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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 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue (626) 302-2222
Rosemead, California 91770 (Registrant's telephone
(Address of principal (Zip Code) number, including area code)
executive offices)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock, no par value New York and Pacific
Rights to Purchase Series A Junior Participating New York and Pacific
Cumulative Preferred Stock, no par value
Guarantee of 7.875% Cumulative Quarterly New York
Income Preferred Securities, Series A
Guarantee of 8.60% Cumulative Quarterly New York
Income Preferred Securities, Series B
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]
The aggregate market value of registrant's voting stock held by non-affiliates was approximately
$5,408,466,019.60 on or about March 25, 2002, based upon prices reported on the New York Stock Exchange. As of
March 25, 2002, there were 325,811,206 shares of Common Stock outstanding.
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
Business of Edison International.................................................................... 1
Forward-Looking Statements, Risk Factors, and Investment Considerations........................ 1
Competitive Environment of Edison International................................................ 3
Regulation of Edison International............................................................. 4
Environmental Matters Affecting Edison International........................................... 5
Business of SCE..................................................................................... 7
Competitive Environment of SCE................................................................. 8
Regulation of SCE.............................................................................. 8
Changing Regulatory Environment of SCE......................................................... 9
Other Rate Matters of SCE...................................................................... 18
Fuel Supply and Purchased Power Costs of SCE................................................... 21
Environmental Matters Affecting SCE............................................................ 23
Business of the Nonutility Companies................................................................ 26
Business of Edison Mission Energy.............................................................. 26
Amercias Region............................................................................ 27
Asia-Pacific Region........................................................................ 30
Europe and Middle East Region.............................................................. 31
Discontinued Operations.................................................................... 32
Financial Ratings.......................................................................... 32
Credit Ratings............................................................................. 35
Trading and Risk Management Activities..................................................... 36
Seasonality................................................................................ 37
Competitive Environment of EME............................................................. 37
Regulation of EME.......................................................................... 38
Environmental Matters Affecting EME........................................................ 41
Properties of EME.......................................................................... 46
Business of Edison Capital..................................................................... 46
Other Nonutility Companies..................................................................... 48
2. Properties.............................................................................................. 48
Generating Facilities of SCE........................................................................ 48
SCE Construction Program and Capital Expenditures................................................... 50
Nuclear Power Matters of SCE........................................................................ 51
3. Legal Proceedings....................................................................................... 53
Litigation Involving Edison International........................................................... 53
Shareholder Litigation......................................................................... 53
Qualifying Facilities Litigation............................................................... 53
Litigation Involving Edison Mission Energy.......................................................... 53
PMNC Litigation................................................................................ 53
Litigation Involving SCE............................................................................ 53
San Onofre Personal Injury Litigation.......................................................... 53
Navajo Nation Litigation....................................................................... 54
Shareholder Litigation......................................................................... 55
Qualifying Facilities Litigation............................................................... 56
Power Exchange (PX) Performance Bond Litigation................................................ 57
CPUC Litigation and Settlement................................................................. 58
4. Submission of Matters to a Vote of Security Holders..................................................... 58
Executive Officers of the Registrant................................................................ 58
TABLE OF CONTENTS
Item Page
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Part II
5. Market for Registrant's Common Equity and Related Stockholder Matters................................... 61
6. Selected Financial Data................................................................................. 61
7. Management's Discussion and Analysis of Results of Operations and Financial Condition................... 61
7A. Quantitative and Qualitative Disclosures About Market Risk.............................................. 61
8. Financial Statements and Supplementary Data............................................................. 61
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 62
Part III
10. Directors and Executive Officers of the Registrant...................................................... 62
11. Executive Compensation.................................................................................. 62
12. Security Ownership of Certain Beneficial Owners and Management.......................................... 62
13. Certain Relationships and Related Transactions.......................................................... 62
Part IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................ 63
Financial Statements................................................................................ 63
Report of Independent Public Accountants and Schedules Supplementing
Financial Statements........................................................................... 63
Exhibits............................................................................................ 63
Reports on Form 8-K................................................................................. 64
Signatures.......................................................................................... 72
PART I
Item 1. Business
Business of Edison International
Edison International was incorporated on April 20, 1987, under the laws of the State of California for the
purpose of becoming the parent holding company of Southern California Edison Company (SCE), a California public
utility corporation. As of December 31, 2001, Edison International owned, directly or indirectly, all of the
issued and outstanding common stock of SCE and of other subsidiaries engaged in nonutility businesses (Nonutility
Companies). The principal Nonutility Companies are: Edison Mission Energy (EME), which is engaged in
developing, acquiring, owning or leasing, and operating electric power generation facilities worldwide and energy
trading and price risk management activities; Edison Capital, a provider of capital and financial services for
energy and infrastructure projects; and Edison Operations & Maintenance Services, which began operations on
January 1, 2001, and provides operations and maintenance services for the power production industry.
Edison International is engaged in the business of holding, for investment, the stock of its subsidiaries.
At year-end 2001, Edison International had 36 full-time employees, SCE had 11,663 full-time employees, Edison
Mission Energy had 3,021 full-time employees, Edison Capital had 66 full-time employees, Edison O&M Services had
147 full-time employees, and other nonutility subsidiaries had 31 full-time employees.
The principal executive offices of Edison International are located at 2244 Walnut Grove Avenue, Rosemead,
California 91770, and its telephone number is (626) 302-2222.
Forward-Looking Statements, Risk Factors, and Investment Considerations
This Annual Report on Form 10-K contains forward-looking statements that reflect Edison International's current
expectations and projections about future events based on Edison International's knowledge of present facts and
circumstances and assumptions about future events. Other information distributed by Edison International that is
incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking
statements. In this 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 Edison International or its
subsidiaries, are:
o Effects of the California Energy Crisis. The energy crisis that occurred in California during 2000 and 2001
adversely affected the financial condition, liquidity, and credit ratings of Edison International and SCE.
In October 2001, SCE entered into an agreement with the California Public Utilities Commission (CPUC) to
settle litigation over SCE's right to recover its costs of procuring power during the crisis. Based on the
rights to cost recovery agreed to in the settlement agreement, SCE was able to obtain financing and repay
past-due obligations in March 2002, using financing proceeds and cash on hand. The court order approving
SCE's settlement agreement is being appealed by a consumer advocacy group and other intervening parties. If
the order is successfully challenged on appeal, implementation of the settlement agreement could be affected
adversely, which in turn may have an adverse effect on Edison International's and SCE's ability to restore
their financial condition. These matters are discussed in Part I, Item 1 of this report under the heading
"Business of SCE - Changing Regulatory Environment of SCE."
EME and Edison Capital also were adversely affected by the California energy crisis and the liquidity
problems of Edison International because in the past they have received financial support from Edison
International in the form of equity investments, intercompany loans, and tax sharing arrangements. Current
constraints on such support may limit their ability to make new investments. In addition, EME has a
substantial amount of indebtedness, including short-term indebtedness and long-term lease
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obligations. There is a risk that EME might not have sufficient cash to service its indebtedness and that
EME's obligations could limit its ability to grow, to compete effectively, or to operate successfully under
adverse economic conditions. These matters are discussed in Part I, Item 1 of this report under the
headings, "Business of EME - Credit Ratings" and "Business of Edison Capital." See also the discussion of
liquidity issues under the heading "Financial Condition" in the Management's Discussion and Analysis of
Results of Operations and Financial Condition (MD&A) that is incorporated by reference into Part II, Item 7
of this report.
o Credit Ratings. During 2001, the credit ratings of Edison International and SCE were downgraded to
below investment grade levels. Due to the recent financing and payment of past-due obligations by SCE, the
credit ratings were raised but remain below investment grade. Edison International and SCE are seeking to
regain investment grade ratings so they can enter the capital markets and obtain financing on more efficient
and reasonable terms. Whether and when they can do this will have a significant impact on their financial
condition.
EME retains investment grade credit ratings, but the ratings are subject to change and a downgrade below
investment grade could have an adverse impact on EME. If downgraded, EME could be required to provide
additional guarantees, letters of credit, and collateral in connection with its business activities. A
downgrade could also increase EME's cost of capital, make efforts to raise capital more difficult, adversely
affect EME's trading operations, and have other adverse impacts on EME and its subsidiaries. This matter is
discussed in Part I, Item 1 of this report under the heading, "Business of EME - Credit Ratings."
o Commodity Price Risk. A substantial amount of EME's revenues are derived under power purchase
agreements with Exelon Generation Company (Exelon) relating to EME's generating plants in Illinois. Exelon
has the option to terminate certain of those agreements for 2003 and 2004. If Exelon terminates or elects
not to exercise options under the agreements or fails to fulfill its obligations under the agreements, EME
would be adversely affected if it were unable to obtain replacement power sales arrangements for the output
of the affected plants. EME also owns, operates or may acquire projects that operate without long-term
power purchase agreements and are or will be subject to market forces that affect the price of power. If
these plants are unsuccessful in selling power into their markets, they may not be able to generate enough
cash to service their own debt or make distributions to EME. For further discussion of the risks related to
the sale of electricity from the First Hydro project, see "Market Risk Exposures" in the MD&A that is
incorporated by reference into Part II, Item 7 of this report.
On March 27, 2001, the United Kingdom replaced its centralized electricity pool with a bilateral trading
system. During 2001, EME's operating income from a hydroelectric plant located in the United Kingdom
decreased $106 million from the prior year, primarily due to lower energy and capacity prices resulting from
the new electricity trading system. EME is monitoring the operation of the new system but can give no
assurance as to its future impact. See the discussion of market risk issues under the heading "Market Risk
Exposures" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.
o Regulatory Actions. Edison International and its subsidiaries are 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 Legislative Actions. Edison International and its subsidiaries 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 United States
statutes governing the electric industry, and new laws and rules governing electricity trading in the United
Kingdom.
o Competition. 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. EME may be affected by
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competition from other project developers and energy providers seeking to do business in the same markets as EME,
which could reduce EME's opportunities and returns.
o Plant Operation Risks. SCE and EME own and operate power generation facilities and, therefore, may be
affected by changes in the cost and availability of fuel and fuel transportation, labor problems,
catastrophic events, mechanical breakdowns, and unpredictable weather conditions that may affect seasonal
patterns of revenue collection, cause changes in demand (and prices) for electricity and result in higher
costs for repair or maintenance of assets.
o Environmental Risks. The operation of power generation, transmission or distribution facilities by SCE and
EME 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 the
EME coal plants. For further discussion, see "Business of Edison International - Environmental Matters
Affecting Edison International," and "Business of EME - Environmental Matters Affecting EME - International."
o Effects of Enron Bankruptcy. The bankruptcy of Enron Corporation (Enron) and related developments have
had limited direct effects on Edison International and its subsidiaries. Edison Capital has an investment
of approximately $85 million in a wind partnership operated by a subsidiary of Enron. Some or all of that
investment could be lost if Enron's bankruptcy is determined to be an event of default under an existing
loan agreement. As a result of Enron's bankruptcy, EME recorded an $8.5 million provision in 2001 for bad
debts in respect of outstanding receivables from electricity and fuel agreements between EME and Enron or
its affiliates. Edison International and its subsidiaries do not have any other material exposures to Enron
that might be affected by Enron's bankruptcy. The Enron bankruptcy and related developments have had and
may continue to have indirect effects on Edison International and its subsidiaries, such as: financial
difficulties of other companies in energy-related businesses, which may limit their ability to enter into or
complete transactions with Edison International's subsidiaries; heightened investor concerns about
energy-related market sectors, which may result in decreased availability or increased cost of financing for
Edison International and its subsidiaries; and reviews by credit rating agencies of the criteria for
assessing the credit risk of merchant energy companies, which could result in negative rating action for
Edison International or EME.
o Off-Balance Sheet Transactions. EME has off-balance sheet transactions in two principal areas:
investments in projects accounted for under the equity method, and operating leases resulting from
sale-leaseback transactions. Edison Capital has entered into off-balance sheet transactions for investments
in certain projects. These transactions are discussed in the section entitled "Off-Balance Sheet
Transactions" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.
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 MD&A that are incorporated by
reference into Part II of this 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 Edison
International's business. The information contained in this report is subject to change without notice, and
Edison International is not obligated to publicly update or revise forward-looking statements. Readers should
review future reports filed by Edison International with the Securities and Exchange Commission (SEC). For
further details, readers should also review the Annual Reports on Form 10-K filed by SCE and EME with the SEC.
Competitive Environment of Edison International
Because Edison International is a holding company, it does not face direct competition itself. However, its
subsidiaries operate in competitive environments. As a regulated public utility, SCE has historically faced
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only limited competition because of its exclusive franchise to serve customers within its service territory.
However, the implementation of electric industry restructuring in California has resulted in increased
competition, particularly in the generation portion of SCE's business. This changing competitive environment and
its effects on SCE are discussed below under "Business of SCE - Changing Regulatory Environment."
Edison International's Nonutility Companies face competitive conditions as well. EME competes with many other
companies (including independent power producers that are affiliates of utilities) in selling electric power and
steam as well as with electric utilities and others in installing new generating capacity. The global
independent power industry is characterized by numerous strong and capable competitors. In recent years, some
markets have been characterized by strong and increasing competition as a result of regulatory changes and other
factors which have contributed to a reduction in market prices for power. These regulatory and other changes may
continue to increase competitive pressures in the markets where EME operates. Edison Capital competes with other
investors, including money center banks, major finance and lease companies, and affiliates of public utilities
and other Fortune 500 companies, in the market for highly structured transactions. (See "Business of EME" and
"Business of Edison Capital" below for more information about the competitive environments faced by EME and Edison
Capital.). The competitive positions of the Nonutility Companies have been adversely affected by the financial
constraints placed upon Edison International by the financial difficulties at SCE during 2001.
Regulation of Edison International
Edison International and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public
Utility Holding Company Act of 1935 on the basis that Edison International and SCE are incorporated in the same
state and their business is predominately intrastate in character and carried on substantially in the state of
incorporation. Section 9(a)(2) provides, in substance, that Edison International may not directly or indirectly
acquire five percent or more of the voting securities of a public utility company other than SCE, unless the
acquisition has been approved by the SEC. The subsidiaries of Edison International, other than SCE, conduct
their businesses so as to avoid becoming public utility companies as defined in the Public Utility Holding
Company Act. (See "Business of EME - Regulation of EME" below for more information on the regulation of EME,
including the effects on EME of the Public Utility Holding Company Act.) It is necessary for Edison
International to file an annual exemption statement with the SEC, and the exemption may be revoked by the SEC
upon a finding that the exemption may be detrimental to the public interest or the interest of investors or
consumers. Edison International has no present intention of becoming a registered holding company under the
Public Utility Holding Company Act.
Edison International is not a public utility under the laws of the State of California and is not subject to
regulation as such by the CPUC. (See "Business of SCE - Regulation of SCE" below for a description of the
regulation of SCE by the CPUC.) The CPUC decision authorizing SCE to reorganize into a holding company
structure, however, contains certain conditions, which, among other things: (1) ensure the CPUC access to books
and records of Edison International and its affiliates which relate to transactions with SCE; (2) require Edison
International and its subsidiaries to employ accounting and other procedures and controls to ensure full review
by the CPUC and to protect against subsidization of nonutility activities by SCE's customers; (3) require that
all transfers of market, technological, or similar data from SCE to Edison International or its affiliates, be
made at market value; (4) preclude SCE from guaranteeing any obligations of Edison International without prior
written consent from the CPUC; (5) provide for royalty payments to be paid by Edison International or its
subsidiaries in connection with the transfer of product rights, patents, copyrights, or similar legal rights from
SCE; and (6) prevent Edison International and its subsidiaries from providing certain facilities and equipment to
SCE except through competitive bidding. In addition, the decision provides that SCE shall maintain a balanced
capital structure in accordance with prior CPUC decisions, that SCE's dividend policy shall continue to be
established by SCE's board of directors as though SCE were a stand-alone utility company, and that the capital
requirements of SCE, as determined to be necessary to meet SCE's service obligations, shall be given first
priority by the boards of directors of Edison International and SCE.
Page 4
In 1997, the CPUC issued 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 Pacific Gas and Electric Company (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 & 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.
Neither Edison International nor SCE can predict what effects the CPUC's investigation or any other actions by
the CPUC or the Attorney General may have on either of them.
Environmental Matters Affecting Edison International
Because Edison International does not own or operate any assets, except the stock of its subsidiaries, it does
not have any direct environmental obligations or liabilities. However, legislative and regulatory activities by
federal, state, and local authorities in the United States and regulatory authorities with jurisdiction over
projects located outside the United States continue to result in the imposition of numerous restrictions on the
operation of existing facilities by Edison International's subsidiaries, on the timing, cost, location, design,
construction, and operation by Edison International's subsidiaries of new facilities, and on
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the cost of mitigating the effect of past operations on the environment. These laws and regulations, relating to
air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics, and
nuclear control, substantially affect future planning and will continue to require modifications of existing
facilities and operating procedures by Edison International's subsidiaries. Edison International is unable to
predict the extent to which additional regulations may affect its operations and capital expenditure requirements.
Edison International records environmental liabilities, on a consolidated basis, when site assessments and/or
remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison
International 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, Edison International records the lower end of this reasonably likely range of costs (classified as other
long-term liabilities at undiscounted amounts). Edison International's consolidated environmental liabilities
include expenses to remediate sites currently owned by Edison International's subsidiaries or by third parties,
and for which one of Edison International subsidiaries has been named as one of the potential responsible
parties. They also include mitigation expenses associated with the construction of SCE's San Onofre nuclear
power plant.
As of December 31, 2001, all of Edison International's consolidated environmental liabilities were associated
with its fully-owned subsidiary SCE. Edison International's recorded estimated minimum liability to remediate
its 42 identified sites is $111 million. The ultimate costs to clean up these identified sites may vary from the
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. Edison International 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 Edison International among a range of reasonably possible outcomes.
Edison International's subsidiaries' 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 Edison International's subsidiaries 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, Edison International (on a
consolidated basis) 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.
Edison International expects its subsidiaries to clean up their 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 $18 million.
Based on currently available information, Edison International 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, Edison International believes that costs ultimately recorded will
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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 and other countries are
focusing considerable attention on carbon dioxide emissions from coal-fired power plants and their potential role
in the "global-warming" issue. Edison International 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 supply. Nevertheless, the fact that EME owns or operates a significant number of 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 the EME 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
United States Environmental Protection Agency are now considering various proposals that would impose, or modify,
controls on these power plant emissions. For additional discussion, see "Business of EME - Edison Mission Energy
- - Environmental Matters Affecting EME - International."
Because SCE is a co-owner of two coal-fired power plants, it also is exposed to the uncertainties and risks
described above; but, 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 of SCE - Environmental Matters Affecting SCE."
Edison International's projected environmental capital expenditures on a consolidated basis are $1.7 billion for
the 2002 - 2006 period, mainly for undergrounding certain transmission and distribution lines at SCE and
upgrading environmental controls at EME.
Additional information about Edison International's environmental liabilities on a consolidated basis is
contained in the MD&A under "Environmental Protection" and in Note 12 of the Notes to Consolidated Financial
Statements, which are incorporated by reference into Part II of this report. For details about the environmental
liabilities, and other business risks from environmental regulation, of SCE and EME, see "Business of SCE -
Environmental Matters Affecting SCE" and "Business of EME - Environmental Matters Affecting EME" below.
BUSINESS OF SCE
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. This 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. SCE comprises the largest portion of the assets and revenue
of Edison International.
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 transition 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 of SCE," in January 2001 SCE ceased buying
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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.
Competitive Environment of SCE
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 "Changing Regulatory Environment of SCE."
Regulation of SCE
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 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.
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. See "Regulation
of Edison International" above for further discussion of these rules and the CPUC order regarding compliance with
past CPUC decisions authorizing utility holding company formation and initiating an investigation into various
affiliate and holding company related issues.
Changing Regulatory Environment of SCE
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 of SCE." 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
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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.
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 in installments 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
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
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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 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 the 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
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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.
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 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.
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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 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
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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.
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 "SCE's 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.
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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%.
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 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
Page 15
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 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
Page 16
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.
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 "SCE's Regulatory Environment - Generation and Power Procurement" and "SCE's 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
Page 17
its investment in its nuclear facilities, and on accounting for generation-related assets and power procurement
costs.
Other Rate Matters of SCE
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 of SCE," the way in which the CPUC regulates SCE 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 non-generation 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, 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.
Page 18
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%.
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 of SCE - 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
Page 19
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.
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 of SCE" 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 of SCE" 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.
Page 20
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.
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 of
SCE," 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 of SCE
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 of SCE - 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
Page 21
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.
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 1, Item 3 of this
report. SCE does not have reasonable assurance of an adequate coal supply for operating
Page 22
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 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 Affecting SCE
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 of SCE - Fuel Supply and Purchased Power Costs of SCE - Coal Supply."
Page 23
The Clean Air Act also requires the EPA to carry out a three-year study of risk to public health from the
emissions of toxic air contaminants from electric utility steam generating plants, and to regulate such emissions
if the 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 control, 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.
Page 24
The Toxic Substances Control Act and accompanying regulations govern the manufacturing, processing, distribution
in commerce, use, and disposal of listed compounds, such as polychlorinated biphenyls, a toxic substance used in
certain electrical equipment. Current costs for disposal of this substance are immaterial.
SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range
of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly,
by assessing a range of reasonably likely costs for each identified site using currently available information,
including existing technology, presently enacted laws and regulations, experience gained at similar sites, and
the probable level of involvement and financial condition of other potentially responsible parties. These
estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site
closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs
(classified as other long-term liabilities at 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 nuclear power plant in San Onofre.
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.
SCE's projected environmental capital expenditures are $1.3 billion for the 2002 - 2006 period, mainly for
undergrounding certain transmission and distribution lines.
Page 25
BUSINESS OF THE NONUTILITY COMPANIES
The businesses of the Nonutility Companies are described below. For Edison International's business segment
information for each of the years ended December 31, 2001, 2000, and 1999, see Note 14 of Notes to Consolidated
Financial Statements that are incorporated by reference into Part II, Item 8 of this report.
Mission Energy Holding Company: On June 8, 2001, Edison International created Mission Energy Holding Company
(MEHC) as a wholly-owned indirect subsidiary. MEHC's principal asset is EME's outstanding common stock. In July
2001, MEHC issued $800 million of 13.50% senior secured notes due in 2008. Concurrently with the consummation of
the offering of its senior secured notes, MEHC borrowed $385 million under a term loan. The senior secured notes
and the term loan are secured by a first priority security interest in EME's common stock and in interest reserve
accounts covering the interest payable on those obligations for the first two years. A change in control of EME
could require EME to prepay indebtedness in EME's debt agreements or debt agreements of EME's subsidiaries. The
respective rights, remedies and priorities of the holders of the senior secured notes and the lenders with
respect to EME's stock are governed by intercreditor arrangements. Neither Edison International nor EME has
guaranteed either the senior secured notes or the term loan, both of which are non-recourse to Edison
International and EME. The net proceeds of the offering and the term loan not deposited into the respective
interest reserve accounts were used to pay a dividend to MEHC's parent, The Mission Group, which in turn loaned
the net proceeds to its parent, Edison International. Edison International used the funds, along with other
available funds, to repay its indebtedness that matured in 2001. The MEHC financing documents contain
restrictions on EME's ability and the ability of its subsidiaries to enter into specified transactions or engage
in specified business activities and require in some instances that EME obtain the approval of the MEHC board of
directors. EME's articles of incorporation also bind EME to the restrictions in the MEHC financing documents by
restricting EME's ability to enter into specified transactions or engage in specified business activities, other
than as permitted in the MEHC financing documents, without shareholder approval.
Business of EME
EME is an independent power producer engaged in the business of developing, acquiring, owning or leasing and
operating electric power generation facilities worldwide. EME also conducts energy trading and price risk
management activities in power markets open to competition.
EME was formed in 1986 with two domestic operating projects. As of December 31, 2001, EME owned interests in 31
domestic and 49 international operating power projects with an aggregate generating capacity of 23,967 MW, of
which EME's share was 19,019 MW. At that date, one domestic and six international projects, totaling 1,153 MW of
generating capacity, of which EME's anticipated share will be approximately 668 MW, were under construction. At
December 31, 2001, EME had consolidated assets of $10.7 billion and total shareholder's equity of $1.6 billion.
EME is incorporated under the laws of the State of Delaware, with headquarters and principal executive offices
located at 18101 Von Karman Avenue, Suite 1700, Irvine, California 92612, and EME's telephone number is
(949) 752-5588.
At December 31, 2001, EME employed 3,021 people, all of whom were full-time employees and approximately 188, 152
and 1,236 of whom were covered by collective bargaining agreements in the United Kingdom, Australia and the
United States, respectively.
EME operates predominantly in one line of business, electric power generation, which it has organized by
geographic regions: Americas, Asia-Pacific, and Europe and Middle East. EME's plants are located in different
geographic areas, which mitigate the effects of regional markets, economic downturns or unusual weather
conditions.
Page 26
Americas Region
As of December 31, 2001, EME had 31 operating projects in this region, all of which are presently located in the
United States and its territories. EME's Americas region is headquartered in Chicago, Illinois with additional
offices located in Irvine, California; Boston, Massachusetts; and Washington, D.C. A description of EME's major
power plants and major investments in energy projects in the Americas region is set forth below.
Illinois Plants
On December 15, 1999, EME completed a transaction with Commonwealth Edison, now a subsidiary of Exelon
Corporation, to acquire Commonwealth Edison's fossil-fuel power generating plants located in Illinois, which are
collectively referred to as the Illinois plants. These plants are located in the Mid-America Interconnected
Network, which has transmission connections to the East Central Area Reliability Council and other regional
markets. In connection with this transaction, EME entered into three power purchase agreements with Commonwealth
Edison with terms of up to five years expiring in 2004, pursuant to which Commonwealth Edison purchases capacity
and has the right to purchase energy generated by the plants. Subsequently, Commonwealth Edison assigned its
rights and obligations under these power purchase agreements to Exelon Generation Company, LLC. In each of 2003
and 2004, Exelon Generation is committed to purchase 1,696 MW of capacity from specific coal units, but has the
option to terminate two of the three agreements in their entirety or with respect to any generating unit or units
included under all of these agreements. EME's power purchase agreements with Exelon Generation accounted for 36%
and 42% of its electric revenues for 2001 and 2000, respectively. See further discussion of the power purchase
contracts with Exelon Generation under "Market Risk Exposures" in the MD&A that is incorporated by reference into
Part II, Item 7 of this report.
The Illinois plants comprise the following:
Interest
Power Generating Plants Location In Plant Type Megawatts
----------------------- -------- -------- ---- ---------
Collins Station ................... Grundy County, Illinois Leased oil/gas 2,698
Crawford Station................... Chicago, Illinois Owned coal 542
Fisk Station....................... Chicago, Illinois Owned coal 327
Joliet #9.......................... Joliet, Illinois Owned coal 314
Joliet #29......................... Joliet, Illinois Leased coal 1,044
Powerton Station................... Pekin, Illinois Leased coal 1,538
Waukegan Station................... Waukegan, Illinois Owned coal 789
Will County Station................ Romeoville, Illinois Owned coal 1,092
Peaking Sites
-------------
Crawford........................... Chicago, Illinois Leased oil/gas 167
Fisk............................... Chicago, Illinois Leased oil/gas 214
Joliet............................. Joliet, Illinois Leased oil/gas 133
Waukegan........................... Waukegan, Illinois Leased oil/gas 118
Calumet............................ Chicago, Illinois Leased oil/gas 158
Bloom.............................. Chicago Heights, Illinois Leased oil/gas 54
Electric Junction.................. Aurora, Illinois Leased oil/gas 188
Lombard............................ Lombard, Illinois Leased oil/gas 74
Sabrooke........................... Rockford, Illinois Leased oil/gas 89
---
Total
9,539
As part of the purchase of the Illinois plants, EME assigned its right to purchase the Collins Station to
third-party entities and EME's subsidiary simultaneously entered into long-term lease of the Collins
Page 27
Station. EME also completed sale-leaseback transactions with respect to its Illinois peaker units in July 2000
and its Powerton and Joliet power facilities in August 2000. EME sold these assets and entered into leases in
order to provide capital to finance, with respect to the Collins Station, the acquisition or, with respect to the
Illinois peaker units and the Powerton and Joliet facilities, repay corporate debt, in each case while
maintaining control over the use of the power plants during the terms of the leases. See further discussion of
these sale-leaseback transactions under "Off-Balance Sheet Transactions" in the MD&A that is incorporated by
reference into Part II, Item 7 of this report.
Homer City Facilities
On March 18, 1999, EME completed a transaction with GPU, Inc., New York State Electric & Gas Corporation and
their respective affiliates to acquire the 1,884 MW Homer City Electric Generating Station. These facilities
consist of three coal-fired steam turbine units, one coal preparation facility, an 1.800-acre site and associated
support facilities in the mid-Atlantic region of the United States and have direct, high voltage interconnections
to both the New York Independent System Operator, which controls the transmission grid and energy and capacity
markets for New York State, and the Pennsylvania-New Jersey-Maryland Power Pool. For further discussion of risks
related to the sale of electricity from the Homer City Facilities, see "Market Risk Exposures" in the MD&A that
is incorporated by reference into Part II, Item 7 of this report.
On December 7, 2001, EME's subsidiary completed a sale-leaseback of the Homer City facilities to third-party
lessors. EME sold the Homer City facilities and entered into long-term leases to provide capital to repay
corporate debt while maintaining control of the use of the facilities during the terms of the leases. See
"Off-Balance Sheet Transactions" and "EME Sale-Leaseback Transaction" in the MD&A that is incorporated by
reference into Part II, Item 7 of this report.
Major Investments in California Cogeneration Projects
EME owns partnership investments in the Kern River Cogeneration Company, Midway Sunset Cogeneration Company,
Sycamore Cogeneration Company and Watson Cogeneration Company, as described below. These projects have similar
economic characteristics and have been used, collectively, to secure bond financing by Edison Mission Energy
Funding LLC, a special purpose entity that EME includes in its consolidated financial statements. Due to similar
economic characteristics and the bond financing related to its equity investments, EME views these projects
collectively.
Kern River Project - EME owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW
natural gas-fired cogeneration facility located near Bakersfield, California. Kern River Cogeneration sells
electricity to SCE under a power purchase agreement that expires in 2005 and sells steam to Texaco Exploration
and Production Inc. under a steam supply agreement that also expires in 2005.
Midway-Sunset Project - EME owns a 50% partnership interest in Midway Sunset Cogeneration Company, which owns a
225 MW natural gas-fired cogeneration facility located near Taft, California. Midway-Sunset sells electricity to
SCE, Aera Energy LLC and PG&E under power purchase agreements that expire in 2009 and sells steam to Aera under a
steam supply agreement that also expires in 2009.
Sunrise Project - EME owns a 50% partnership interest in Sunrise Power Company, which owns a natural gas-fired
facility currently under construction in Kern County, California. The Sunrise Project consists of two phases.
Phase I, a simple-cycle gas-fired facility (320 MW), was completed on June 27, 2001. Phase II, a conversion to
a combined-cycle gas-fired facility (560 MW), is currently scheduled to be completed in July 2003. Sunrise Power
entered into a 10-year power purchase agreement with the CDWR on June 25, 2001. For further discussion about a
pending regulatory challenge to this agreement, see "Regulation of EME - California Deregulation and Energy
Crisis" below.
Page 28
Sycamore Project - EME owns a 50% partnership interest in Sycamore Cogeneration Company, which owns and operates
a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California. Sycamore Cogeneration
sells electricity to SCE under a power purchase agreement that expires in 2007 and sells steam to Texaco
Exploration and Production Inc. under a steam supply agreement that also expires in 2007.
Watson Project - EME owns a 49% partnership interest in Watson Cogeneration Company, which owns a 385 MW natural
gas-fired cogeneration facility located in Carson, California. Watson Cogeneration sells electricity to SCE and
to the adjacent British Petroleum refiners under power purchase agreements that expire in 2008 and sells steam to
ARCO Products Company under a steam supply agreement that also expires in 2008.
Other Projects in the Americas
EME's remaining projects in the Americas region consist of its Brooklyn Navy Yard, Gordonsville and EcoElectrica
projects described below. EME is currently offering all of its interests in these projects for sale.
Brooklyn Navy Yard Project - EME owns a 50% partnership interest in Brooklyn Navy Yard Cogeneration Partners
L.P., which owns a 286 MW natural gas and oil-fired cogeneration facility located near Brooklyn, New York.
Brooklyn Navy Yard sells electricity and steam to Consolidated Edison Company of New York, Inc. under a power
purchase agreement that expires in 2039. EME is currently offering this project for sale. See "Asset Sales"
below. See also "Litigation Involving Edison Mission Energy - PMNC Litigation" in Part I, Item 3 below, for
information about disputes related to the construction of this facility.
Gordonsville Project - EME owns a 50% partnership interest in Gordonsville Energy, L.P. which owns a 240 MW
natural gas-fired cogeneration facility located in Gordonsville, Virginia. Gordonsville Cogeneration sells
electricity to Virginia Electric & Power Company under a power purchase agreement that expires in 2024 and sells
steam to Rapidan Service Authority under a steam supply agreement that also expires in 2024. EME is currently
offering this project for sale. See "Asset Sales" below.
EcoElectrica Project - EME owns a 50% partnership interest in EcoElectrica L.P., which owns a 540 MW power plant
located in Penuelas, Puerto Rico. EcoElectrica sells electricity to Puerto Rico Electric Power Authority under a
power purchase agreement that expires in 2018 and sells water to Puerto Rico Water & Sewer Authority under a
water supply agreement that also expires in 2018. EME is currently offering this project for sale. See "Asset
Sales" below.
Asset Sales
During 2001, EME decided to offer for sale some of its non-strategic investments in energy projects to reduce
debt. At December 31, 2001, EME had agreements to sell five of its projects. Subsequent to December 31, 2001,
EME completed the sales of its interests in three of its projects. The sales of its interests in the
EcoElectrica and Gordonsville projects have not closed, and in each case, the sales agreement has terminated, and
EME has recommenced marketing efforts. On March 8, 2002, EME filed a lawsuit against Mirant Corporation and two
of its affiliates, alleging that Mirant wrongfully terminated the sale agreement for the purchase of the
EcoElectrica project. EME is currently offering for sale its interest in the Brooklyn Navy Yard, EcoElectrica and
Gordonsville projects. See "Acquisitions and Dispositions" in the MD&A that is incorporated by reference into
Part II, Item 7 of this report, for further details about EME's asset sales.
Investment in Four Star Oil and Gas Company
EME owns a 37.2% direct and indirect interest (with 36.05% voting stock) in Four Star Oil and Gas Company, with
majority control held by affiliates of Chevron Texaco Corp. Four Star Oil and Gas owns oil
Page 29
and gas reserves in the San Juan Basin, the Hugoton Basin, the Permian Basin and offshore Gulf Coast and
Alabama. Under a long-term service contract, the majority of Four Star Oil and Gas's properties are operated
through Texaco Exploration & Production Inc.
Asia-Pacific Region
As of December 31, 2001, EME had 15 operating projects in this region that are located in Australia, Indonesia,
Thailand and New Zealand. EME's Asia-Pacific region is headquartered in Singapore with additional offices
located in Australia, Indonesia and the Philippines. A description of EME's major power plants, investment in
Contact Energy, and investments in energy projects in the Asia-Pacific region is set forth below.
Australia
Loy Yang B Project - EME owns a 1,000 MW coal-fired power station in located in Traragon, Victoria Australia.
The project sells electricity to a centralized electricity pool, which provides for a system of generator
bidding, central dispatch and a settlements system based on a clearing market for each half-hour of every day.
The National Electricity Market Management Company, operator and administrator of the pool, determines a spot
price each half-hour. EME has entered into an agreement with the State Electricity Commission of Victoria that
provides through October 16, 2016, for the project to receive a fixed price for a portion of its electricity in
exchange for payment to the state of the spot price assignable to such portion of EME's electricity through
October 31, 2016. For further discussion of risks related to the sale of electricity from the Loy Yang B
project, see "Market Risk Exposures" in the MD&A that is incorporated by reference into Part II, Item 7 of this
report.
Valley Power Peaker Project - During 2001, EME began construction of a 300 MW gas-fired peaker plant located at
the Loy Yang B coal-fired power plant site. The peaker units will service peaking demand within the National
Energy Market of Eastern Australia and, specifically, within the State of Victoria by selling the output of the
peakers directly into the pool and by entering into financial contracts related to pool prices with other power
generators and distribution businesses. EME owns 60% interest in the Valley Power Peaker project with the
remaining interest held by its affiliate, Contact Energy.
Kwianna Project - EME owns a 70% interest in a 116 MW gas-fired cogeneration plant in Perth, Australia. EME
sells electricity to Western Power under a power purchase agreement that expires in 2021 and sells steam to
British Petroleum Kwianna refinery under a steam supply agreement which also expires in 2021.
New Zealand
Contact Energy - EME owns a 51.2% majority interest in Contact Energy Limited. The remaining shares of Contact
Energy are publicly held and traded on the New Zealand stock exchange. Contact Energy is the largest wholesaler
and retailer of natural gas in New Zealand and generates about one-quarter of New Zealand's electricity.
Indonesia
The Paiton Project - EME owns a 40% interest in PT Paiton Energy (Paiton Energy), which owns a 1,230 MW
coal-fired power plant in operation in East Java, Indonesia. Paiton Energy sells electricity to PT PLN, the
state-owned electric utility company, under a power purchase agreement that expires in 2029. PT PLN and Paiton
Energy signed a Binding Term Sheet on December 14, 2001, setting forth the revised commercial terms under which
Paiton Energy is to be paid for capacity and energy charges, as well as a monthly "restructure settlement
payment" covering arrears owed by PT PLN as well as settlement of other claims. In addition, the Binding Term
Sheet provides for an extension of the power purchase agreement from 2029 to 2039. For a further discussion of
the Paiton project, see "Paiton Project" in the MD&A that is incorporated by reference into Part II, Item 7 of
this report.
Page 30
Philippines
CBK Project - In February 2001, EME purchased a 50% interest in CBK Power Co. Ltd. CBK has entered into a
25-year build-rehabilitate-operate-transfer (BROT) agreement with National Power Corporation related to the 728 MW
Caliraya-Botocan-Kalayaan hydroelectric project located in the Philippines. CBK is paid capital recovery fees
and operations and maintenance fees for generating electricity and providing other services under the BROT
agreement. At December 31, 2001, 168 MW have been commissioned and are operational.
Thailand
Tri Energy Project - EME owns a 25% interest in Tri Energy Company Limited, which owns a 700 MW gas-fired
cogeneration plant located west of Bangkok, Thailand. Tri Energy sells electricity to Electricity Generating
Authority of Thailand under a power purchase agreement that expires in 2020.
Europe and Middle East Region
As of December 31, 2001, EME had 34 operating projects in this region that are located in the United Kingdom,
Turkey, Spain and Italy. EME's Europe and Middle East region is headquartered in London, England with additional
offices located in Italy, Spain and Turkey. The London office was established in 1989. A description of EME's
major power plants and major investments in energy projects in the Europe and Middle East region is set forth
below.
United Kingdom
First Hydro Project - EME owns two pumped storage stations in North Wales at Dinorwig and Ffestiniog which have a
combined capacity of 2,088 MW. Pumped storage stations consume electricity when it is comparatively less
expensive in order to pump water for storage in an upper reservoir. Water is then allowed to flow back through
turbines in order to generate electricity when its market value is higher. EME sells electricity and ancillary
services to regional electricity companies, other generators and into short-term markets. For further discussion
of the risks related to the sale of electricity from the First Hydro project, see "Market Risk Exposures" in the
MD&A that is incorporated by reference into Part II, Item 7 of this report.
Lakeland Project - EME owns a 220 MW combined-cycle natural gas-fired power plant located in Barrow-in-Furness,
Cumbria, United Kingdom. EME sells electricity to North Western Electricity Board under a power purchase
contract that expires in 2006.
Derwent Project - EME owns a 33% interest in Derwent Cogeneration Limited, which owns a 214 MW gas-fired
cogeneration plant in Derby, England. Derwent sells electricity to Southern Electric plc under a power purchase
agreement that expires in 2010 and sells steam to Courtaulds Chemicals (Holdings) Limited under a steam supply
contract that also expires in 2010.
Italy
ISAB Project - EME owns a 49% interest in ISAB Energy S.r.l. which owns a 512 MW integrated gasification combined
cycle power plant in Sicily, Italy. ISAB sells electricity to Gestore Rate Transmissione Nazionale, Italy's
state transmission company, under a power purchase agreement that expires in 2020. The ISAB project is located
at an oil refinery owned by ERG Petroli SpA.
Italian Wind Project - In 2000, EME purchased Edison Mission Wind Power Italy B.V., which owns a 50% interest in
a series of power projects that are in operation or under development in Italy by UPC International Partnership
CV II. The projects use wind to generate electricity from turbines, which is sold
Page 31
under fixed-price, long-term tariffs to Gestore Rate Transmissione Nazionale. At December 31, 2001, 230 MW have
been commissioned and are operational. Assuming all the projects under construction at December 31, 2001, are
completed, currently scheduled for 2002, the total capacity of these projects will be 283 MW.
Spain
Spanish Hydro Project - EME owns 18 small run-of-the-river hydro plants regionally dispersed in Spain totaling
86 MW. EME sells electricity to Fuerzas Electricas de Cataluma, S.A. under concessions that have various
expiration dates ranging from 2030 to 2065.
Turkey
Doga Project - EME owns an 80% interest in Doga Enerji which owns a 180 MW gas-fired cogeneration plant in
Istanbul, Turkey. Doga Enerji sell electricity to Turkiye Elektrik, Urehm A.S., under a power purchase agreement
that expires in 2018.
Discontinued Operations
As a result of the change in the prices of power in the United Kingdom and the anticipated negative impacts of
such changes on earnings and cash flow, EME offered for sale through a competitive bidding process the
Ferrybridge and Fiddler's Ferry coal-fired power plants located in the United Kingdom. On December 21, 2001, EME
completed the sale of the power plants to two wholly-owned subsidiaries of American Electric Power. In addition,
as part of the transactions, the purchasers acquired other assets and assumed specified liabilities associated
with the plants. EME acquired the plants in 1999 from PowerGen UK plc. For additional information, see
"Discontinued Operations" in the MD&A that is incorporated by reference into Part II, Item 7 of this report.
Financial Ratios
In assessing the leverage of EME's ability to meet debt service obligations, EME uses two primary ratios:
recourse debt to recourse capital ratio and an interest coverage ratio. These ratios are determined in
accordance with financial covenants that have been included in EME's corporate credit facilities and are not
determined in accordance with generally accepted accounting principles as reflected in its Consolidated
Statements of Cash Flows. Accordingly, these ratios should not be considered in isolation or as a substitute for
cash flows from operating activities or cash flow statement data set forth in EME's Consolidated Statement of
Cash Flows. While the ratios included in EME's corporate credit facilities measure the leverage and ability of
EME to meet its debt service obligations, they do not measure the liquidity or ability of EME's subsidiaries to
meet their debt service obligations. Furthermore, these ratios are not necessarily comparable to other similarly
titled captions of other companies due to differences in methods of calculation.
Page 32
EME's corporate credit facilities include covenants tied to these financial ratios(1):
Actual at December 31,
-------------
Financial Ratio Covenant 2001 Description
- --------------- -------- ---- -----------
Recourse Debt to Less than or 64.1% Ratio of (a) senior recourse debt to (b)
Recourse Capital Ratio equal to sum of (i) shareholder's equity per EME's
67.5% balance sheet adjusted by comprehensive
income after December 31, 1999, plus (ii)
----
senior recourse debt
Interest Coverage Greater than or 1.64 to 1.00 For prior 12-month period, ratio of (a)
Ratio equal to funds flow from operations to (b) interest
1.50 to 1.00 expense on senior recourse debt
(1) EME's corporate credit facilities and corporate debt securities include a tangible net worth covenant, which
is determined based on EME's shareholder's equity adjusted for changes in other comprehensive income after
December 31, 1999. At December 31, 2001, EME's tangible net worth as determined in accordance with the
covenant was $944.9 million, which exceeds the covenant requirement of $613.8 million.
At December 31, 2001, EME met the above financial covenants. The actual interest coverage ratio during 2001 was
adversely affected by the operating results of the Ferrybridge and Fiddler's Ferry projects in the United
Kingdom. The interest coverage ratio, excluding the activities of the Ferrybridge and Fiddler's Ferry projects,
was 1.98 to 1.0. Compliance with these covenants is subject to future financial performance, including items
that are beyond EME's control. See "Market Risk Exposures" in the MD&A that is incorporated by reference into
Part II, Item 7 of this report.
Discussion of Recourse Debt to Recourse Capital Ratio
The recourse debt to recourse capital ratio of EME at December 31, 2001, and 2000 was calculated as follows:
December 31,
-----------------------------
-------------- --------------
2001 2000
---- ----
(in millions)
Recourse Debt(1)
Corporate Credit Facilities $ 203.6 $ 1,339.8
Senior Notes 1,700.0 700.0
Guarantee of termination value of
Powerton/Joliet operating leases 1,431.9 1,394.5
Coal and CapEx Facility 251.6 86.7
Other 46.3 130.7
---- -----
Total Recourse Debt to EME $ 3,633.4 $ 3,651.7
------- -------
Recourse Capital $ 2,039.0 $ 3,255.4
------- -------
Total Capitalization $ 5,672.4 $ 6,907.1
======= =======
Recourse Debt to Recourse Capital Ratio 64.1% 52.9%
(1) Recourse debt means direct obligations of EME or obligations of one of its subsidiaries for which EME has
provided a guaranty.
During 2001, the recourse debt to recourse capital ratio was adversely affected by a decrease in EME's
shareholder's equity from $1.1 billion of after-tax losses, attributable to the loss on sale of its Ferrybridge
Page 33
and Fiddler's Ferry coal-fired power plants located in the United Kingdom. EME sold the Ferrybridge and
Fiddler's Ferry power plants in December 2001 due, in part, to the adverse impact of the negative cash flow
pertaining to these plants. EME's recourse debt at December 31, 2001, was slightly less than its recourse debt
at December 31, 2000, with the proceeds from new notes issued during the course of the year having been used to
repay short-term indebtedness.
Discussion of Interest Coverage Ratio
The following table sets forth the major component of EME's interest coverage ratio for 2001 and 2000:
December 31,
---------------------------------
---------------- ----------------
2001 2000
---- ----
(in millions)
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating
Projects(2):
Midwest Generation $ 201.3 $ 175.4
Homer City 175.2 106.7
Ferrybridge and Fiddler's Ferry (104.5) (9.2)
First Hydro 45.9 132.8
Other consolidated operating projects 64.1 43.5
Trading and price risk management 28.2 (44.9)
Distributions from non-consolidated Big 4 projects(2) 222.3 170.0
----- -----
Distributions from other non-consolidated operating projects
------------------------------------------------------------
Interest income 9.0 12.5
Operating expenses (143.1) (81.5)
----- ----
Total funds flow from operations 498.4 505.3
----- -----
Interest Expense 304.8 206.8
----- -----
Interest Coverage Ratio 1.64 2.44
==== ====
(1) Operating cash flow is defined as revenues less operating expenses, foreign taxes paid and project debt
service.
(2) Consolidated operating projects are entities in which EME owns more than a 50% interest and, thus, includes
the operating results and cash flows in its consolidated financial statements. Non-consolidated operating
projects are entities in which EME owns 50% or less and account for on the equity method.
(3) The Big 4 projects are comprised of investments in the Kern River project, Midway-Sunset project, Sycamore
project and Watson project. See description under "Business of EME - Americas Region - Major Investments in
California Cogeneration Projects," above.
The major factors affecting funds from operations in 2001 compared to 2000 were:
o Changes in market prices for energy and capacity from the Homer City, Ferrybridge and Fiddler's Ferry and
First Hydro projects. As a result of the sale of the Ferrybridge and Fiddler's Ferry plants, EME does not
expect to incur negative cash flow from this project in future periods. See "Market Risk Exposures" in the
MD&A that is incorporated by reference into Part II, Item 7 of this report.
o Change in the fair value of the natural gas swap entered into in 2000 as a hedge against the changes in
natural gas prices from EME's investment in Four Star Oil & Gas.
o Lower 2000 operating expenses as a result of the reduction in the liability for previously accrued incentive
compensation during 2000 of approximately $60 million.
Page 34
Interest expense increased $98 million in 2001 from 2000 as a result of:
o higher average debt balance in 2001 attributable in large part to the California power crisis;
o an increase in borrowing costs from refinancing short-term debt with 2001 issuances of $1 billion long-term
fixed rate debt as well as higher interest margins on EME's corporate credit facilities; and
o additional 2001 financing fees from three maturity extensions of EME's corporate lines of credit.
Credit Ratings
To isolate itself from the impact of the California power crisis on Edison International and SCE, and to
facilitate its ability and the ability of its subsidiaries to maintain their respective investment grade credit
ratings, on January 17, 2001, EME amended its articles of incorporation and its bylaws to include "ring-fencing"
provisions. These ring-fencing provisions are intended to preserve EME as a stand-alone investment grade rated
entity. These provisions require the unanimous approval of EME's board of directors, including at least one
independent director, before EME can do any of the following:
o declare or pay dividends or distributions unless either of the following are true: EME then has an
investment grade credit rating and receives rating agency confirmation that the dividend or distribution
will not result in a downgrade; or the dividends do not exceed $32.5 million in any fiscal quarter and EME
meets an interest coverage ratio of not less than 2.2 to 1 for the immediately preceding four fiscal
quarters;
o institute or consent to bankruptcy, insolvency or similar proceedings or actions; or consolidate or merge
with any entity or transfer substantially all its assets to any entity, except to an entity that is subject
to similar restrictions.
In January 2001, Standard & Poor's and Moody's Investors Service downgraded EME's senior unsecured credit ratings
to "BBB-" from "A-" and to "Baa3" from "Baa1", respectively. EME's credit ratings remain investment grade.
Maintaining investment grade credit ratings is part of EME's current operational focus and long-term strategy.
However, EME cannot assure that Standard & Poor's and Moody's will not downgrade EME's credit rating below
investment grade. If EME's credit ratings are downgraded below investment grade, EME could be required to, among
other things:
o provide additional collateral in the form of letters of credit or cash for the benefit of counterparties
in its domestic trading and price risk management activities related to accounts receivable and unrealized
losses ($7.4 million at December 31, 2001); and
o post a letter of credit or cash collateral to support its $45.3 million equity contribution obligation
in connection with its acquisition in February 2001 of a 50% interest in the CBK Power Co. Ltd. project in
the Philippines, which equity contribution would otherwise be payable commencing after full draw down of the
debt facility currently scheduled for late 2002.
A downgrade of EME's credit ratings could result in a downgrade of the credit rating of Edison Mission Midwest
Holdings Co., an indirect subsidiary. In the event of a downgrade of Edison Mission Midwest Holdings below its
current credit ratings, provisions in the agreements binding on its subsidiary, Midwest Generation, LLC, would
limit the ability of Midwest Generation to use excess cash flow to make distributions.
A downgrade in EME's credit ratings below investment grade could increase its cost of capital, increase its
credit support obligations, make efforts to raise capital more difficult, and have an adverse impact on EME
Page 35
and its subsidiaries. A downgrade in the credit rating of EME below investment grade would adversely impact its
ability to pay dividends to Edison International and, to the extent its situation continued beyond July 1, 2003,
it would adversely affect EME's ability to meet its debt service obligations. In addition, if the credit rating
were downgraded, in order to continue to market the power from its Homer City facilities and First Hydro plants
as well as purchase natural gas or fuel oil at its Illinois Plants, EME may be required to provide substantial
additional credit support in the form of letters of credit or cash. In addition, if the credit rating were
downgraded, changes in forward market prices and margining requirements could further increase the need for
credit support for EME's trading and price risk management activities.
Recently, Standard & Poor's and Moody's have indicated that they are reviewing the criteria for assessing credit
risk for merchant energy companies (companies that generate and/or trade wholesale power without long-term
contracts). The criteria used by Standard & Poor's and Moody's in assessing credit risk in turn is used to
assign credit ratings, including whether or not a company is investment grade. EME cannot predict whether
Standard & Poor's or Moody's will change their criteria for assessing credit risk or, if changes were made,
whether or not such changes would adversely affect EME's credit ratings.
Trading and Risk Management Activities
EME has developed risk management policies and procedures, which, among other things, address credit risk. When
making sales under negotiated bilateral contracts, it is EME's general policy to deal with investment grade
counterparties or counterparties that have equivalent credit quality. EME's risk management committees grant
exceptions to the policy only after review and scrutiny. Most entities that have received exceptions are
organized power pools and quasi-governmental agencies. EME hedges a portion of the electric output of its
merchant plants in order to provide more predictable earnings and cash flow. When appropriate, EME manages the
spread between electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts
to achieve those objectives.
EME's domestic power marketing and trading organization, Edison Mission Marketing & Trading, Inc., markets and
trades electric power and energy related to commodity products, including forwards, futures, options and swaps.
It also provides services and price risk management capabilities to the electric power industry. EME segregates
its activities into two categories:
o Marketing and Fuel Management - Edison Mission Marketing & Trading engages in the sale of electricity and
purchase of fuels through intercompany contracts with EME's subsidiaries that own or lease the Illinois
plants and the Homer City facilities. The objective of these activities is to sell the output of the power
plants on a forward basis, thereby increasing the predictability of earnings and cash flows. EME also
conducts risk management activities to manage the price risk associated with the purchase of fuels,
including natural gas and fuel oil.
o Trading - In conducting its trading activities, EME seeks to generate profit from price volatility of
electricity and fuels by buying and selling these commodities in wholesale markets. EME generally balances
forward sales and purchases contracts and manages its exposure through a value at risk analysis, as
described further below. EME also conducts price risk management activities for third parties generally not
related to its power plants or investments in energy projects, including restructuring of power sales and
power supply agreements.
Edison Mission Marketing & Trading is divided into front-, middle-, and back-office segments, with specified
duties segregated for control purposes. The personnel of Edison Mission Marketing & Trading have a high level of
knowledge of utility operations, fuel procurement, energy marketing and futures and options trading. EME has
systems in place which monitor real time spot and forward pricing and perform option valuations. EME also has a
wholesale power scheduling group that operates on a 24-hour basis.
Internationally, EME also conducts price risk management activities through subsidiaries that are primarily
focused on marketing and fuel management activities in the same manner described above.
Page 36
Energy trading and price risk management activities give rise to commodity price risk, which represents the
potential loss that can be caused by a change in the market value of a particular commodity. Commodity price
risks are actively monitored to ensure compliance with EME's risk management policies. Policies are in place
which limit the amount of total net exposure EME may enter into at any point in time. Procedures exist which
allow for monitoring of all commitments and positions with daily reporting to senior management. EME performs a
"value at risk" analysis in its business to measure, monitor and control its overall market risk exposure. The
use of value at risk allows management to aggregate overall risk, compare risk on a consistent basis and identify
the drivers of the risk. Value at risk measures the worst expected loss over a given time interval, under normal
market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a
single risk measurement tool, EME supplements this approach with stress testing and worst-case scenario analysis,
as well as stop limits and counterparty credit exposure limits.
Seasonality
Due to warmer weather during the summer months, electric revenues generated from the Homer City facilities and
the Illinois plants are usually higher during the third quarter of each year. In addition, EME's third quarter
revenues from energy projects are materially higher than other quarters of the year due to a significant number
of its domestic energy projects located on the west coast of the United States, which generally have power sales
contracts that provide for higher payments during the summer months. Certain other plants, including the First
Hydro plants, provide for higher electric revenues during the winter months.
Competitive Environment of EME
EME and its subsidiaries are subject to intense competition in the United States and overseas from energy
marketers, utilities, industrial companies and other independent power producers. Over the past several years,
the restructuring of energy markets has led to the sale of utility-owned assets to EME and its competitors. More
recently, in response to market conditions, EME has, and believes other power generators have, changed focus from
acquisition and growth to concentrating on selective asset dispositions as well as postponing or canceling power
plants under development. This trend is in response to credit concerns in the wake of the Enron bankruptcy,
economic recession in the United States, and a potential oversupply of new generating capacity.
In markets where EME sells power from plants where the output is not committed to be sold under long-term
contracts, commonly referred to as merchant plants, EME is subject to substantial competition with independent
power producers with power plants located in the same geographic region. EME competes primarily based on price,
reliability and other factors which are heavily influenced by electricity demand and supply, which is commonly
referred to as capacity. EME's customers include large electric utilities or regional distribution companies.
In some cases, the electric utilities and distribution companies have their own generation capacity, including
nuclear generation, that affects the amount of generation available to meet demand and may affect the price of
electricity in a particular market.
Amendments to the Public Utility Holding Company Act made by the Energy Policy Act have increased the number of
competitors in the domestic independent power industry by reducing restrictions applicable to projects that are
not QFs under the Public Utility Regulatory Policies Act. Retail wheeling of power, which is the offering by
utilities of unbundled retail distribution service, could also lead to increased competition in the independent
power market. See "Regulation of EME - Retail Competition" below.
Page 37
Regulation of EME
General
EME's operations are subject to extensive regulation by governmental agencies in each of the countries in which
it conducts operations. EME's domestic operating projects are subject to energy, environmental and other
governmental laws and regulations at the federal, state and local levels in connection with the development,
ownership and operation of, and use of electric energy, capacity and related products, including ancillary
services from its projects. Federal laws and regulations govern, among other things, transactions by and with
purchasers of power, including utility companies, the operations of a project and the ownership of a project.
Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or
waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility
regulatory commissions may have broad jurisdiction over non-utility owned electric power plants. Energy
producing projects are also subject to federal, state and local laws and regulations that govern the geographical
location, zoning, land use and operation of a project. Federal, state and local environmental requirements
generally require that a wide variety of permits and other approvals be obtained before the commencement of
construction or operation of an energy producing facility and that the facility then operate in compliance with
these permits and approvals. While EME believes the requisite approvals for its existing projects have been
obtained and that its business is operated in substantial compliance with applicable laws, EME remains subject to
a varied and complex body of laws and regulations that both public officials and private parties may seek to
enforce. Regulatory compliance for the construction of new facilities is a costly and time consuming process.
Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures
and may create a significant risk of expensive delays or significant loss of value in a project if the project is
unable to function as planned due to changing requirements or local opposition.
Furthermore, each of EME's international projects is subject to the energy and environmental laws and regulations
of the foreign country in which this project is located. The degree of regulation varies according to each
country and may be materially different from the regulatory regime in the United States.
United States Federal Energy Regulation
The FERC has ratemaking jurisdiction and other authority with respect to interstate sales and transmission of
electric energy under the Federal Power Act and with respect to certain interstate sales, transportation and
storage of natural gas under the Natural Gas Act of 1938. The enactment of the Public Utility Regulatory
Policies Act of 1978 and the adoption of regulations thereunder by the FERC provided incentives for the
development of cogeneration facilities and small power production facilities using alternative or renewable fuels
by establishing certain exemptions from the Federal Power Act and the Public Utility Holding Company Act for the
owners of QFs. The passage of the Energy Policy Act in 1992 further encouraged independent power production by
providing additional exemptions from the Public Utility Holding Company Act for exempt wholesale generators and
foreign utility companies.
Federal Power Act - The Federal Power Act grants the FERC exclusive ratemaking jurisdiction over wholesale sales
of electricity in interstate commerce, including ongoing, as well as initial, rate jurisdiction. This
jurisdiction allows the FERC to revoke or modify previously approved rates. These rates may be based on a
cost-of-service approach or, in geographic and product markets determined by FERC to be workably competitive, may
be market-based. As noted, most QFs are exempt from the ratemaking and several other provisions of the Federal
Power Act. Exempt wholesale generators and other non-QF independent power projects are subject to the Federal
Power Act and to the ratemaking jurisdiction of the FERC thereunder, but the FERC typically grants exempt
wholesale generators the authority to charge market-based rates as long as the absence of market power is shown.
In addition, the Federal Power Act grants the FERC jurisdiction over the sale or transfer of jurisdictional
facilities, including wholesale power sales contracts.
Page 38
Currently, in addition to the facilities owned or operated by EME, a number of its operating projects, including
the Homer City facilities, the Illinois plants, and Brooklyn Navy Yard facilities, are subject to the FERC
ratemaking regulation under the Federal Power Act. EME's future domestic non-QF independent power projects will
also be subject to FERC jurisdiction on rates.
The Public Utility Holding Company Act - Unless exempt or found not to be a holding company by the SEC, a company
that owns 10% or more of the voting securities of an electric utility company falls within the definition of a
holding company and becomes subject to regulation under the Public Utility Holding Company Act. Exempt wholesale
generators, foreign utility companies and QFs are not deemed to be electric utility companies for purposes of the
Public Utility Holding Company Act; and power marketing activities alone do not result in an entity being deemed
to be an electric utility company.
As discussed above under "Business of Edison International - Regulation of Edison International," Edison
International is currently exempt from most provisions of the Public Utility Holding Company Act. Consequently,
EME is not a subsidiary of a registered holding company, so long as Edison International continues to be exempt
from registration. Nor is EME a holding company under the Public Utility Holding Company Act, because EME's
interests in power generation facilities are exclusively in QFs, exempt wholesale generators and foreign utility
companies. All international projects and specified United States projects that EME is currently developing or
proposing to acquire will be non-QF independent power projects. EME intends for each project to qualify as an
exempt wholesale generator or as a foreign utility company. Loss of exempt wholesale generator, QF or foreign
utility company status for one or more projects could result in EME becoming a holding company subject to
registration and regulation under the Public Utility Holding Company Act and could trigger defaults under the
covenants in EME's project agreements. Becoming a holding company could, on a retroactive basis, lead to, among
other things, fines and penalties and could cause certain of EME's project agreements and other contracts to be
voidable.
Public Utility Regulatory Policies Act of 1978 - The Public Utility Regulatory Policies Act provides two primary
benefits to QFs. First, ownership of QFs will not result in a company's being deemed an electric utility company
for purposes of the Public Utility Holding Company Act. Second, the FERC regulations promulgated under the
Public Utility Regulatory Policies Act require that electric utilities purchase electricity generated by QFs at a
price based on the purchasing utility's avoided cost, and that the utilities sell back up power to the QF on a
non discriminatory basis. The FERC's regulations also permit QFs and utilities to negotiate agreements for
utility purchases of power at prices different than the utility's avoided costs. While it has been common for
utilities to enter into long-term contracts with QFs in order, among other things, to facilitate project
financing of independent power facilities and to reflect the deferral by the utility of capital costs for new
plant additions, increasing competition and the development of new power markets have resulted in a trend toward
shorter term power contracts that would place greater risk on the project owner.
If one of the projects in which EME has an interest were to lose its status as a QF, the project would no longer
be entitled to the QF-related exemptions from regulation under the Public Utility Holding Company Act and the
Federal Power Act. As a result, the project could become subject to rate regulation by the FERC under the
Federal Power Act, and EME could inadvertently become a holding company under the Public Utility Holding Company
Act. If a project were to lose its QF status, EME could attempt to avoid holding company status on a prospective
basis by qualifying the project owner as an exempt wholesale generator. However, assuming this changed status
would be permissible under the terms of the applicable power sales agreement, rate approval from the FERC would
be required. In addition, the project would be required to cease selling electricity to any retail customers, in
order to qualify for exempt wholesale generator status, and could become subject to additional state regulation.
Loss of QF status by one project could also potentially cause other projects with the same partners to lose their
QF status. Loss of QF status could also trigger defaults under covenants to maintain QF status in the project's
power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or
acceleration of indebtedness under such agreements. If a power purchaser were to cease taking and
Page 39
paying for electricity or were to seek to obtain refunds of past amounts paid because of the loss of QF status,
EME cannot assure that the costs incurred in connection with the project could be recovered through sales to
other purchasers. Moreover, EME's business and financial condition could be adversely affected if regulations or
legislation were modified or enacted that changed the standards for maintaining QF status or that eliminated or
reduced the benefits, such as the mandatory purchase provisions of the Public Utility Regulatory Policies Act and
exemptions currently enjoyed by QFs. Loss of QF status on a retroactive basis could lead to, among other things,
fines and penalties being levied against EME, or claims by a utility customer for the refund of payments
previously made.
Natural Gas Act - Twenty-one of the domestic operating facilities that EME owns, operates or has investments in
use natural gas as their primary fuel. Under the Natural Gas Act, the FERC has jurisdiction over certain sales
of natural gas and over transportation and storage of natural gas in interstate commerce. The FERC has granted
blanket authority to all persons to make sales of natural gas without restriction but continues to exercise
significant oversight with respect to transportation and storage of natural gas services in interstate commerce.
California Deregulation and Energy Crisis
EME has partnership interests in eight QF partnerships that own power plants in California and have power
purchase contracts with PG&E and/or SCE. Three of these partnerships have a contract with SCE, four of them have
a contract with PG&E, and one of them has contracts with both. In 2001, EME's share of earnings before taxes
from these partnerships was $244 million, which represented 35% of its operating income. EME's investment in
these partnerships at December 31, 2001 was $527.9 million. As a result of the liquidity crisis affecting SCE
and PG&E during 2001, each of them failed to make payments during the first quarter of 2001 to these
partnerships. This adversely affected the cash flow from EME's eight California QFs. In March 2002, SCE paid
all material past-due amounts to the partnerships that have contracts with SCE.
On March 27, 2001, the CPUC issued a decision that modified the pricing formula for determining short-run avoided
costs for certain QFs, including four of the partnerships in which EME has a partnership interest. This decision
could have a material adverse effect on EME's investment in those partnerships, depending on how it is
implemented and future changes in the relationship between the pricing formula and the actual cost of natural gas
procured by EME's California partnerships.
On April 6, 2001, PG&E filed for reorganization under Chapter 11 of the United States Bankruptcy Code in San
Francisco bankruptcy court. PG&E has paid for power delivered after the bankruptcy filing, but it paid only a
small portion of the amounts due to the partnerships for power delivered in December 2000 and January 2001, and
made no payment at all for power delivered in February and March 2001. At the petition date, accounts receivable
to these partnerships from PG&E were $47 million. EME's share of these receivables was $23 million. Effective
as of July 31, 2001, PG&E and four of the partnerships in which EME has a partnership interest entered into
agreements that amended the power purchase agreements to provide for a fixed energy price for the lesser of the
remaining term of the power purchase agreement or five years. The contract amendments were approved by both the
bankruptcy court and the CPUC. PG&E assumed the power purchase agreements, as amended, and, in addition to
payments for current deliveries of power, is making payments of the past-due receivables on an agreed schedule
which, absent further defaults by PG&E, should bring the past-due amounts current by the end of the first quarter
of 2003.
Sunrise Power Company, in which a subsidiary of EME owns a 50% interest, sells all of its output to the CDWR
under a power purchase agreement entered into on June 25, 2001. On February 25, 2002, the CPUC and the
California Electricity Oversight Board filed complaints with the FERC against all sellers of long-term contracts
to the CDWR, including Sunrise Power Company. The CPUC complaint alleges that the contracts are "unjust and
unreasonable" on price and other terms, and requests that the contracts be abrogated. The California Electricity
Oversight Board complaint makes a similar allegation and requests
Page 40
that the contracts be deemed voidable at the request of the CDWR or, in the alternative, abrogated as of a future
date, to allow for the possibility of renegotiation. In response, on March 19, 2002, Sunrise filed a motion to
dismiss with the FERC requesting, among other things, a dismissal of both complaints and expedited treatment of
its motion; however, EME cannot predict what actions the FERC may take at this proceeding.
Retail Competition
In response to pressure from retail electric customers, particularly large industrial users, the state
commissions or state legislatures of most states are considering, or have considered, whether to open the retail
electric power market to competition. Retail competition is possible when a customer's local utility agrees, or
is required, to unbundle its distribution service, for example, the delivery of electric power through its local
distribution lines, from its transmission and generation service, for example, the provision of electric power
from the utility's generating facilities or wholesale power purchases. Several state commissions and
legislatures have issued orders or passed legislation requiring utilities to offer unbundled retail distribution
service, which is called retail wheeling, and phasing in retail wheeling over the next several years.
The competitive pricing environment that will result from retail competition may cause utilities to experience
revenue shortfalls and deteriorating creditworthiness. However, EME expects that most, if not all, state plans
will insure that utilities receive sufficient revenues, through a distribution surcharge if necessary, to pay
their obligations under existing long-term power purchase contracts with qualifying facilities and exempt
wholesale generators. On the other hand, QFs and exempt wholesale generators may be subject to pressure to lower
their contract prices in an effort to reduce the stranded investment costs of their utility customers.
Other State and Foreign Energy Regulation
Regulatory matters affecting EME in certain states in the United States and recent foreign regulatory matters are
discussed in "Market Risk Exposures" in the MD&A that is incorporated by reference into Part II, Item 7 of this
report."
Environmental Matters Affecting EME
EME is subject to environmental regulation by federal, state and local authorities in the United States and
foreign regulatory authorities with jurisdiction over projects located outside the United States. EME believes
that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance
with current requirements will not materially affect its financial position or results of operations. However,
possible future developments, such as the promulgation of more stringent environmental laws and regulations, and
future proceedings that may be initiated by environmental authorities, could affect the costs and the manner in
which EME conducts its business and could cause EME to make substantial additional capital expenditures. There
is no assurance that EME would be able to recover these increased costs from its customers or that its financial
position and results of operations would not be materially adversely affected.
Typically, environmental laws require a lengthy and complex process for obtaining licenses, permits and approvals
prior to construction and operation of a project. Meeting all the necessary requirements can delay or sometimes
prevent the completion of a proposed project as well as require extensive modifications to existing projects,
which may involve significant capital expenditures.
State - Illinois
Air Quality. In June 2001, Illinois passed legislation mandating the Illinois Environmental Protection Agency to
evaluate and issue a report to the Illinois legislature addressing the need for further emissions controls on
fossil fuel-fired electric generating stations, including the potential need for additional controls
Page 41
on nitrogen oxides, sulfur dioxide and mercury. The study, which is to be submitted between September 30, 2003,
and September 30, 2004, also requires an evaluation of incentives to promote renewable energy and the
establishment of a banking system for certifying credits from voluntary reductions of greenhouse gases. The law
allows the Illinois Environmental Protection Agency to propose regulations based on its findings no sooner than
90 days after the issuance of its findings, and requires the Illinois Pollution Control Board to act within one
year on such proposed regulations. Until the Illinois Environmental Protection Agency issues its findings and
proposes regulations in accordance with the findings, if such regulations are proposed, EME cannot evaluate the
potential impact of this legislation on the operations of its facilities.
Water Quality. The Illinois EPA is reviewing the water quality standards for the Des Plaines River adjacent to
the one EME generating station and immediately downstream of the another EME generating station to determine if
the use classification should be upgraded. One of the limitations for discharges to the river that could be made
more stringent if the existing secondary contact classification is changed would be the allowable temperature of
the discharges from the applicable counties. At this time no new standards have been proposed, so EME cannot
estimate the financial impact of this review.
State - Pennsylvania
Water Quality. EME's coal-cleaning plant National Pollutant Discharge Elimination System, commonly referred to
as NPDES, permit was recently renewed by the Pennsylvania Department of Environmental Protection, or PADEP,
Bureau of Water Management. It now includes water quality-based limits for certain contaminants. EME is not
required to meet these limits until February 2005 but must conduct toxics reduction evaluation studies in the
meantime. These limits may require upgrade of EME's facilities' wastewater treatment systems with such
approaches as reverse osmosis, ozonation, dechlorination and/or recycling of water. EME has contested these
requirements in an administrative appeal, but hopes to reach an amicable resolution with PADEP.
The discharge from the treatment plant receiving the wastewater stream from the Homer City Unit 3 flue gas
desulfurization system has exceeded the limits for selenium in the station's NPDES permit. The selenium limits
are water-quality-based and require removal to very low levels. EME is investigating technical alternatives to
maximize the level of selenium removal in the discharge. EME is also meeting with PADEP to discuss potential
modifications to the Station's NPDES permit.
EME conducts ground water monitoring in a number of areas throughout the site, including active and former ash
disposal sites, wastewater and runoff settling and drainage ponds and a coal refuse disposal site. On
September 27, 2001, the Pennsylvania Department of Environmental Protection responded to an assessment report by
stating that no further groundwater assessment or abatement is required for the industrial waste treatment ponds.
To date, PADEP has not requested that any additional remediation actions be performed at the site. EME's
facility has a drinking water treatment system designed to meet applicable potable water standards. Recent tests
indicate that EME's facilities' drinking water supply meets these standards.
Helvetia Discharges. EME's Homer City generating units were originally constructed as a mine-mouth generating
station, where coal produced from two adjacent deep mines was delivered directly to the units by coal conveyors.
The two adjacent deep mines were owned by Helen Mining Company, a subsidiary of the Quaker State Corporation, and
Helvetia, a subsidiary of the Rochester and Pittsburgh Coal Company. Both Helen Mining and Helvetia developed
mine refuse sites, water treatment facilities and other mine related facilities on the site. The Helen Mining
mine was closed in the early 1990s, and the mine surface operations and maintenance shop areas were restored
before Helen Mining left the site. Helen Mining has continuing mine water and refuse site leachate treatment
obligations and remains obligated to perform any cleanup required with respect to its refuse site. Helvetia's
on-site mine was closed in 1995. As a result of the cessation of its on-site mining activities, Helvetia has
continuing mine discharge and refuse site leachate discharge treatment obligations that it performs using water
treatment facilities owned by Helvetia and located on the site. Bonds posted by Helvetia may not be sufficient
to fund Helvetia's
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obligations in the event of Helvetia's failure to comply with its mine-related permits at the site. Current
annual operating costs for Helvetia's treatment systems are estimated to be approximately $1 million.
If Helvetia defaults on its treatment obligations, the government may look to EME to fund these commitments.
Penn Hill No. 2 and Dixon Run No. 3 Discharges. In connection with EME's purchase of the Homer City facilities,
EME acquired the Two Lick Creek Dam and Reservoir. Acid mine drainage discharges from the Penn Hill No. 2 and
Dixon Run No. 3 inactive deep mines were collected and partially treated on the reservoir property by Stanford
Mining Company before being pumped off the property for additional treatment at the nearby Chestnut Ridge
Treatment Plant. The mining company filed for bankruptcy, however, it operated the collection and treatment
system until May 1999 when its assets were allegedly depleted.
PADEP initially advised EME that it was potentially liable for treating the two discharges solely because of
EME's ownership of the property from which the discharges emanated. Without any admission of its liability, EME
voluntarily entered into a letter agreement to fund the operation of the collection and treatment system for an
interim period until the agency completed its investigation of potentially liable parties and alternatives for
permanent treatment of the discharges were evaluated. After examining property records, PADEP concluded that EME
is only responsible for treating the Dixon Run No. 3 discharge. The agency completed its investigation of other
potentially responsible parties, particularly mining companies that previously operated the two mines, and has
notified EME that they plan no further action against other parties.
A draft consent decree agreement that addresses remedial responsibilities for the two discharges has been
prepared by PADEP. Under its terms, EME is responsible for designing and implementing a permanent system to
collect and treat the Dixon Run No. 3 discharge. EME will continue its funding of the existing collection and
treatment system until the Dixon Run No. 3 treatment system becomes operational. The state has provided funding
to the Blacklick Creek Watershed Association to develop and operate a collection and treatment system for the
Penn Hill No. 2 discharge. The Watershed Association has completed construction of the Penn Hill No. 2 system,
and it will be fully operational in the next several months.
The current cost of operating the collection and treatment system is approximately $17,000 per month. EME
expects that the costs of operation will be reduced by 30% to 40% as a result of the completion of the Penn Hill
No. 2 system. EME has evaluated options for permanent treatment of the Dixon Run No. 3 discharge, and concluded
that conventional chemical treatment is the most appropriate option. The capital cost of the system is estimated
to be $1 million. Its operational costs cannot be determined until design and permitting are complete.
Federal - United States of America
Clean Air Act. EME expects that compliance with the Clean Air Act and the regulations and revised State
Implementation Plans developed as a consequence of the Act will result in increased capital expenditures and
operating expenses. For example, EME expects to spend approximately $17.8 million for 2002 to install upgrades
to the environmental controls at the Homer City facilities to reduce sulfur dioxide and nitrogen oxide
emissions. Similarly, EME anticipates upgrades to the environmental controls at the Illinois plants to reduce
nitrogen oxide emissions to result in expenditures of approximately $367.9 million for the 2002 - 2005 period.
Mercury MACT Determination. On December 20, 2000, the EPA issued a regulatory finding that it is "necessary and
appropriate" to regulate emissions of mercury and other hazardous air pollutants from coal-fired power plants.
The agency has added coal-fired power plants to the list of source categories under Section 112(c) of the Clean
Air Act for which "maximum available control technology" standards will be developed. Eventually, unless
overturned or reconsidered, the EPA will issue technology-based standards that will apply to every coal-fired
unit owned by EME or its affiliates in the United States. This section of the Clean Air Act provides only for
technology-based standards, and does not permit market
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trading options. Until the standards are actually promulgated, the potential cost of these control technologies
cannot be estimated, and EME cannot evaluate the potential impact on the operations of its facilities.
National Ambient Air Quality Standards. A new ambient air quality standard was adopted by the EPA in July 1997
to address emissions of fine particulate matter. It is widely understood that attainment of the fine particulate
matter standard may require reductions in nitrogen oxides and sulfur dioxides, although, under the time schedule
announced by the EPA when the new standard was adopted, non-attainment areas were not to have been designated
until 2002 and control measures to meet the standard were not to have been identified until 2005. In May 1999,
the United States Court of Appeals for the District of Columbia Circuit held that Section 109(b)(1) of the Clean
Air Act, the section of the Clean Air Act requiring the promulgation of national ambient air quality standards,
as interpreted by the EPA, was an unconstitutional delegation of legislative power. The Court of Appeals
remanded both the fine particulate matter standard and the revised ozone standard to allow the EPA to determine
whether it could articulate a constitutional application of Section 109(b)(1). On February 27, 2001, the Supreme
Court, in Whitman v. American Trucking Associations, Inc., reversed the Circuit Court's judgment on this issue
and remanded the case back to the Court of Appeals to dispose of any other preserved challenges to the
particulate matter and ozone standards. Accordingly, as the final application of the revised particulate matter
ambient air quality standard is potentially subject to further judicial proceedings, the impact of this standard
on EME's facilities is uncertain at this time.
EME believes that its facilities are in material compliance with applicable state and federal air quality
requirements. Further reductions in emissions may be required for the achievement and maintenance of National
Ambient Air Quality Standards for ozone and fine particulate.
Clean Water Act -ss.316(b) Rulemakings. The EPA proposed rules establishing standards for the location, design,
construction and capacity of cooling water intake structures at new facilities, including steam electric power
plants. Under the terms of a consent decree entered into by the United States District Court for the Southern
District of New York in Riverkeeper, Inc. v. Whitman, regulations for new facilities were adopted by November 9,
2001. Pursuant to the consent decree, the agency proposed similar regulations for existing facilities on
February 28, 2002, and is required to finalize those regulations by August 28, 2003. Until the final standards
are promulgated, EME cannot determine their impact on its facilities or estimate the potential cost of compliance.
Comprehensive Environmental Response, Compensation, and Liability Act. Under various federal, state and local
environmental laws and regulations, a current or previous owner or operator of any facility, including an
electric generating facility, may be required to investigate and remediate releases or threatened releases of
hazardous or toxic substances or petroleum products located at that facility, and may be held liable to a
governmental entity or to third parties for property damage, personal injury and investigation and remediation
costs incurred by these parties in connection with these releases or threatened releases. Many of these laws,
including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the
Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew
of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to
be strict and joint and several. The cost of investigation, remediation or removal of these substances may be
substantial. In connection with the ownership and operation of EME's facilities, EME may be liable for these
costs.
In addition, persons who arrange for the disposal or treatment of hazardous or toxic substances at a disposal or
treatment facility may be liable for the costs of removal or remediation of a release or threatened release of
hazardous or toxic substances at that disposal or treatment facility, whether or not that facility is owned or
operated by that person. Some environmental laws and regulations create a lien on a contaminated site in favor
of the government for damages and costs it incurs in connection with the contamination. The owner of a
contaminated site and persons who arrange for the disposal of hazardous substances at that site also may be
subject to common law claims by third parties based on damages and costs resulting from environmental
contamination emanating from that site. In connection with the ownership and operation of EME's facilities, EME
may be liable for these costs.
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EME accrues for costs for the sites related to investigation, remediation and groundwater monitoring as required
under existing environmental regulations to the extent the costs are probable and can be reasonably estimated.
EME does not believe it can provide an estimate of the reasonably possible total remediation costs for any site
before a remedial investigation has been completed. To the extent that remediation is necessary, the timing of
the remediation activities has an impact on the cost of remediation. Therefore, EME currently cannot determine
the total costs that may be incurred in connection with the remediation of all sites, to the extent that
remediation might be required. In connection with the acquisition of the Illinois plants, EME generally
indemnified the prior owner with respect to environmental remediation liabilities, unless otherwise specified in
the acquisition agreement. As part of that pre-acquisition diligence, EME engaged a third party to conduct an
assessment of EME's possible future costs for environmental remediation. EME believes the scope of this
assessment was less rigorous than a typical remedial investigation. Since EME considers the level of due
diligence in this study to be lower than the level of due diligence that would normally be involved in a remedial
investigation, EME did not record a liability as part of fair value of assets acquired and liabilities assumed in
December 1999. EME plans individual site assessments as appropriate in its judgment. As those assessments are
completed, EME will determine whether to perform or update a remedial investigation.
Enforcement Issues. EME owns an indirect 50% interest in EcoElectrica, L.P., a limited partnership which owns
and operates a liquefied natural gas import terminal and cogeneration project at Penuelas, Puerto Rico. In 2000,
the United States EPA issued to EcoElectrica a notice of violation and a compliance order alleging violation of
the Federal Clean Air Act primarily related to start-up activities. Representatives of EcoElectrica have met
with the EPA to discuss the notice of violation and compliance order. To date, EcoElectrica has not been
informed of the commencement of any formal enforcement proceedings. It is premature to assess what, if any,
action will be taken by the EPA.
On November 3, 1999, the United States Department of Justice filed suit against a number of electric utilities
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. See the discussion under "Business of SCE - Environmental Matters Affecting SCE," above.
Prior to EME's purchase of the Homer City facilities, the EPA requested information from the prior owners of the
plant concerning physical changes at the plant. Other than with respect to the Homer City facilities, no
proceedings have been initiated or requests for information issued with respect to any of EME's United States
facilities. However, EME has been in informal voluntary discussions with the EPA relating to these facilities,
which may result in the payment of civil fines. EME cannot give assurance that it will reach a satisfactory
agreement or that these facilities will not be subject to proceedings in the future. Depending on the outcome of
the proceedings, EME could be required to invest in additional pollution control requirements, over and above the
upgrades EME is planning to install, and could be subject to fines and penalties. EME cannot estimate the
outcome of these discussions or the potential costs of investing in additional pollution control requirements,
fines or penalties at this time.
International
United Nations Framework Convention on Climate Change. Since the adoption of the United Nations Framework
Convention on Climate Change in 1992, there has been worldwide attention with respect to greenhouse gas
emissions. In December 1997, the Clinton administration participated in the Kyoto, Japan negotiations, where the
basis of a Climate Change treaty was formulated. Under the treaty, known as the Kyoto Protocol, the United
States would be required, by 2008 - 2012, to reduce its greenhouse gas emissions by 7% from 1990 levels.
The Kyoto Protocol has yet to be submitted to the United States Senate for ratification. In March 2001, the Bush
administration announced that the United States would not ratify the Kyoto Protocol, but would instead offer an
alternative. On February 14, 2002, President Bush announced objectives to slow the growth of greenhouse gas
emissions by reducing the amount of greenhouse gas emissions per unit of
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economic output by 18% by 2012 and to provide funding for climate-change related programs. The President's
proposed program does not include mandatory reductions of greenhouse gas emissions. However, various bills have
been, or are expected to be, introduced in Congress to require greenhouse gas emissions reductions and to address
other issues related to climate change. Apart from the Kyoto Protocol, EME may be impacted by future federal or
state legislation relating to controlling greenhouse gas emissions.
Notwithstanding the Bush administration position, environment ministers from around the world have reached a
compromise agreement on the mechanics and rules of the Kyoto Protocol. The compromise agreement is believed to
clear the way for countries to begin the treaty ratification process.
With the exception of Turkey, all of the countries in which EME does business have ratified the United Nations
Framework Convention on Climate Change, as well as signed the Kyoto Protocol. None of the countries have
ratified the Kyoto Protocol, but, with the exception of the United States, all are expected to do so by the end
of 2002. For the treaty to come into effect, approximately 55 countries that also represent at least 55% of the
greenhouse gas emissions of the developed world must ratify it.
All of the countries, with the exception of Indonesia, the Philippines and Thailand, are classified as Annex 1 or
"developed" countries and are subject to national greenhouse gas emission reduction targets during the period of
2008 - 2012 (e.g., Phase 1). Each nation is actively developing policies and measures meant to assist it with
meeting the individual national emission targets as set out within the Kyoto Protocol.
If EME does become subject to limitations on emissions of carbon dioxide from its fossil fuel-fired electric
generating plants, these requirements could have a significant economic impact on its operations.
Properties of EME
The following table shows the properties owned or leased by EME or its projects and which are material to EME.
Each property represents at least five percent of EME's income before tax or is one in which EME has an
investment balance greater than $50 million. Most of these properties are subject to mortgages or other liens or
encumbrances granted to the lenders providing financing for the plant or project.
Business Interest
Plant or Project Segment Location In Land Plant Description
---------------- ------- -------- ------- -----------------
Brooklyn Navy Yard.. Americas Brooklyn, New York Leased Natural gas-turbine cogeneration
facility
Contact............. Asia Pacific Wellington, New Zealand Owned/Leased Various
Doga................ Europe Esenyurt, Turkey Owned Combined cycle generation technology
EcoElectrica........ Americas Penuelas, Puerto Rico Owned Liquified natural gas cogeneration
facility
First Hydro......... Europe Dinorwig, Wales Owned Pumped-storage electric power
facility
First Hydro......... Europe Ffestiniog, Wales Owned Pumped-storage electric power
facility
Homer City.......... Americas Pittsburgh, Pennsylvania Owned Coal-fired generation facility
Illinois plants..... Americas Northeast Illinois Owned/Leased Coal, oil/gas-fired generation
facilities
Kern River.......... Americas Oildale, California Leased Natural gas-turbine cogeneration
facility
Loy Yang B.......... Asia Pacific Victoria, Australia Owned Coal-fired generation facility
Midway-Sunset....... Americas Fellows, California Leased Natural gas-turbine cogeneration
facility
Paiton.............. Asia Pacific East Java, Indonesia Leased Coal-fired generation facility
Roosecote........... Europe Barrow-in-Furness, Owned Combined cycle generation technology
Cumbria, UK
Sunrise............. Americas Fellows, California Leased Simple cycle generation technology
Sycamore............ Americas Oildale, California Leased Natural gas-turbine cogeneration
facility
Watson.............. Americas Carson, California Leased Natural gas-turbine cogeneration
facility
Business of Edison Capital
Edison Capital provides capital and financial services in energy and infrastructure projects, including power
generation, electric transmission and distribution, transportation, telecommunications, and
Page 46
affordable housing. On December 31, 2001, Edison Capital had total consolidated assets of $3.7 billion and, for
the year then ended, consolidated revenue of $202 million and net income of $84 million. Edison Capital invested
$29 million in energy and infrastructure projects and $5 million in affordable housing in 2001.
Europe - In 2000, Edison Capital invested $272 million in a telecommunications duct network with Swisscom,
- ------
Switzerland's partially privatized, government majority-owned national telecommunications company. Located in
northeast Switzerland, the duct network carries all voice and data traffic. This transaction was a follow-on
investment to Edison Capital's 1999 investment of $116 million with Swisscom. In its first participation in an
EME project, Edison Capital provided $243 million of mezzanine financing for the acquisition of the Ferrybridge
and Fiddler's Ferry generating stations in northern England. This financing was committed in 1999 and closed in
January 2000. In January 2001, Edison Capital redeemed its investment in Ferrybridge and Fiddler's Ferry plants
for the original investment value plus accrued coupons. Edison Capital also committed $125 million to co-sponsor
a new $525 million Emerging Europe Infrastructure Fund L.P., which will invest in electricity and infrastructure
projects in Central and Eastern Europe. American International Group Inc. (AIG) and ABN-AMRO are the other
co-sponsors of the fund. Through the fund, Edison Capital has invested $40 million in six projects. During
2000, Edison Capital also closed $4 million in mezzanine investments in seven infrastructure and education
facilities under the United Kingdom's Private Finance Initiative.
In May 2001, Edison Capital, through a wholly-owned subsidiary, sold its ownership interest in seven
infrastructure projects resulting in net cash proceeds of $39 million and a recorded gain on sale of assets of
$6 million. This sale represented the entire remaining Edison Capital mezzanine investment portfolio.
United States - Edison Capital owns interest in four wind-energy projects placed into service in 1999 with an
- -------------
aggregate investment of $108 million. All of these projects are located in the Midwest, including Edison
Capital's most recent investment in Enron Wind Corp.'s Storm Lake I.
Edison Capital has an investment of approximately $85 million in the partnership that operates Storm Lake I. The
lenders have sent a notice to the partnership claiming that Enron Corporation's bankruptcy is an event of default
under the loan agreement. In the event of default, the lenders may exercise certain remedies, including
acceleration of the loan balance and repossession and foreclosure of the project, which could result in the loss
of some or all of Edison Capital's investment in the project. Edison Capital expects the project to demonstrate
that Enron's bankruptcy does not impair its ability to meet its loan obligations. Edison Capital also expects
that the partnership will vigorously oppose any attempt by the lenders to exercise remedies that could result in
Edison Capital's loss of its investment.
Latin America - Edison Capital actively participates in the $1 billion AIG-GE Latin American Infrastructure Fund
- -------------
(LAIF). This fund is in the latter stages of its investment cycle, with approved investments totaling 80% of
Edison Capital's original $80 million commitment. Through the fund, Edison Capital invested $60 million in 19
projects. Together with LAIF and AIG, and others Edison Capital also directly invested another $20 million in
cable television systems in Mexico.
Asia - Edison Capital entered the Asian market in 1998 through its $100 million commitment and active
- ----
participation in the $1.7 billion AIG Asian Infrastructure Fund II. Through its participation in the fund in
2001, Edison Capital closed investments of $2 million in three projects. As of year-end 2001, Edison Capital has
invested $59 million or 59% of the total commitment.
Affordable Housing - Over the past 12 years, Edison Capital has invested more than $1 billion in more than 350
- ------------------
affordable housing projects representing 28,000 housing units in 37 states. During 2001, the company closed
$5 million in investments, and had no new commitments. Edison Capital completed four syndications of affordable
housing properties during the year which generated $47 million in operating revenues.
Edison Capital has entered into investments that rely in part on specific federal and state tax benefits and
incentives available under existing laws and regulations. There is no assurance against changes in those
Page 47
laws, or unfavorable interpretation and application of the laws by tax authorities, which could adversely affect
Edison Capital's business prospects or, if applied retrospectively, its return on existing investments.
Edison Capital historically receives cash from Edison International for the federal and state tax benefits and
incentives flowing from Edison Capital's investments that are actually utilized on the Edison International tax
return. However, due to the impacts of the California energy crisis on Edison International, these tax benefits
and incentives are not currently being fully utilized by Edison International and Edison Capital is not currently
receiving full cash benefits for them. Without such cash, Edison Capital must meet its current obligations out
of existing unrestricted cash ($73 million at February 28, 2002) and/or by disposing of some of its investments.
Any failure by Edison Capital to meet its obligations as and when they become due could be expected to have a
material adverse effect on Edison Capital's financial position and ability to conduct future operations. In the
current circumstances, Edison Capital is not pursuing any new investment opportunities.
Other Nonutility Companies
Edison Enterprises: Edison Enterprises was organized to own the stock and coordinate the activities of Edison
International's retail products and services business. One of Edison Enterprises' subsidiaries, Edison Utility
Services (EUS), was sold in January 2001, because management determined that the business conducted by EUS no
longer fit well with Edison International's core business strategy. During the second quarter of 2001, Edison
Enterprises decided to sell its remaining subsidiaries, Edison Select and Edison Source. On August 1, 2001, it
sold Edison Select to ADT Security Services, Inc. In June 2001, Edison Source entered into a letter of intent to
sell substantially all of its assets to its current management. The sale was completed October 18, 2001. For
additional information, see "Discontinued Operations" in the MD&A that is incorporated by reference into Part II,
Item 7 of this report.
Prior to its sale, Edison Select was engaged in the business of providing home services to consumers, and
currently provides electrical repair services under the Edison OnCall name, as well as providing security
services through Edison Security.
Prior to sale of most of its assets, Edison Source was engaged in the business of integrated energy outsourcing.
Integrated energy outsourcing services include the energy efficient retrofit, operation, and maintenance of
refrigeration, heating, ventilating, air conditioning, lighting, and other electrical systems equipment. Edison
Source continues to engage of the business of providing rapid battery charging technology for the electric fork
lift market.
Edison O&M Services: In January 2001, Edison O&M Services began providing operation and maintenance
services to third parties, including certain of the independent power companies who now own the generation
stations SCE sold in 1998. Edison O&M Services is not material to the operations and results of Edison
International.
Item 2. Properties
As a holding company, Edison International does not directly own any significant properties other than the stock
of its subsidiaries. The principal properties of SCE are described below. Properties of EME and Edison Capital
are discussed above under "Business of the Nonutility Companies - Business of EME" and " - Business of Edison
Capital."
Generating Facilities of SCE
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 of SCE - Environmental Matters
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Affecting SCE and Fuel Supply and Purchased Power Costs of SCE - Coal Supply," and "Business of SCE -
Environmental Matters Affecting SCE" 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 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 being 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, 23% 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) 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, 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
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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 of SCE), 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.
SCE 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 of SCE - Liquidity Issues."
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Nuclear Power Matters of SCE
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 in 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 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.
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 the 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.
Page 51
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 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 trusts which, together with accumulated
earnings, will be utilized solely for decommissioning.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of San
Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance
is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor
licensee if a nuclear incident at any licensed reactor in the United States results in claims and/or costs which
exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial
protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum
deferred premium for each nuclear incident is $88 million per reactor, but not more than $10 million per reactor
may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay
a maximum of $175 million per nuclear incident. It would have to pay, however, no more than $20 million per
incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public
liability claims and are subject to adjustment for inflation. If the public liability limit above is
insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and
Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million has also
been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement
power expenses during an accident-related nuclear unit outage. These policies are issued by a mutual insurance
company owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement
were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium
adjustments of up to $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 52
Item 3. Legal Proceedings
Litigation Involving Edison International
Shareholder Litigation
Edison International has been named as a defendant along with SCE in two lawsuits, which have recently been
dismissed, as more fully described under "Litigation Involving Southern California Edison Company - Shareholder
Litigation."
Qualifying Facilities Litigation
Edison International along with SCE has been named as a defendant in one of the lawsuits more fully described
under "Litigation Involving Southern California Edison Company - Qualifying Facilities Litigation."
Litigation Involving Edison Mission Energy
PMNC Litigation
In February 1997, a civil action was commenced in the Superior Court of the State of California, Orange County,
entitled The Parsons Corporation and PMNC v. Brooklyn Navy Yard Cogeneration Partners, L.P. (Brooklyn Navy Yard),
Mission Energy New York, Inc. and B-41 Associates, L.P., in which plaintiffs assert general monetary claims under
the construction turnkey agreement in the amount of $136.8 million. In addition to defending this action,
Brooklyn Navy Yard has also filed an action in the Supreme Court of the State of New York, Kings County entitled
Brooklyn Navy Yard Cogeneration Partners, L.P. v. PMNC, Parsons Main of New York, Inc., Nab Construction
Corporation, L.K. Comstock & Co., Inc. and The Parsons Corporation, asserting general monetary claims in excess
of $13 million under the construction turnkey agreement. On March 26, 1998, the Superior Court in the California
action granted PMNC's motion for attachment against Brooklyn Navy Yard in the amount of $43 million and PMNC
subsequently attached three checking accounts in the amount of $0.5 million. Brooklyn Navy Yard has appealed the
attachment order. On the same day, the Court stayed all proceedings in the California action pending the New
York action. That appeal was denied following a hearing on September 29, 1998. On March 9, 1999, Brooklyn Navy
Yard filed a partial Motion for Summary Judgment in the New York action which was ultimately denied. In
December 1999, Brooklyn Navy Yard appealed the orders denying partial Summary Judgment. The appeal and the
commencement of discovery were suspended until June 2000, to allow for voluntary mediation between the parties.
The mediation ended unsuccessfully on March 23, 2000. On November 13, 2000, a New York appellate court issued a
ruling granting summary judgment in favor of Brooklyn Navy yard, striking PMNC's cause of action for quantum
meruit, and limiting PMNC to its claims under the construction contract. In August 2001, PMNC filed a motion to
lift the stay of the California action and to amend the California action to (1) add EME as a defendant; and
(ii) add EME as a party to the attachment previously granted against Brooklyn Navy Yard. PMNC's motion to lift
the stay of the California action was denied on October 11, 2001, and its petition for writ of mandamus was
summarily denied by the California Court of Appeals on November 20, 2001. On September 20, 2001, L.K. Comstock
filed for bankruptcy in the United States. Bankruptcy Court, District of Maryland, Baltimore Division, stayed the
pending action as to it, and thereafter agreed to and did lift the stay. On February 14, 2002, PMNC moved to
amend the complaint to add EME and to seek a $43 million attachment against EME. This motion is presently
calendared for May 2002.
Litigation Involving Southern California Edison Company
San Onofre Personal Injury Litigation
SCE is actively involved in four lawsuits claiming personal injuries allegedly resulting from exposure to
radiation at San Onofre.
Page 53
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.
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
Page 54
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 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
Page 55
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
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
Page 56
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, 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 of SCE - Changing Regulatory Environment of SCE - 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
Page 57
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 "Business of SCE - Changing Regulatory Environment of SCE" 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
- -------------------------------------------------------------------------------------------------------------------
Edison International
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
Age at
Executive Officer December 31, 2001 Company Position
- -------------------------------- -------------------------- -------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
John E. Bryson 58 Chairman of the Board, President, Chief Executive
Officer and Director
- -------------------------------- -------------------------- -------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
Theodore F. Craver, Jr. 50 Executive Vice President, Chief Financial Officer and
Treasurer
- -------------------------------- -------------------------- -------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
Bryant C. Danner 64 Executive Vice President and General Counsel
- -------------------------------- -------------------------- -------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
Mahvash Yazdi 50 Senior Vice President and Chief Information Officer
- -------------------------------- -------------------------- -------------------------------------------------------
- -------------------------------- -------------------------- -------------------------------------------------------
Thomas M. Noonan 50 Vice President and Controller
- -------------------------------- -------------------------- -------------------------------------------------------
(1) Executive Officers are defined by Rule 3b-7 of the General Rules and Regulations under the Securities
Exchange Act of 1934, as amended. Pursuant to this rule, the Executive Officers of Edison International
include certain elected officers of Edison International and its subsidiaries SCE, Edison Mission Energy,
and Edison Capital, all of whom may be deemed significant policy makers of Edison International. None of
Edison International's Executive Officers is related to each other by blood or marriage.
Page 58
As set forth in Article IV of Edison International's Bylaws, the elected officers of Edison International
are chosen annually by and serve at the pleasure of Edison International'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 of Edison International have been actively
engaged in the business of Edison International, SCE, and/or the Nonutility Companies for more than five
years except Mahvash Yazdi. Those officers who have not held their present position with Edison
International for the past five years had the following business experience during that period:
- ----------------------------------------------------------------------------------------------------------------------
Edison International
- ------------------------------- ------------------------------------------------- ------------------------------------
Executive Officer Company Position Effective Dates
- ------------------------------- ------------------------------------------------- ------------------------------------
John E. Bryson Chairman of the Board, President, Chief January 2000 to present
Executive Officer, and Director, Edison
International
Chairman of the Board, Edison Mission Energy January 2000 to present
and Edison Capital
Chairman of the Board, Chief Executive Officer, October 1990 to December 1999
and Director, Edison International and SCE
- ------------------------------- ------------------------------------------------- ------------------------------------
Theodore F. Craver, Jr. Executive Vice President, Chief Financial January 2002 to present
Officer, and Treasurer, Edison International
Senior Vice President, Chief Financial Officer January 2000 to December 2001
and Treasurer, Edison International
Chairman of the Board and Chief Executive September 1999 to August 2001
Officer, Edison Enterprises
Senior Vice President and Treasurer, Edison February 1998 to January 2000
International
Senior Vice President and Treasurer, SCE February 1998 to September 1999
Vice President and Treasurer, Edison September 1996 to February 1998
International and SCE
- ------------------------------- ------------------------------------------------- ------------------------------------
Bryant C. Danner Executive Vice President and General Counsel, January 2000 to present
Edison International
Executive Vice President and General Counsel, June 1995 to December 1999
Edison International and SCE
- ------------------------------- ------------------------------------------------- ------------------------------------
Mahvash Yazdi Senior Vice President and Chief Information January 2000 to present
Officer, Edison International and SCE
Vice President and Chief Information Officer, May 1997 to December 1999
Edison International and SCE
Vice President of Information Technology and September 1994 to May 1997
Chief Information Officer, Hughes Aircraft
Company(1)
- ------------------------------- ------------------------------------------------- ------------------------------------
Thomas M. Noonan Vice President and Controller, Edison March 1999 to present
International and SCE
Assistant Controller, Edison International and September 1993 to February 1999
SCE
- ------------------------------- ------------------------------------------------- ------------------------------------
(1) This entity is not a parent, subsidiary or other affiliate of Edison International.
Page 59
- --------------------------------------------------------------------------------------------------------------------
Southern California Edison Company
- --------------------------------------------------------------------------------------------------------------------
- -------------------------- -------------------------- --------------------------------------------------------------
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
- -------------------------- -------------------------- --------------------------------------------------------------
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 of
SCE have been actively engaged in the business of SCE, Edison International and/or the Nonutility Companies for
more than five years. Those officers who have not held their present position with SCE for the past five years
had the following business experience during that period:
- --------------------------------------------------------------------------------------------------------------------
Southern California Edison Company
- --------------------------------------------------------------------------------------------------------------------
- --------------------------- ---------------------------------------------- -----------------------------------------
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 January 1998 to September 1999
Enterprises
---------------------------------------------- -----------------------------------------
---------------------------------------------- -----------------------------------------
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, April 2001 to December 2001
Edison International and SCE
---------------------------------------------- -----------------------------------------
---------------------------------------------- -----------------------------------------
Senior Vice President, Public Affairs, November 1996 to April 2001
Edison International and SCE
- --------------------------- ---------------------------------------------- -----------------------------------------
- --------------------------------------------------------------------------------------------------------------------
The Nonutility Companies
- ---------------------------------- -------------------------- ------------------------------------------------------
Age at
Executive Officer December 31, 2001 Company Position
- ---------------------------------- -------------------------- ------------------------------------------------------
John E. Bryson(1) 58 Chairman of the Board, Edison Mission Energy and
Edison Capital
- ---------------------------------- -------------------------- ------------------------------------------------------
- ---------------------------------- -------------------------- ------------------------------------------------------
William J. Heller 46 President and Chief Executive Officer,
Edison Mission Energy
- ---------------------------------- -------------------------- ------------------------------------------------------
- ---------------------------------- -------------------------- ------------------------------------------------------
Thomas R. McDaniel 52 President and Chief Executive Officer,
Edison Capital
- ---------------------------------- -------------------------- ------------------------------------------------------
(1) Mr. Bryson is also deemed an Executive Officer due to his positions at Edison International. Information
concerning Company position and business experience is set forth under Edison International. Edison
International is the parent holding company of the Nonutility Companies.
Page 60
As set forth in Article IV of their respective Bylaws, the elected officers of the Nonutility Companies are
chosen annually by and serve at the pleasure of the respective Boards 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 of the Nonutility Companies have been actively engaged in the
business of the respective Nonutility Companies, Edison International, and/or SCE for more than five years.
Those officers who have not held their present position with the Nonutility Companies for the past five years had
the following business experience:
- -----------------------------------------------------------------------------------------------------------------
The Nonutility Companies
- ----------------------------- ------------------------------------------- ---------------------------------------
Executive Officer Company Position Effective Dates
- ----------------------------- ------------------------------------------- ---------------------------------------
William J. Heller President and Chief Executive Officer, January 2002 to present
Edison Mission Energy
------------------------------------------- ---------------------------------------
Senior Vice President, Edison Mission February 2000 to December 2001
Energy
------------------------------------------- ---------------------------------------
------------------------------------------- ---------------------------------------
Senior Vice President, Edison January 1996 to January 2000
International
- ----------------------------- ------------------------------------------- ---------------------------------------
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Information responding to Item 5 is included in Edison International's Annual Report to Shareholders for the year
ended December 31, 2001, (Annual Report) under Quarterly Financial Data on page 87 and under Shareholder
Information on page 91, and is incorporated by reference pursuant to General Instruction G(2). The number of
Common Stock shareholders of record was 72,774 on March 25, 2002. Additional information concerning the market
for Edison International's Common Stock is set forth on the cover page hereof.
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 88, 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 on
pages 5 through 43 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 19 through 24 incorporated herein by reference to General
Instruction G(2).
Item 8. Financial Statements and Supplementary Data
Certain information responding to Item 8 is set forth after Item 14 in Part IV. Other information responding to
Item 8 is included in the Annual Report on pages 46 through 86 and is incorporated herein by reference pursuant
to General Instruction G(2).
Page 61
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Information concerning executive officers of Edison International is set forth in Part I in accordance with
General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information
responding to Item 10 will be incorporated by reference from Edison International's definitive Joint Proxy
Statement (Proxy Statement) filed with the SEC in connection with Edison International's Annual Shareholders'
Meeting to be held on May 14, 2002, under the heading, "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 Edison International,
who are expected to retire from the Board on May 14, 2002:
Warren Christopher, age 76, has been a Director of Edison International from April 1988 through January 1993 and
from May 1997 to date. He is also a Director of SCE. 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 Edison International since 1988 and is also a Director of
SCE. 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 a Director of Edison International since
1988. 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 Edison International'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,"
"Compensation and Executive Personnel Committees' Interlocks and Insider Participation," and "Five-Year Stock
Performance Graph" 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 Edison International'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 Edison International's definitive Proxy
Statement under the heading "Certain Relationships and Transactions of Nominees and Executive
Page 62
Officers" and "Other Management Transactions," and is incorporated herein by reference pursuant to General
Instruction G(3).
In addition, Mr. Christopher is a Senior Partner of the law firm of O'Melveny and Myers. The firm provided legal
services to Edison International, SCE, and/or their 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. Edison International 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 5 through 88, and are incorporated by
reference in this report.
Management's Discussion and Analysis of Results of Operations and Financial Condition
Responsibility for Financial Reporting
Report of Independent Public Accountants
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 Shareholders' Equity - Years Ended December 31, 2001, 2000,
1999, and 1998
Notes to Consolidated Financial Statements
(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 65
Schedule I - Condensed Financial Information of Parent 66
Schedule II - Valuation and Qualifying Accounts for the
Years Ended December 31, 2001, 2000, and 1999 69
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 73 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.
Page 63
(b) Reports on Form 8-K
October 2, 2001
Item 5: Other Events Settlement Agreement
October 8, 2001
Item 5: Other Events Sales of Nonutility Generating Stations and Approval of
Settlement Agreement
October 30, 2001
Item 5: Other Events Settlement Agreement
Page 64
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
ON SUPPLEMENTAL SCHEDULES
To Edison International:
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 Edison International 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 Edison International'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 65
Edison International
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED BALANCE SHEETS
December 31,
- -------------------------------------------------------------------------------------------------------------------
2001 2000
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
Assets:
Cash and equivalents $ 31,434 $ 255,323
Other current assets 106,485 112,396
- -------------------------------------------------------------------------------------------------------------------
Total current assets 137,919 367,719
Investments in subsidiaries 5,989,341 5,104,107
Other deferred debits 5,183 5,333
- -------------------------------------------------------------------------------------------------------------------
Total assets $ 6,132,443 $ 5,477,159
- -------------------------------------------------------------------------------------------------------------------
Liabilities and Shareholders' Equity:
Accounts payable $ 1,608 $ 2,183
Other current liabilities 80,013 1,278,265
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 81,621 1,280,448
Long-term debt 746,848 745,702
Other long-term liabilities 1,670,643 866,285
Other deferred credits 32,303 25,060
Common shareholders' equity 3,601,028 2,559,664
- -------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 6,132,443 $ 5,477,159
- -------------------------------------------------------------------------------------------------------------------
Page 66
Edison International
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------
(In thousands, except per-share amounts)
Operating revenue and other income $ 105,747 $ 107,573 $ 73,892
Operating expenses and interest expense 247,436 243,872 114,447
- -------------------------------------------------------------------------------------------------------------------
Loss before equity in earnings of subsidiaries (141,689) (136,299) (40,555)
Equity in earnings of subsidiaries 1,176,634 (1,806,498) 663,585
- -------------------------------------------------------------------------------------------------------------------
Net income (Loss) $ 1,034,945 $ (1,942,797) $ 623,030
- -------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock outstanding 325,811 332,560 347,551
Basic earnings per share $ 3.18 $ (5.84) $ 1.79
Diluted earnings per share $ 3.17 $ (5.84) $ 1.79
Page 67
Edison International
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------
(In thousands)
Cash Flows From Operating Activities $ (320,606) $ (217,134) $ 137,336
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities 97,144 468,246 (113,581)
- -------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities (427) (1,351) (25,294)
- -------------------------------------------------------------------------------------------------------------------
Increase (Decrease) in cash and equivalents (223,889) 249,761 (1,539)
Cash and equivalents at beginning of period 255,323 5,562 7,101
- -------------------------------------------------------------------------------------------------------------------
Cash and Equivalents at the End of Period $ 31,434 $ 255,323 $ 5,562
- -------------------------------------------------------------------------------------------------------------------
Cash dividends received from Southern California
Edison Company $ 0 $ 372,268 $ 663,282
Page 68
Edison International
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 $ 36,513 $ 43,529 $ 32 $ 37,119 $ 42,955
All other 3,433 1,836 0 1,613 3,656
- -------------------------------------------------------------------------------------------------------------------
Total $ 39,946 $ 45,365 $ 32 $ 38,732(a) $ 46,611
- -------------------------------------------------------------------------------------------------------------------
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 307,729 197,985 973(d) 78,167(e) 428,520
Maintenance accrual -- -- -- -- --
Insurance, casualty and other 71,368 54,836 -- 51,059(f) 75,145
- -------------------------------------------------------------------------------------------------------------------
Total $ 875,249 $ 252,821 $ 973 $ 245,099 $ 883,944
- -------------------------------------------------------------------------------------------------------------------
(a) Accounts written off, net.
(b) Represents amounts paid.
(c) Represents the amortization of the liability established for purchased-power contract settlement agreements.
(d) Primarily represents transfers from the accrued paid absence allowance account for required additions to the
comprehensive disability plan accounts.
(e) Includes pension payments to retired employees, amounts paid to active employees during periods of illness
and the funding of certain pension benefits.
(f) Amounts charged to operations that were not covered by insurance.
Page 69
Edison International
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 $ 31,083 $ 41,168 $ -- $ 35,732 $ 36,519
All other 3,009 1,201 -- 783 3,427
- -------------------------------------------------------------------------------------------------------------------
Total $ 34,092 $ 42,369 $ -- $ 36,515(a) $ 39,946
- -------------------------------------------------------------------------------------------------------------------
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 242,235 46,361 24,101(e) 4,968(f) 307,729
Maintenance accrual 31,540 31,540(g) --
Insurance, casualty and
other 76,124 42,815 -- 47,571(h) 71,368
- -------------------------------------------------------------------------------------------------------------------
Total $ 947,948 $ 106,364 $ 23,882 $ 202,945 $ 875,249
- -------------------------------------------------------------------------------------------------------------------
(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) Effective January 1, 2000, EME changed its accounting method for major maintenance to record such expenses
as incurred. Previously, EME recorded major maintenance costs on a accrue-in-advance method. EME
voluntarily made the change in accounting due to guidance provided by the Securities and Exchange
Commission. The cumulative effect of the change in accounting method was an $18 million after-tax benefit.
(h) Amounts charged to operations that were not covered by insurance.
Page 70
Edison International
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 $ 21,638 $ 30,013 $ -- $ 20,568 $ 31,083
All other 2,634 1,288 -- 913 3,009
- -------------------------------------------------------------------------------------------------------------------
Total $ 24,272 $ 31,301 $ -- $ 21,481(a) $ 34,092
- -------------------------------------------------------------------------------------------------------------------
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 58,228 21,674(e) 77,335(f) 242,235
Maintenance accrual 26,053 18,505 54 13,072 31,540
Insurance, casualty and other 80,493 37,674 -- 42,043(g) 76,124
- -------------------------------------------------------------------------------------------------------------------
Total $ 515,330 $ 580,450 $ 21,594 $ 169,426 $ 947,948
- -------------------------------------------------------------------------------------------------------------------
(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 71
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.
EDISON INTERNATIONAL
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:
John E. Bryson* Chairman of the Board, President, March 29, 2002
Chief Executive Officer and Director
Principal Financial Officer:
Theodore F. Craver, Jr.* Executive Vice President, Chief March 29, 2002
Financial Officer and Treasurer
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 72
EXHIBIT INDEX
Exhibit
Number Description
- ------ -----------
3.1 Restated Articles of Incorporation of Edison International effective May 9, 1996 (File No. 1-9936,
filed as Exhibit 3.1 to Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of Edison
International dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on January 1, 2002
Edison International
4.1 Subordinated Indenture dated as of July 26, 1999 (File No. 1-9936, filed as Exhibit 4.1 to Form 8-K
dated July 26, 1999)*
4.2 Supplemental Indenture No. 1 dated as of July 26, 1999 (File No. 1-9936, filed as Exhibit 4.2 to
Form 8-K dated July 26, 1999)*
4.3 Amended and Restated Trust Agreement dated as of July 26, 1999 (File No. 1-9936, filed as Exhibit
4.3 to Form 8-K dated July 26, 1999)*
4.4 Senior Indenture dated September 28, 1999 (File No. 1-9936, filed as Exhibit 4.1 to Form 10-Q for
the quarter ended September 30, 1999)*
4.5 Supplemental Indenture No. 1 dated September 28, 1999 (File No. 1-9936, filed as Exhibit 4.2 to
Form 10-Q for the quarter ended September 30, 1999)*
4.6 Supplemental Indenture No. 2 dated as of October 29, 1999 (File No. 1-9936, filed as Exhibit 4.1 to
Form 8-K dated October 29, 1999)*
4.7 Amended and Restated Trust Agreement dated as of October 29, 1999 (File No. 1-9936, filed as
Exhibit 4.2 to Form 8-K dated October 29, 1999)*
Southern California Edison Company
4.8 SCE First Mortgage Bond Trust Indenture, dated as of October 1, 1923 (Registration No. 2-1369)*
4.9 Supplemental Indenture, dated as of March 1,1927 (Registration No. 2-1369)*
4.10 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)*
4.11 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No. 2-4522)*
4.12 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No. 2-4522)*
4.13 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No. 2-4522)*
4.14 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No. 2-7610)*
4.15 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)*
4.16 Eighty-Eighth Supplemental Indenture, dated as of July 15, 1992 (File No. 1-2313 Form 8-K dated
July 22, 1992)*
4.17 Indenture dated as of January 15, 1993 (File No. 1-2313, Form 8-K dated January 28, 1993)*
4.18 Indenture dated as of May 1, 1995 (File No. 1-2313, Form 8-K dated May 24, 1995)*
4.19 Ninety-Seventh Supplemental Indenture, dated as of February 21, 2002
Edison Mission Energy (EME)
4.20 Copy of Global Debenture representing EME's 9-7/8% Junior Subordinated Deferrable Interest
Debentures, Series A, Due 2024 (File No. 1-13434, filed as Exhibit 4.1 to Form 10-K for the year
ended December 31, 1994)*
4.21 Indenture dated as of November 30, 1994 (File No. 1-13434, Form 10-K for the year ended December
31, 1994)*
4.22 First Supplemental Indenture dated as of November 30, 1994 (File No. 1-13434, filed as Exhibit
4.2.1 to Form 10-K for the year ended December 31, 1994)*
4.23 Indenture dated as of June 28, 1999 (File No. 1-13434, filed as Exhibit 10.63 to Form 10-Q for the
quarter ended June 30, 1999)*
Page 73
4.24 First Supplemental Indenture dated as of June 28, 1999 (File No. 1-13434, filed as Exhibit 10.63 to
Form 10-Q for the quarter ended June 30, 1999)*
Edison International
10.1 1981 Deferred Compensation Agreement (File No. 1-2313, filed as Exhibit 10.2 to the SCE 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 the
SCE Form 10-K for the year ended December 31, 1985)*
10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313, filed as Exhibit 10.4 to the
SCE 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 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 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 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 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 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 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 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 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 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 Form
10-K for the year ended December 31, 1994)*
10.13 Retirement Plan for Directors (File No. 1-9936, filed as Exhibit 10.2 to 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 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 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 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 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 Form 10-K for the year ended December 31,
1995, for 1996 stock option awards filed as Exhibit 10.16.2 to Form 10-K for the year ended
December 31, 1996, for 1997 stock option awards filed as Exhibit 10.16.3 to Form 10-K for the year
ended December 31, 1997, for 1998 stock option awards filed as Exhibit 10.4 to Form 10-Q for the
quarter ended June 30, 1998, for 1999 stock option awards filed as Exhibit 10.1 to 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 Form 10-Q for the quarter ended March 31, 2001, for May 2000
special stock option awards filed as Exhibit 10.2 to 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 Form 10-Q for the
quarter ended March 31, 2001, for 2001 special stock option awards filed as Exhibit 10.4 to Form
10-Q for the quarter ended March 31, 2001, for 2001 retention incentives filed as Exhibit 10.5
Page 74
to 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 Special Grant Certificate and Award Agreements with John E. Bryson related to May 2000 stock option
awards under the Equity Compensation Plan and the 2000 Equity Plan (File No. 1-9936, filed as
Exhibit 10.18 to Form 10-K for the year ended December 31, 2000)*
10.19 Special Grant Certificate and Award Agreement with Bryant C. Danner related to a May 2000 stock
option award under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.19 to Form
10-K for the year ended December 31, 2000)*
10.20 Special Grant Certificate and Award Agreement with Alan J. Fohrer related to a May 2000 stock
option award under the Equity Compensation Plan (File No. 1-9936, filed as Exhibit 10.20 to Form
10-K for the year ended December 31, 2000)*
10.21 Form of Agreement for 2001 Director Awards under the Equity Compensation Plan
10.22 Edison International and Edison Capital Affiliate Option Exchange Offer Circular (File No. 1-9936,
filed as Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2000)*
10.23 Edison International and Edison Capital Affiliate Option Exchange Offer Summary of Deferred
Compensation Alternatives (File No. 1-9936, filed as Exhibit 10.1 to Form 10-Q for the quarter
ended September 30, 2000)*
10.24 Edison International and Edison Mission Energy Affiliate Option Exchange Offer Circular (File No.
1-13434, filed as Exhibit 10.93 to the Edison Mission Energy Form 10-K for the year ended December
31, 2001)*
10.25 Edison International and Edison Mission Energy Affiliate Option Exchange Offer Summary of Deferred
Compensation Alternatives (File No. 1-13434, filed as Exhibit 10.94 to the Edison Mission Energy
Form 10-K for the year ended December 31, 2001)*
10.26 Estate and Financial Planning Program (File No. 1-9936, filed as Exhibit 10.2 to Form 10-Q for the
quarter ended June 30, 1999)*
10.27 Option Gain Deferral Plan as restated September 15, 2000 (File No. 1-9936, filed as Exhibit 10.25
to Form 10-K for the year ended December 31, 2000)*
10.28 Employment Letter Agreement with Bryant C. Danner (File No. 1-9936, filed as Exhibit 10.27 to Form
10-K for the year ended December 31, 1992)*
10.29 Employment Letter Agreement with Stephen E. Frank (File No. 1-9936, filed as Exhibit 10.25 to Form
10-K for the year ended December 31, 1995)*
10.30 Retirement Agreement with Stephen E. Frank (File No. 1-2313, filed as Exhibit 10.22 to the SCE Form
10-K for the year ended December 31, 2001)*
10.31 Consulting Agreement with Stephen E. Frank (File No. 1-2313, filed as Exhibit 10.23 to the SCE Form
10-K for the year ended December 31, 2001)*
10.32 Election Terms for Warren Christopher (File No. 1-9936, filed as Exhibit 10.22 to Form 10-K for the
year ended December 31, 1997)*
10.33 Resolution regarding the computation of disability and survivor benefits prior to age 55 for Alan
J. Fohrer (File No. 1-9936, filed as Exhibit 10.2 to Form 10-Q for the quarter ended March 31,
2000)*
10.34 Executive Severance Plan as adopted effective January 1, 2001
10.35 Stock Purchase Agreement By and Between Edison Enterprises and ADT Security Services, Inc., dated
as of June 27, 2001 (File No. 1-9936, filed as Exhibit 10 to Form 10-Q for the quarter ended June
30, 2001)*
11. Computation of Basic and Fully Diluted Earnings Per Share
12. Computation of Ratios of Earnings to Fixed Charges
13. Selected portions of the Annual Report to Shareholders for year ended December 31, 2001
21. Subsidiaries of the Registrant
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.