 to August 1999
-------------------------------- ---------------------------------------------- ----------------------------------------
---------------------------
(1) This entity is not a parent, subsidiary or other affiliate of SCE.
(2) The Fluor Corporation is one of the world's largest, publicly owned engineering, procurement, construction,
and maintenance services organizations.
(3) Thermo King Corporation provides climate control solutions for global transportation industries.
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, 2001 (Annual Report), under Quarterly
Financial Data on page 49 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:
1996 - 2001 on page 1 and is incorporated herein by reference pursuant to General Instruction G(2).
Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition
Information responding to Item 7 is included in the Annual Report under Management's Discussion and Analysis of
Results of Operations and Financial Condition on pages 2 through 20 and is incorporated herein by reference
pursuant to General Instruction G(2).
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 7A is included in the Annual Report under Management's Discussion and Analysis of
Results of Operations and Financial Condition on pages 8 through 9 incorporated herein by reference pursuant to
General Instruction G(2).
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in Part IV. Other information responding to
Item 8 is included in the Annual Report on pages 21 through 49, 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.
Page 33
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 will
be incorporated by reference from SCE's definitive Joint Proxy Statement (Proxy Statement) filed with the SEC in
connection with SCE's Annual Shareholders' Meeting to be held on May 14, 2002, under the headings, "Election of
Directors" and is incorporated herein by reference pursuant to General Instruction G(3).
In addition, the following information is furnished with respect to certain Directors of SCE, who are expected to
retire from the Board on May 14, 2002:
Warren Christopher, age 76, has been a Director of SCE from August 1971 through January 1977, from June 1981
through January 1993, and from May 1997 to date. He is also a Director of Edison International. He is a Senior
Partner of the law firm of O'Melveny & Myers (1958-1967, 1969-1977, 1981-1993, and since 1997) and is the former
United States Secretary of State (1993-1997).
Carl F. Huntsinger, age 72, has been a Director of SCE since 1983 and is also a Director of Edison
International. He has been a General Partner of DAE Limited Partnership, Ltd. (agricultural management) since
1986.
Charles D. Miller, age 73, has been a Director of SCE since 1987 and is also a Director of Edison International.
He is a Director of Avery Dennison Corporation, Nationwide Health Properties (Chairman), The Air Group, Mellon
Financial Group-West Coast, and Korn/Ferry International. He is also the Retired Chairman of the Board of Avery
Dennison Corporation (manufacturer of self-adhesive products) (1998-2000); and the prior Chairman of the Board
and Chief Executive Officer of Avery Dennison Corporation (1983-1998).
Item 11. Executive Compensation
Information responding to Item 11 will be incorporated by reference from SCE's definitive Proxy Statement under
the headings "Board Compensation," "Executive Compensation - Summary Compensation Table," "Aggregated Option/SAR
Exercises in 2001 and FY-End Option/SAR Values," "Long-Term Incentive Plan Awards in Last Fiscal Year," "Pension
Plan Table," "Other Retirement Benefits," "Employment Contracts and Termination of Employment Arrangements,"
"Compensation and Executive Personnel Committees' Report on Executive Compensation," and "Compensation and
Executive Personnel Committees' Interlocks and Insider Participation," 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 will be incorporated by reference from SCE's definitive Proxy Statement under
the headings "Stock Ownership of Directors and Executive Officers" and "Stock Ownership of Certain Shareholders,"
and is incorporated herein by reference pursuant to General Instruction G(3).
Item 13. Certain Relationships and Related Transactions
Information responding to Item 13 will be incorporated by reference from SCE's definitive Proxy Statement under
the heading "Certain Relationships and Transactions of Nominees and Executive Officers" and "Other Management
Transactions," and is incorporated herein by reference pursuant to General Instruction G(3).
Page 34
In addition, Mr. Christopher is a Senior Partner of the law firm of O'Melveny and Myers. The firm provided legal
services to SCE and/or its subsidiaries in 2001, and such services are expected to continue to be provided in the
future. The amount paid to O'Melveny and Myers for legal services was below the threshold requiring disclosure
by the SEC. SCE believes that these transactions are comparable to those which would have been undertaken under
similar circumstances with nonaffiliated entities or persons.
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 2 through 51, 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, 2001, 2000, and 1999
Consolidated Balance Sheets - December 31, 2001, and 2000
Consolidated Statements of Cash Flows - Years Ended December 31, 2001, 2000, and 1999
Consolidated Statements of Changes in Common Shareholder's Equity - Years Ended
December 31, 2001, 2000, 1999 and 1998
Notes to Consolidated Financial Statements
Responsibility for Financial Reporting
Report of Independent Public Accountants
(a)(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 36
Schedule II - Valuation and Qualifying Accounts for the Years
Ended December 31, 2001, 2000, and 1999 37
Schedules I through V, inclusive, except those referred to above, are omitted as not required or not applicable.
(a)(3) Exhibits
See Exhibit Index beginning on page 41 of this report.
The Company will furnish a copy of any exhibit listed in the accompanying Exhibit Index upon written
request and upon payment to the Company of its reasonable expenses of furnishing such exhibit, which shall be
limited to photocopying charges and, if mailed to the requesting party, the cost of first-class postage.
(b) Reports on Form 8-K
October 2, 2001
Item 5: Other Events Settlement Agreement
October 30, 2001
Item 5: Other Events Settlement Agreement
Page 35
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 2001 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 March 25, 2002. Our
audits were made for the purpose of forming an opinion on those consolidated financial statements taken as a
whole. The supplemental schedules listed in Part IV of this Form 10-K are the responsibility of SCE's management
and are presented for purposes of complying with the Securities and Exchange Commission's rules and regulations,
and are not part of the consolidated financial statements. These supplemental schedules have been subjected to
the auditing procedures applied in the audits of the 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
consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Los Angeles, California
March 25, 2002
Page 36
Southern California Edison Company
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 2001
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:
Geothermal projects reserves
Projects in development stage
Uncollectible Accounts:
Customers $ 19,793 $ 28,926 $ -- $ 20,419 $ 28,300
All other 3,427 1,836 -- 1,607 3,656
-------------------------------------------------------------------------------------------------------------------
Total $ 23,220 $ 30,762 $ -- $ 22,026(a) $ 31,956
-------------------------------------------------------------------------------------------------------------------
Group B:
DOE Decontamination
and Decommissioning $ 29,920 $ -- $ $ 5,520(b) $ 24,400
Purchased-power settlements 466,232 -- 110,353(c) 355,879
Pension and benefits 296,278 195,558 72,037(d) 419,799
Maintenance Accrual
Insurance, casualty and other 64,058 54,827 -- 43,815(e) 75,070
-------------------------------------------------------------------------------------------------------------------
Total $ 856,488 $ 250,385 $ -- $ 231,725 $ 875,148
-------------------------------------------------------------------------------------------------------------------
-------------------------
(a) Accounts written off, net.
(b) Represents amounts paid.
(c) Represents the amortization of the liability established for purchased-power contract settlement agreements.
(d) Includes pension payments to retired employees, amounts paid to active employees during periods of illness
and the funding of certain pension benefits.
(e) Amounts charged to operations that were not covered by insurance.
Page 37
Southern California Edison Company
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Year Ended December 31, 2000
Additions
-----------------------------
Balance at Charged to Charged to Balance
Beginning of Costs and Other at End
Description Period Expenses Accounts Deductions of Period
-------------------------------------------------------------------------------------------------------------------
(In thousands)
Group A:
Uncollectible accounts
Customers $ 21,656 $ 24,017 $ -- $ 25,880 $ 19,793
All other 3,009 1,201 -- 783 3,427
-------------------------------------------------------------------------------------------------------------------
Total $ 24,665 $ 25,218 $ -- $ 26,663(a) $ 23,220
-------------------------------------------------------------------------------------------------------------------
Group B:
DOE Decontamination
and Decommissioning $ 34,590 $ -- $ (219)(b) $ 4,451(c) $ 29,920
Purchased-power settlements 563,459 17,188 -- 114,415(d) 466,232
Pension and benefits 232,901 44,244 24,101(e) 4,968(f) 296,278
Insurance, casualty and other 68,880 42,749 -- 47,571(g) 64,058
-------------------------------------------------------------------------------------------------------------------
Total $ 899,830 $ 104,181 $ 23,882 $ 171,405 $ 856,488
-------------------------------------------------------------------------------------------------------------------
-------------------------
(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.
Page 38
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.
Page 39
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 29, 2002
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:
Alan J. Fohrer* Chairman of the Board, Chief March 29, 2002
Executive Officer and Director
Principal Financial Officer:
W. James Scilacci* Vice President and
Chief Financial Officer March 29, 2002
Controller or Principal Accounting Officer:
Thomas M. Noonan* Vice President and Controller March 29, 2002
Board of Directors:
Warren Christopher* Director March 29, 2002
Joan C. Hanley* Director March 29, 2002
Carl F. Huntsinger* Director March 29, 2002
Charles D. Miller* Director March 29, 2002
Luis G. Nogales* Director March 29, 2002
Ronald L. Olson* Director March 29, 2002
James M. Rosser* Director March 29, 2002
Robert H. Smith* Director March 29, 2002
Thomas C. Sutton* Director March 29, 2002
Daniel M. Tellep* Director March 29, 2002
*By:
Kenneth S. Stewart
-----------------------------
Kenneth S. Stewart
Assistant General Counsel
Page 40
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 effective August 21,
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
January 1, 2002
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)*
4.11 Indenture dated as of May 1, 1995 (File No. 1-2313, Form 8-K dated May 24, 1995)*
4.12 Ninety-Seventh Supplemental Indenture, dated as of February 21, 2002
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. 1-9936, filed as Exhibit 10.3 to the Edison
International Form 10-Q for the quarter ended June 30, 1998)*
10.5 Director Grantor Trust Agreement (File No. 1-9936, filed as Exhibit 10.10 to the Edison
International Form 10-K for the year ended December 31, 1995)*
10.6 Executive Deferred Compensation Plan (File No. 1-9936, filed as Exhibit 10.2 to the Edison
International Form 10-Q for the quarter ended March 31, 1998)*
10.7 Executive Grantor Trust Agreement (File No. 1-9936, filed as Exhibit 10.12 to the Edison
International Form 10-K for the year ended December 31, 1995)*
10.8 Executive Supplemental Benefit Program (File No. 1-9936, filed as Exhibit 10.2 to the Edison
International Form 10-Q for the quarter ended September 20, 1999)*
10.9 Dispute resolution amendment of 1981 Executive Deferred Compensation Plan, 1985 Executive and
Director Deferred Compensation Plans and Executive Supplemental Benefit Program (File No. 1-9936,
filed as Exhibit 10.21 to the Edison International Form 10-K for the year ended December 31, 1998)*
10.10 Executive Retirement Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form
10-Q for the quarter ended September 30, 1999)*
10.10.1 Executive Retirement Plan Amendment 2001-1 (File No. 1-9936, filed as Exhibit 10.1 to the Edison
International Form 10-Q for the quarter ended March 31, 2001)*
10.11 Executive Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.12 to the Edison
International Form 10-K for the year ended December 31, 1997)*
10.12 Executive Disability and Survivor Benefit Program (File No. 1-9936, filed as Exhibit 10.22 to the
Edison International Form 10-K for the year ended December 31, 1994)*
Page 41
10.13 Retirement Plan for Directors (File No. 1-9936, filed as Exhibit 10.2 to the Edison International
Form 10-Q for the quarter ended June 30, 1998)*
10.14 Officer Long-Term Incentive Compensation Plan (File No. 1-9936, filed as Exhibit 10.3 to the Edison
International Form 10-Q for the quarter ended March 31, 1998)*
10.15 Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form
10-Q for the quarter ended June 30, 1998)*
10.15.1 Amendment No. 1 to the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.3 to the
Edison International Form 10-Q for the quarter ended June 30, 2000)*
10.16 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for
the quarter ended June 30, 2000)*
10.17 Forms of Agreement for long-term compensation awards under the Officer Long-Term Incentive
Compensation Plan, the Equity Compensation Plan or the 2000 Equity Plan (File No. 1-9936, for
1991-1995 stock option awards filed as Exhibit 10.21.1 to the Edison International Form 10-K for
the year ended December 31, 1995, for 1996 stock option awards filed as Exhibit 10.16.2 to the
Edison International Form 10-K for the year ended December 31, 1996, for 1997 stock option awards
filed as Exhibit 10.16.3 to the Edison International Form 10-K for the year ended December 31,
1997, for 1998 stock option awards filed as Exhibit 10.4 to the Edison International Form 10-Q for
the quarter ended June 30, 1998, for 1999 stock option awards filed as Exhibit 10.1 to the Edison
International Form 10-Q for the quarter ended March 31, 1999, for January 2000 stock option and
performance share awards as restated filed as Exhibit 10.2 to the Edison International Form 10-Q
for the quarter ended March 31, 2001, for May 2000 special stock option awards filed as Exhibit
10.2 to the Edison International Form 10-Q for the quarter ended June 30, 2000, for 2001 basic
stock option and performance share awards filed as Exhibit 10.3 to the Edison International Form
10-Q for the quarter ended March 31, 2001, for 2001 special stock option awards filed as Exhibit
10.4 to the Edison International Form 10-Q for the quarter ended March 31, 2001, for 2001 retention
incentives filed as Exhibit 10.5 to the Edison International Form 10-Q for the quarter ended
March 31, 2001, and for 2001 exchange offer deferred stock units filed as Attachment C of Exhibit
(a)(1) to Schedule TO-I dated October 26, 2001)*
10.18 Form of Agreement for 2001 Director Awards under the Equity Compensation Plan (File No. 1-9936,
filed as Exhibit 10.21 to the Edison International Form 10-K for the year ended December 31, 2001)*
10.19 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)*
10.20 Option Gain Deferral Plan as restated September 15, 2000 (File No. 1-9936, filed as Exhibit 10.25
to the Edison International Form 10-K for the year ended December 31, 2000)*
10.21 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)*
10.22 Retirement Agreement with Stephen E. Frank
10.23 Consulting Agreement with Stephen E. Frank
10.24 Election Terms for Warren Christopher (File No. 1-9936, filed as Exhibit 10.22 to the Edison
International Form 10-K for the year ended December 31, 1997)*
10.25 Executive Severance Plan as adopted effective January 1, 2001 (File No. 1-9936, filed as Exhibit
10.34 to the Edison International Form 10-K for the year ended December 31, 2001)*
12. Computation of Ratios of Earnings to Fixed Charges
13. Annual Report to Shareholders for year ended December 31, 2001
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
99 Letter to United States Securities and Exchange Commission Regarding the Issuer's Independent
Public Accountants, Arthur Andersen LLP
-------------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 42
